Greetings, and welcome to the Energy Transfer Partners Fourth 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 Partners. Thank you, Mr. Long. You may now begin. Thomas E. Long: Thank you, operator. Good morning, everyone, and welcome to Energy Transfer Partners' and Energy Transfer Equity's fourth quarter 2015 earnings call. And thank you for joining us today. I will begin with a discussion of Energy Transfer Partners' fourth quarter results, followed by a growth project update, a financing and liquidity update, and an ETP distribution discussion. Then I will provide a brief update on the merger with Williams. And lastly, and overview of Energy Transfer Equity's fourth quarter earnings and other highlights. I'm also joined today by Kelcy Warren; Mackie McCrea; Matt Ramsey, who is ETP's new President and Chief Operating Officer; John McReynolds and other members of our senior management team who are here to help answer your questions after our prepared remarks. 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 ETP's fourth quarter 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. Adjusted EBITDA on a consolidated basis totaled $1.36 billion, which is a decrease of $168 million compared to the fourth quarter of 2014. We had continued strong growth in the Liquids segment, but saw Midstream EBITDA decrease. And in the fourth quarter of 2014, we had unusually strong Retail performance. DCF attributable to the partners of ETP, as adjusted, totaled $959 million, an increase of $165 million from a year ago. We had a current tax benefit from bonus depreciation, partially offset by higher maintenance capital. Now, let's go over the individual segment results. In the Midstream segment, adjusted EBITDA was $264 million, down $96 million compared to the same period a year ago. This decrease was primarily driven by lower commodity prices. These were partially offset by higher throughput volumes, an increase in fee-based revenues and lower G&A. There were also several plant outages, the majority of which have been resolved and continued volume shut-ins in the Northeast. Gathered gas volumes totaled over 10 million MMBtus per day, which is a 5% increase versus the same period last year, primarily due to higher volumes in the Eagle Ford, Permian and Cotton Valley regions, as well as the King Ranch acquisition. NGL production also increased in the fourth quarter by 67,000 barrels per day to 444,000 barrels per day compared to the fourth quarter of 2014, and Equity NGLs decreased in the fourth quarter by 1,000 barrels per day to 29,000 barrels per day. In the Liquids Transportation and Services segment, adjusted EBITDA increased by 40% to $222 million compared to the same period last year. The increase in adjusted EBITDA was due to higher throughput at the Lone Star fractionators and West Texas NGL pipeline, as well as increases in storage margin due to the ramp-up of Mariner South and related storage fees. We also increased margin in several other areas. NGL and crude transportation volumes on our wholly owned and joint venture pipelines increased 20% to 474,000 barrels. This was due to increased volumes out of the Eagle Ford and Permian, as well as the commissioning of a crude oil transportation pipeline at the end of 2014. There was also an increase in volumes on our NGL pipelines from our plants in Southeast Texas. Average daily fractionated volumes increased 22% to 250,000 barrels, compared to the fourth quarter of last year, due to the startup of our second fractionator in Mont Belvieu, which was commissioned in late 2013. In our Intrastate segment, adjusted EBITDA increased slightly year-over-year to $122 million. This was due to increased transportation fees and newly initiated long-term demand contracts for Mexico export volumes on our Houston Pipeline system. Also, while transported volumes decreased to 7.9 million MMBtus per day from lower production in the Barnett Shale, we expect this trend to reverse due to volume growth in 2016 related to increased demand from Mexico and the Gulf Coast LNG facilities. In our Interstate segment adjusted EBITDA was $283 million, down $24 million from a year ago, partially due to the expiration of a transportation rate schedule on the Transwestern Pipeline and the repurposing of Trunkline's 30-inch line for the Bakken Pipeline project. There were, however, increased deliveries on the Transwestern Pipeline due to sustained pooling demand and increased customer demand. Moving to Sunoco Logistics, who had another great quarter with EBITDA of $317 million. This was $80 million higher than SXL's fourth quarter of 2014. Moving to Retail. As a reminder, due to ETP's sale of its 100% membership interest of Sunoco GP LLC and all of the IDRs of Sunoco to ETE, ETP no longer consolidate Sunoco for accounting purposes. ETP's remaining proportionate investment in SUN is accounted for under the equity method. This change impacts the comparability of the Retail segment results versus prior periods. For the fourth quarter of 2015, adjusted EBITDA for the Retail segment is reported as ETP's 100% ownership of the assets in Sunoco, Inc. and includes adjusted EBITDA related to unconsolidated affiliates, which is comprised of our 68.4% interest in Sunoco LLC, the wholesale distribution business, and our investment in Sunoco LP based on ETP's percentage ownership of outstanding LP unit. For the fourth quarter, the Retail segment contributed $119 million of adjusted EBITDA. Going forward, as a result of our drop-down of our remaining interest in Sunoco LLC to SUN LP, which is expected to close in March, we will not report Retail results as its own segment. Instead, our investment in SUN LP will be reported in the All Other segment and broken out in our disclosures related to supplemental information on unconsolidated affiliates. For the current All Other segment, adjusted EBITDA decreased to $33 million, down $17 million versus a year ago due to weaker refining crack spreads from our investment in PES. 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. Starting with the Bakken Pipeline project, our joint venture with SXL and P66. We are obtaining the necessary permits and regulatory authorizations for this project. We expect to receive the remaining state agency authorizations in the next few months. This should provide us with sufficient time to construct the project by the fourth quarter of this year. Our project management group has done an outstanding job keeping Bakken on schedule. Next, on Bayou Bridge, another joint venture with SXL and P66, construction is nearly complete on the Nederland to Lake Charles segment of the pipeline, which is expected to be mechanically complete in March. Bayou Bridge successfully concluded its expansion open season in November, adding incremental Committed Shipper volumes to the project. Based on these commitments, the segment from Lake Charles to St. James is moving forward and is currently in the permitting and right-of-way acquisition phase. We continue to anticipate the deliveries to St. James will commence in the second half of 2017. On the Rover gas pipeline, we received the draft EIS from FERC last Friday, with final EIS scheduled for the end of July and the FERC certificate in the beginning of the fourth quarter of this year. We anticipate being in service to the Midwest Hub near Defiance, Ohio by June of 2017 and to markets in Michigan and Union Gas Dawn Hub by November of 2017. Lone Star's Frac III was placed into service in mid-December on time and under budget. Lone Star's III 100,000 barrel per day fractionators have averaged 339,000 barrels per day to-date. Frac IV remains on schedule to be in service by December of 2016. The Lone Star Express NGL Pipeline remains on schedule with Phase I to start up in the second quarter and final completion expected to be in the third quarter of this year. It is also expected to come in under budget. The Trans-Pecos and Comanche Trail Pipelines, which will expand our Intrastate Pipeline capacity to carry gas from the Permian Basin to Mexico remain on-track to be in service in the first quarter of 2017. We have completed the project financing and expect to commence construction on both projects in the next several weeks. On the Edinburg and Nueces Pipelines in South Texas, volumes to Mexico continue to grow as our demand fee contract expands from 530 million cubic feet per day to 930 million cubic feet per day, effective March 1. Both the 24-inch Volunteer Pipeline and the 200 million cubic foot per day East Texas cryo plant, also known as the Alamo Plant, came on-line in January 2016. On the 2.1 Bcf per day Utica Ohio River Expansion, as a reminder, Phase I was placed in service in mid-October last year, and Phases II and III came online at the end of December. The project is now fully in service delivering volumes into both REX and TETCO and we expect volumes to continue to grow throughout the year. And on the Revolution project, the pipeline and plant, as well as the fractionation facility, are expected to be in service in the third quarter of 2017. As a reminder, our project provides shippers with unique end-to-end solution with significantly improved net-back economics compared to their other alternatives. Our 200 million cubic foot per day, Orla cryo processing plant in the Delaware Basin is expected to come online in April and be full within 30 days and we have additional 200 million cubic foot per day cryo processing plant, the Panther Plant which is in the Permian Basin, that is expected to come online in the fourth quarter of this year. Now moving onto CapEx, ETP invested over $1.2 billion during the fourth quarter in organic growth projects, with the majority allocated to our Liquids Transportation and Services, Midstream and Interstate segments. For full year 2015, ETP invested approximately $5.6 billion in growth CapEx projects. For 2016, as we mentioned in our distribution press release, we have identified approximately $750 million of CapEx that could be deferred or cut from our original forecast. As a result, we now expect to spend approximately $4.2 billion on organic growth capital for 2016. This is net of an additional $325 million that is expected to be financed at the joint venture level with non-recourse debt. The majority of the CapEx reduction is related to the Midstream segment where we have placed new processing plants and other projects on hold. In addition, we have deferred some projects at Lone Star and delayed and reduced cost in the Interstate segment. We continue to foresee significant EBITDA growth in 2017 from the completion of our project backlog, and the majority of these projects are backed by long-term fee-based contracts. During the fourth quarter, we spent $142 million on maintenance capital expenditures, and for full year 2015, we spent $394 million. As you can see, fourth quarter maintenance capital was higher than normal. Accordingly, for 2016, we expect to spend approximately $345 million on maintenance capital expenditures. Before moving on to discussing our distribution, let's take a quick look at our liquidity position as well as our funding strategy for 2016. We ended the quarter with a debt-to-EBITDA ratio of 4.5 times for our credit facility. As of December 31, 2015, there was $1.36 billion in outstanding borrowing under the $3.75 billion facility. And we issued approximately $400 million of equity during the fourth quarter of 2015 under our ATM and DRIP programs. Taking a look at our current funding strategy for 2016, with the expected closing of the previously announced drop-down of the remaining interest in Sunoco LLC and the legacy Sunoco Retail business to Sunoco LP in March, the outstanding balance under ETP's revolver will be close to zero. As a result of this transaction, along with the $750 million reduction in 2016, growth capital funding and other potential asset sales, and the project financings, we do not expect to need to access the fixed income market in 2016, or to need to issue ETP common units in 2016. While we do not need the equity markets to fund our growth, we expect to opportunistically utilize the ATM from time-to-time in order to manage our leverage. In addition, ETE recently agreed to extend the $95 million annual management fee paid to ETP through 2016. Collectively, these actions are fully consistent with our goal of maintaining ETP's investment grade rating, which we consider a top priority. We have also kicked off initial discussions regarding project financing of the Bakken Pipeline. This measure would materially reduce the direct spending required to finance this project and would substantially reduce ETP's and SXL's 2016 capital funding requirements. Now, I'd like to touch on our recent distribution announcement. In January, we announced a distribution of $1.055 per common unit for the fourth quarter, or $4.22 per common unit on an annualized basis. This was flat compared to our third quarter distribution and was paid on February 16 to unitholders of record as of the close of business on February 8. As it relates to potential distribution increases going forward, this is a time when coverage and liquidity are valued more by the equity markets and rating agencies than distribution growth. We will continue to evaluate our distribution on a quarterly basis and will be prudent as it relates to balancing coverage and liquidity with distribution growth. Now, for a brief update on our merger with Williams. As a result of the FTC's second request for additional information, we entered into a Timing Agreement with the FTC on December 14, under which we have agreed not to consummate the proposed acquisition prior to 60 days after substantial compliance with the second request. ETE and Williams continue to work cooperatively with the staff of the FTC as it conducts its review of the proposed acquisition. In addition, on February 1, we received comments to our S-4 proxy that we previously filed with the SEC, we are in the process of working through those comments, some of which relate to the information that will be included in the ETE and Williams 10-Ks, and expect to file an amendment to the S-4 shortly after filing our respective 10-Ks. The pending merger also remains subject to the approval of Williams' stockholders and other customary closing conditions. As a result, we now expect closing to occur sometime in the second quarter. As it relates to the integration planning, we recently announced that Don Chappel has accepted the roll of CEO of WPZ, post-closing of the merger. In addition, our integration committee has been diligently working through the integration planning. We intend to actively implement a shared services model and continue to expect substantial synergies as result of the merger. As a reminder, we have a commitment for a $6.05 billion bridge loan in place with a syndicate of banks to fund the cash portion of the merger. This is effectively a two-year loan. We have had extensive discussions with the rating agencies and we are evaluating several alternative financing plans internally. We will provide more details on this at the appropriate time. With that update, we will not be taking questions on the call today related to the merger. We appreciate your cooperation in this regard. Moving on now to ETE, I will begin with ETE's fourth quarter results followed by a liquidity financing update and a Lake Charles LNG update. We will then take your questions. Turning to the financial results. First of all, we are pleased with the fourth quarter results of SXL, Sunoco and ETP. As a reminder, effective July 1, 2015, ETE acquired 100% of the membership interest of Sunoco GP LLC, the General Partner of Sunoco LP and all of the IDRs of Sunoco LP from ETP. So Sunoco still appears in the consolidated financial statements for ETE. ETE's cash flows came 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 the Lake Charles LNG, and 100% of the GP and IDRs of Sunoco LP. Our distributable cash flow, as adjusted, for the fourth quarter totaled $343 million, an increase of $100 million compared to the same period last year. DCF, as adjusted, per unit for the fourth quarter was $0.32 per unit, or an increase of 45% compared to the fourth quarter of 2014. Distributions from ETP accounted for 68% of ETE's total cash flows in the latest quarter. SXL contributed 17%, Lake Charles LNG approximately 11% and Sunoco LP contributed 4%. ETE announced last month a quarterly distribution of $0.285 per unit. This equates to $1.14 per unit on an annualized basis. Our distributable cash flow coverage was 1.15 times for the fourth quarter. It was paid on February 19 to unitholders of record at the close of business of February the 8th. 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 2.96 times for our credit facility. As of December 31, 2015 there were $860 million in outstanding borrowings under the facility. Therefore, at the end of the fourth quarter of 2015 the overall ETE standalone debt was $6.33 billion with a blended interest rate of 4.8% and with no pending maturities until almost 2019. Now turning to Lake Charles, which to remind everyone, is owned 60% by ETE and 40% by ETP. Progress continued to be made during the fourth quarter. We received our final FERC authorization in December to site, construct and operate the facility. And we received our final approval from the U.S. Army Corps of Engineers last Friday. On February the 15, Shell completed its acquisition of BG. And last week, we held our kick-off meeting for the project financing and preliminary responses from lenders has been strong. We remain on target to reach affirmative FID on the project in 2016 with the construction expected to start immediately thereafter and first LNG exports anticipated in early 2021. Before opening the call up to your questions, I would just like to say that our business continues to demonstrate resiliency in commodity markets that have been challenging, as well as the benefit of our diversified business model. Our project backlog is built on long-term third party demand fees that give us visibility into future EBITDA growth, particularly in 2017. These projects are tracking on schedule and on budget. ETP's financing needs for 2016 are expected to be met without the need to access the equity or debt markets, and our counterparties are strong, high-quality companies or have security for performance that is well structured to mitigate risk. ETE's priority is to support its core operating subsidiaries, and it will take the steps necessary to ensure they maintain their financial health and investment grade ratings. We remain very focused on project execution, cost management and improving our balance sheet strength by lowering our leverage and increasing coverage. The underlying fundamentals of our business are strong and we believe we will be in a great position for growth when the current market conditions improve. Before we begin taking your questions, I just want to reiterate that we will not be taking questions on the call today related to the pending merger with Williams or related matters. Thank you once again for your cooperation. With that, operator, that concludes our prepared remarks. Please open the line up for questions.

Thank you. We will now be conducting a question-and-answer session. Our first question is from Brandon Blossman of Tudor, Pickering, Holt. Please go ahead.

Hello?

You are live, Mr. Blossman.

Yes. Good morning, Tom. Thomas E. Long: Yeah. Good morning.

I guess let's start on Lake Charles. Has there been any conversations with Shell, post-close? And what does that timeline look like, or what's the process to get to FID over the course of 2016? Marshall S. McCrea: Yeah, so there's been no direct conversation with Shell, but BG met with Shell last week, and those conversations continue this week. And the feedback from our counterparts at BG said the meetings were very favorable, and we've been told to proceed as planned.

Great. Well, that sounds very positive. Okay. As far as we could crack through 2016 and into 2017, what – conceptually, or philosophically, how do you address the kind of intermittent use of the ATM program for equity versus kind of distribution thoughts as you consider rating agency action and your investment grade credit rating? Thomas E. Long: Yeah. You bet. As you know, the ATM has always been really a good tool. We have obviously gone lighter on it as we've moved into these lower prices. But clearly, we want to leave it as an option out there and with trying to manage once again our leverage ratio and our – as far as our credit metrics, all of our credit metrics. So the reason why we want to leave that in place is not because of the funding needs that we have, but once again, just because we want to just make sure that we're staying down the middle of the fairway.

Okay. Fair enough. And then just a detailed accounting question. On the bonus depreciation add to DCF in the fourth quarter, what period was that for? Thomas E. Long: The bonus depreciation was for 2015.

Full year 2015? Thomas E. Long: Yes. But there was some carry back in to 2014 and 2013, so.

Okay. Thank you very much. That's all from me for right now. Thomas E. Long: Thank you.

Thank you. The next question is from Jeremy Tonet with JPMorgan. Please go ahead. Jeremy B. Tonet: Good morning. Thomas E. Long: Good morning. Jeremy B. Tonet: Just wanted to turn to the Midstream segment, if we could. And I was wondering if you provide any more thoughts as far as things are trending into 2016? And we saw decline in the quarter, do you think things have baseline in growth CapEx coming into service can kind of stem that, or how do you think about that these days? And appreciate there's a lot of uncertainty with investment with producer budget at this point? Marshall S. McCrea: Yeah. Thanks, Jeremy. This is Mackie. Yeah, as we look at the challenging times we're in, and you look at our volumes, they're actually up. If you compare the fourth quarter of 2014 to 2015, certainly some of that's related to King Ranch. But even without King Ranch as a whole, some down, some up, as a whole our volumes are up across the board. In fact if you take out North Texas, the Barnett Shale, our volumes are up significantly not only on Midstream, but also on our Intrastate. In addition to that, as we kind of take a forward look into 2016, once again in very challenging times, the thing we contract on the most is volumes. As Kelcy's always said, we can't control basis, we can't control commodity prices, but we can be aggressive and more competitive on volumes and we actually are seeing volume growth in 2016 compared to the fourth quarter of 2015, ranging anywhere from 4% to as high as 17% depending on the basin. So the things that we can control, we're pleased with, especially in the environment we're in. And we can't worry about the things we don't control. Jeremy B. Tonet: Got you. Fair enough. And as far as the Midstream reductions there, would you be able to share more color on which plants are being deferred, and was Revolution part of that CapEx reduction? Marshall S. McCrea: I'm not sure of CapEx reduction, but we still are on track to have Revolution in by the third quarter of 2017. It has been pushed back a little bit to be in line with the downstream pipeline. The other plants that Tom talked about earlier was Orla and it's coming on soon. We're very pleased with that plant. It's very rare; you bring a plant on and it's full within 30 days; Panther will be very similar. At the end of this year, it will ramp up fairly quickly. And any other plants that we have contemplated, we have put on hold until we have accretive contracts to support them. Jeremy B. Tonet: Sounds great. Thanks for that. And just as far as the JV potential, as far as managing the balance sheet, and as far as project financing at Dakota Access, do you need agreement from all of the JV partners there to do that? And are you looking for any other JVs on growth projects that you have to further strengthen your balance sheet? Thomas E. Long: We are – first off, first part, I think the last part of your question there, yes, we do need the consent of the JV partners, which as you know, that P66 is our 25% partner on that one. What we're looking at there is, we're not looking at necessarily pushing the leverage up really high on that. We're really just kind of looking at kind of a 50/50 financing on that project. And I'm sorry, the second part of your question was around the JV? Jeremy B. Tonet: As far as this type of financing, bringing JV partners for any other projects, is that a possibility at this time? Thomas E. Long: Yeah. I would say that is a possibility. We're clearly focused on the project financing side of it is what we're focused on right now. But yes, that is a possibility. Jeremy B. Tonet: Got you. Thank you. And then just one last one from me, in the Liquids segment, it looks like there was an inventory liquidation. Could you just provide a little bit more color on what was happening there? Thomas E. Long: Are you talking about kind of the goodwill and the impairment? Is that what you're referring to? Jeremy B. Tonet: In other margin; in other margin, I think there was a little bit of an increase this quarter. So I was just wondering about that? Kelcy L. Warren: Can you get back to him? Thomas E. Long: Yeah. Listen, I'll have to get back to you on that other marketing. I apologize. I thought you were asking the question. Let me get back to you on that one, so. Jeremy B. Tonet: Great. I appreciate it. Thank you. Thomas E. Long: Yep.

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

Hi. Good morning, everyone. Can we go back to I guess, Mackie, some of your comments you were just making about your outlook for volume? I know at your Investor Day, you said you that weren't really seeing volume declines and you actually expected some increases. So you just threw out a range 4% to 17% growth. Can you just kind of walk us through by basin, kind of what you're seeing there and what's driving volume growth? Marshall S. McCrea: Sure. You bet. One thing we're very pleased with is a lot of our dollars, a lot of our capital has been focused in two of the better basins in the country, that being Eagle Ford and probably the best basin in the world with Permian and Delaware. So we certainly see significant growth there. As I mentioned a minute ago, we'll have 200,000 day flowing to our Orla facility by May or so. So that's an increase alone just at that one facility. Also, we've seen significant growth up in the Northeast on our Ohio River system. It came on last year, started ramping up towards the end of the year and it's exceeding our expectations in the first quarter and we project that that will continue throughout 2016, once again, even in these very difficult environments. As I mentioned earlier, Barnett Shale. It's on a slow decline. The reserves are there. Our pipes are waiting whenever the prices make sense. But every other area for the most part, Rebel is growing. The volume's there. South Texas, we've had some down time on some plants, as Tom alluded to. We have those up and running. So we'll see volumes at least hold, if not gain a little bit in the Eagle Ford. And so all-in-all, as I mentioned earlier, other than a few exceptions, we're pretty excited, or pleased with where we see volume growth this year compared to our competitors in this very difficult environment.

Okay. Great. And then, as I'm sure you know, Chesapeake made some comments on their call about some recontracting on Tiger, it looks like. But it seems like there is some sort of quid pro quo and you'll be seeing a benefit somewhere in your gathering system. I was wondering if you could just provide a little more details and maybe if you could quantify for us, how that trade occurred. Marshall S. McCrea: You bet. You know, it's funny when all this started happening Kelcy and I talked. There's always some lemonade with the lemons. And that's what we try to do. We've built our relationship with creating or working with producers on their needs. And clearly there is a lot of pain on the E&P side, on all the sides. And we have, in that situation, been able to help out Chesapeake in the short-term by shifting demand charges where some of their business is more commodity now with us in the short term. And by extending contracts that were ending over the next three years to five years, for many years out, and then also adding significant business in the future. So we're very pleased with Chesapeake. We have enjoyed working with them. We do believe they'll make it through these tough times, and we look forward to being kind of their partner of choice, is what we hope, as they continue to drill out some of the better rock that they have control of or have leases on throughout the country.

Okay. So we should see that benefit show up in later years in the Midstream segment? I'm just trying to figure out what are the offset is? Marshall S. McCrea: It's – yes, you'll see more of it. I can't get into a lot of details here, but certainly you'll see more of it more in the Midstream and even in some different basins.

Okay. And then just on Rover, can you just remind us kind of what percent of that pipe is currently contracted, and also how much capital has been spent to-date? Marshall S. McCrea: I'll let Tom speak to the capital. On the math, it's like 97% I believe, 97%, 98%. So we have 150,000 left of 3.25 million, whatever the math is there, I think it's about 97% or 98% on the main charge, on the CapEx that's been spent. Thomas E. Long: Yeah. On the CapEx, Michael, I'll get back with you. I believe we're probably at about $2 billion or so. But I tell you what, I'll get back with you on that, see what's the absolute latest on that.

Okay. Great. And then my last question is really, I don't know if you can or will comment, but obviously there's been a lot of speculation with the departure of Jamie. And I just wanted to know if there's anything you could share in terms of the circumstances with that whole situation? Thanks. Kelcy L. Warren: So, Michael, this is Kelcy. I think to be respectful to Jamie I'll keep this to a minimum, and we've talked to many, many that are on this call. Jamie is a very talented guy, but the decision was made by me that we needed to make a move, and we did. And Tom Long is now our CFO.

Great. Thank you.

Thank you. Our next question is from Darren Horowitz of Raymond James. Please go ahead. Darren C. Horowitz: Morning, guys. Tom, if I could, I just have one question. I want to go back to your discussion around the balance sheet. And obviously, what the market is telling us is they want more transparency, not just into the timing, but the magnitude of enhancing liquidity and reducing leverage. You've talked about your options, like monetizing part of the Bakken pipe, maybe deferring more CapEx. Obviously that $2.2 billion in proceeds from the sale of Sunoco interest helps, but there are other options. And I'm wondering how you guys rank those in terms of priority, or in terms of what could have the biggest benefit to the balance sheet? If you think about SUN, it's obviously countercyclical. Historically you said not a core business. And it helps both ETE and ETP with regard to the GP and the LP interest. And I'm thinking about if you could just provide some color, how you view those monetization options? What's changed in the marketplace? And if you could provide any transparency on the timing and your forecast for where you want leverage to be exiting this year, especially if this fundamental or cost of capital challenge continues into 2017? Thomas E. Long: Okay. No, you bet. And let me kind of start with the last part. Our target is still to maintain a 4.5 times leverage ratio. So obviously at year end – and this is per the credit facility, that's how we continue to manage that as we look out. We still think that's a very good target. And of course, as you know we're right in the middle of a lot of pre-funding. So we knew that that was going to put some pressure on the leverage, but it's also going to put some pressure on the coverage. The real comforting thing to us is these projects are all coming on late this year, early next year. So that's what we've been working toward and getting kind of the last portions of this funded. Back to the prioritization, I guess I would say, we do have those options. It's really kind of difficult to prioritize them in the sense that the market is so dynamic. As you look at various options, different days, different things move around on you. And we're going to probably stay consistent with what we've always done in the past, and that is to, as we get and make a certain decision as to what's the best for the company from once again all the various metrics, coverage, credit metrics, et cetera, we will make those decisions at the time. And we will announce them at the time. But if we try to get out and pre-announce on these, you can appreciate what that really does. So just kind of staying consistent with the way we've always funded our projects in the past where we announce them at the time that we get whatever negotiated is what we're going to continue to go – a plan that we're going to stick with, so. Kelcy L. Warren: Yeah. Darren, I would add, as you and I spoke recently, the CTE's job to support the partnerships that operate underneath it. And so there will be continued support to the extend IDR holidays for growth are appropriate that they will be given, and other means that ETE can support ETE's growth, and get ETE into late 2017, where ETE is pretty remarkable growth at that – ETP has pretty remarkable growth at that time. So just know just rest assured that ETE will do what it needs to do. Darren C. Horowitz: Thank you.

Thank you. The next question is from Ted Durbin of Goldman Sachs. Please go ahead.

Thanks. Maybe just taking that one more level. Is the distribution cut on the table at all for either ETP or ETE relative to the leverage metrics you're looking at? It's a choice that some other ownerships have made. And maybe you could put that in the context of, if and when the Williams deal goes through, how you think about that? And then also, balancing between ETE and ETP and where you might make that decision? Kelcy L. Warren: Yeah. I'll take the first part. There's no contemplated distribution cuts at ETP, whatsoever. We've not looked at any scenario where that would be appropriate or necessary. It's just not – we just don't see that. Like we said before, we're not going to talk about the Williams transaction, but, ETE's very healthy. Our distribution cuts are not required at ETE. And we take our obligation to our unitholders very, very seriously. We have a duty to maintain our distributions. But everybody knows, obviously, that's an option to the extent of that we need access to distributions to maintain our financial health at ETE; would we reach in to that bucket, it would be the last one we'd reach to, but it's certainly possible.

Okay. I appreciate that, Kelcy. Can we just talk about the Bakken Pipeline and it sounds like you're still confident hitting that late 2016 in-service date. It feels like it's a stretch from my seat at least, given that you haven't started construction as far as I can tell. What's left that needs to get done on the permitting side, to hit that in-service time? Marshall S. McCrea: Hey, Ted. This is Mackie again. I've got to say, like we do for most of our teams, we have one of the best teams in the country building that pipeline with Joey Mahmoud on the engineering side and Lee on the commercial side. And that project has gone exceptionally well in a very, very difficult environment throughout the country. We still are holding to the schedule. We have every permit other than a permit in Iowa, the eight material permits and we are optimistic and hope to have that permit in March. And as soon as we have that permit we'll begin construction. But right now, we do expect to be flowing oil by January 1, 2017 and it's very realistic that that's going to happen at this point.

That's great. I appreciate it, Mackie. And then last one from me, just on the Lone Star Express, I think you've spoken about that as being kind of a 6x multiple of invested capital. Are you still comfortable with that given the environment? Kelcy L. Warren: Yes, we are.

I'll leave it at that. Thank you.

Thank you. The next question is from Kristina Kazarian of Deutsche Bank. Please go ahead.

Hey, guys. So not to beat a dead horse here, but just a clarification question on ETP's IG rating. So Kelcy, the thought process is that if ETP had the risk of being downgraded from another sibling entity or parent entity and read through that the parent would actually backstop the rating and help it out to protect that balance sheet. Is that fair? Kelcy L. Warren: That is fair.

Okay. Perfect. And then I know you talked about this in an answer to a different question, but over the whole complex maybe can you touch about counterparty risk and the potential or magnitude for contract resetting, kind of like the Tiger line which we heard about yesterday? Thomas E. Long: Yeah. I'll take the first part of that. With the slide that we used in Analyst Day where we showed that 86% was basically DD or higher on our credit ratings, that has really remained very consistent in where we are from that standpoint. So we continue to stay obviously very focused on that and we like the positions that we have with our counterparty credit exposures. But I wouldn't – we've really not seen much movement in that and we know there's been a lot of changes with the agencies, but it's not really impacted as far as our top credit exposures at this point.

And then on the second part, maybe about potential contracts resetting like throughout all of 2016 across your fleet? Thomas E. Long: Yeah, well, I'll tell you what – Matt... Matthew S. Ramsey: (49:03). Thomas E. Long: Yeah. Go ahead. Matthew S. Ramsey: I'm sorry. Thomas E. Long: I'm sorry. Second part, one more time.

The second part is how do I think about contract resetting potentials across the whole complex for calendar year 2016? Matthew S. Ramsey: Midstream, Intrastate, Interstate, the whole complex? Thomas E. Long: Yeah, the whole complex. Matthew S. Ramsey: Well, on our Midstream, most of the contracts on our Midstream are long term now. Any plant that we've built recently is under at least 10 years or 15 year fracs. On all of our NGL business, they're long-term contracts. Most of our frac contracts are at least 10 years and probably majority of them are 15 years. On the Intrastate, it varies depending on the Interstate. The older Intrastate, the interesting phenomena there is, is that as the contracts roll-off we actually are increasing rates. Certainly, not charging tariff on some of our pipelines, but certainly at higher rates than where they've been. For example, we've taken out our Trunkline Pipeline and on the existing space that we still have on Trunkline has provided for higher rates because of demand in Northeast this winter. So all-in-all, we don't have a whole lot of exposure, and as I mentioned earlier in our discussions with Chesapeake we're having similar discussions with other companies that have similar type pain. And in those, we are looking at extending contracts that are ending in the next year or two years out for at least 10 years or 12 more years. So we're pretty pleased with where we sit across the complex of all of our segments on the timing of our contracts. And our goal is through this tough period is extending everything out because we'll provide that opportunity by helping them or some of these companies with the difficulties they are going through today.

Perfect. Thanks, guys. Appreciate the clarification.

Thank you. Our next question is from Robert Balsamo of UBS. Please go ahead. Robert F. Balsamo: Hey. Good morning. Most of my questions have been answered. Just a quick one on the unconsolidated affiliates, it looks like PES was down for the quarter due to crack spreads, which makes sense. But the distribution seem to be strong in the segment, unconsolidated affiliates. And I just wonder if you could talk a little bit about that, the distributions kind of being maintained, it looks like they're still growing and how to think about cash flows and distributions coming from that segment? PES and then unconsolidated affiliates overall. Thomas E. Long: Yeah, yeah, you bet. You're right, we did have some pressure because of the crack spreads there at that refinery. From a distribution standpoint, we've always been very much aligned with our partner there, both of us wanting to maximize distributions. And kind of like I said in my prepared remark, we're going to obviously maintain it and be ready to go with an IPO at any time. But I think direct answer to your question, we will always try to maximize distributions going forward. But that is going to be kind of up and down with where the crack spreads are. Robert F. Balsamo: Okay. Thank you. That's all.

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

Thank you. Good morning. Just a couple of quick items. When you say – when you plan to do the DAPL project financing, do you need FERC approval to launch it? And also, if you were to get let's say 50% project financed, would that reduce your 2016 CapEx by let's say about $1 billion? Thomas E. Long: Yes, as to the last part of your question, you're right on that. 2016 is right at $1 billion is what it would reduce it by. As far as the FERC approval, no, we do not need FERC approval to get project financing on that pipe.

Okay. So this is something you could launch anytime basically? Thomas E. Long: Yes. Yes. We've actually already started the dialog on it, so.

Okay. Got it. And then how much of your DAPL spending was already in your 2015 CapEx? I see $2 billion of liquid CapEx. Are you able to quantify how much of DAPL has already been spent? Thomas E. Long: As far as DAPL, I think we're right at about $1.7 billion, $1.8 billion on how much has been spent to-date.

Is that net to ETP? Thomas E. Long: No. That would be the 8.8 (54:19).

Full? Thomas E. Long: Yeah, the full amount.

Got it. Got it. Great. And then apologies if I missed this, but what drove the increase in Midstream OpEx in the quarter; was up quite steeply? Thomas E. Long: Yeah. What you saw during the fourth quarter, of course, was several plants starting up where you started seeing some additional expenses. You probably saw nearly additional about $25 million, $26 million work that occurred during the quarter. I would say, Helen though, it is fairly to kind of normal to see in the fourth quarter a lot of times as you get into year-end, you will see the expenses come up some. I guess what I'd like to say is, as you go into 2016 and really look at the – let's say, the early quarters, I would say that that number probably popped up by about $25 million number that we would expect not to necessarily see as we roll into 2016, so.

Got it. And then your comments on PES, you mentioned that the IPO was delayed, but that this is a near-term monetization option. So when you think about a couple of, I guess, assets you could sell, and I assume that includes Lake Charles, do you see this as something more higher in the rank in terms of probability, or maybe you could more broadly talk about certain assets that you could sell to help the balance sheet? Thomas E. Long: Yeah. And Helen, you can probably, like I say, appreciate about talking in too much specifics before you actually have a plan or have a deal in place is always difficult. In other words, usually that you would announce those at the time that you would actually go out. But I think when you really look, clearly this is one you could look at, our 33% ownership in that. But I think we still feel like that until you really get it to kind of to an IPO, that's probably where you're going to get the highest value. So it's not one that's let's just call it right for doing that and LNG was the other one you brought up. I mean, clearly that's one – that is an option out there, but you heard the update today. We're very excited at where that is in moving forward, but likewise, don't necessarily see that as being something you would do today. And then I think there was another, even a comment made earlier about options around if any of the JVs you wanted to bring in any other partners, et cetera, you can't obviously do that. But I will just reiterate once more that I think from a funding standpoint on the projects with the 4.2 what we've accomplished on that front, we feel like we've got a lot leeway here as we look out through 2016, so.

Okay. And then my last one is just on SUN deal closing date. It seems like it got pushed out a month. What's causing that? And any other, any risk of further delays there? Thomas E. Long: No. And listen, Helen, really that one is really pretty much on schedule with where we had kind of anticipated. Remember that we file our 10-Ks, we'll probably get them filed by at least Monday. And you really could not finish up the carve out financials to close this transaction until after those 10-Ks were filed. So just keep in mind that's probably a – when we say March, I would like to tell you that's probably a very early March, meaning possibly as early as next week even, by the end of the week or so. But we're working through those financials and that is really the component. Nothing's going to change as far as the effective day of the transaction. It's still going to be January 1 of 2016. So whether we do it the first week or the second week of March, but the only, absolutely the only holdup was getting the 10-Ks filed and getting the carve out financials.

Understood. Thank you very much. Thomas E. Long: Thank you.

Thank you. The next question is from John Edwards of Credit Suisse. Please go ahead. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Yeah. Good morning, everybody. Just a couple follow ups on the counterparty risk side. Just out of the – you indicated I think it was 86% is BB or higher. So out of the remaining 14%, if those BB or lower went to bankruptcy. I'm just curious how many of those rights are perhaps above market or how you would quantify, say, the revenue hit if those contracts had to be renegotiated like in a bankruptcy situation. Some sort of revenue quantification we could look at. Marshall S. McCrea: Hey, John. This is Mackie. And I won't go through specific risks or producers and areas. But one thing that's very helpful is where a lot of this risk is, it's on parts of our gathering systems where it's really hard to compete. Certainly, in a bankruptcy there may be some renegotiation. But we don't see in a lot of these situations a lot of risk because our ability to either work it out with them or because there may not be a lot of options out there and the price that we're moving forward is the market price. So, and not talking about any specific producer. We can reduce their exposure significantly just because of how they're situated in our system. Thomas E. Long: And John, what I'd like to go ahead and just add to that from the absolute kind of percentage, if you will. When you get down to that group, the exposure, and I know we talked some about the Chesapeake. But as far as the counterparties and where those percentages lie, they're really small. It's spread out over a lot of counterparties. And the number's well less than 1% on any one customer, so. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Okay. That's actually – that's helpful. And just following up, Tom, on the balance sheet. You indicated you're targeting four and a half times exiting this year. I'm just curious kind of your longer term leverage target, what you're thinking about? Thomas E. Long: Yeah. And once again, at ETP we do feel like that the 4.5 times is a good place to be. Remember that the credit facility calculation, the way we do that, does allow for the inclusion of the material project adjustments, if you will. I know we've talked about before. And so that's how we get to the number. In other words, these are the calculations that we will be sending out to the banks at this 4.5 times. But the real beauty of that, it does show these projects as they come on, where the economics are, and it does give you a line of sight of where your both GAAP and MPA are headed to be basically the same number at the four-and-a-half. So once again, as we go through 2016 and complete a lot of this funding you're going to see that that four-and-a-half, both on a GAAP basis as well as with the material project adjustments, that GAAP narrows significantly, so. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Okay. That's helpful. And I guess the only – I know we all have to jump to the next call, but just maybe give a little bit of color on the impairment losses of, I think it was a $339 million item there? Thomas E. Long: Yeah, you bet. It really is all around the commodity prices, if you will. So let's start with the Transwestern piece first. The number was $99 million. It really was about kind of looking out at where the commodity prices were on that. So that's the goodwill impairment. The rest was really all in the Refinery Services. In other words, in the Liquids segment. And, same thing, it related to actually the spread that you see in those contracts we had between off gas projects we have. We actually took one of those plants that completely out of service, so that was it. It was the Refinery Services and the Transwestern, so that's what makes up to $339 million. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Okay. I'll follow-up with the rest of my questions, but thank you for that. Thomas E. Long: Okay. Thank you.

Thank you. The next question is from Selman Akyol of Stifel. Please go ahead.

Thank you. Good morning. Just a couple of quick ones. Mackie, going back to your earlier comments, you mentioned there was some down time on plants in the Midstream segment. I was wondering is there any way to quantify the impact on that? Marshall S. McCrea: Yeah. I wouldn't – it would take a while to go through kind of the every specific. We have issues on several plants. But for example, in South Texas, we've had issues on a plant that moves about 130,000 a day. That's been down off and on, and we're hopefully to the end of that where that runs reliably. And then some of our plants out in West Texas we continue to kind of work through issues, but we are working through those. That has a lot to do with why we're seeing our volumes increase on our projections in 2016 as we kind of line all those issues out.

I got you. And then just one more, I guess at the time of, when you guys acquired Regency you had forecasted some pretty good synergies. And I'm wondering are you seeing any of those? Are they yet to come? Is it just being chewed up in the commodity environment? Any commentary around that? Marshall S. McCrea: No, we're seeing them across the country. If you look at West Texas, we've talked about Orla, Energy Transfer's building Orla put in place tying it to the Regency system. The Delaware Basin, as I mentioned earlier, if you talk to some of the larger producers in the country, they believe that's some of the best rock in the world. So as we kind of expand out our business, the Regency assets and the broad expansion of all those gathering systems and all their plants gives us the ability to provide services while we're building new plants. So the synergies out in the Permian Basin, in West Texas have been extensive. Up in the Northeast, of course, with Ohio River we are seeing a lot of volume growth there. Once Rover is up and transporting gas, that will be one of the main feeders to that pipeline or a very significant supply source. And then we also have some synergy in East Texas that we're benefiting from. So yes, it's been very – the areas of the country we've had significant synergies that have helped out a lot.

All right. Thank you.

Thank you. The next question is from Chris Sighinolfi of Jefferies. Please go ahead.

Hey, guys. This is Corey (01:06:25) filling in for Chris. Just real quick, Tom, just to follow up on the last question, I think again, you mentioned some plant outages since the Northeast volumes shut-ins. Can you quantify the EBITDA impact there that you saw in 4Q? Thomas E. Long: Yeah. That impact was probably $6 million to $7 million.

Got it. Thanks. And then last question, I think you mentioned that Revolution was pushed one quarter into 3Q, but effectively, what was the remaining cause for the $500 million and decrease (01:06:58) CapEx, like which projects specifically are being deferred or shifted there? Thomas E. Long: Let me give you more of a high level versus maybe talking about the specific projects. Just to give you a split on that $750 million, let's say, about 25% of that was actual cuts. The other 75% of it is really more deferrals, and you'll see that spend kind of over – that kind of occur in over 2017, maybe a little bit more of it in the first half of 2017. I think, and Mackie touched on this, but I think you have the, of course, the gathering system down in South Texas, but you also have a West Texas plant likewise, and that's – like I say, the rest of it's really more around just some of the deferral on the projects that are already there, so.

But no other timing's changed besides Revolution? Marshall S. McCrea: No other timing's changed. Well, Rover at one time, gosh, I think at the Analyst Meeting we were optimistic that we'd be in by April, May. Where we stand with FERC, we thought we'd have the ability to kind of push the July 29 date up a little bit. It's clear that that's very unlikely. So we are planning accordingly. And so we have moved that date out to June. We're confident that we will be flowing most of the pipeline in June and then complete it by November.

Okay. Great. And same thing on Intrastate, what was the reason for the $135 million shift in CapEx there? Thomas E. Long: I'm sorry. You said on the Intrastate?

Intra, yeah. I think you reiterated Trans-Pecos still in 1Q. So just wondering now what the mix shift was there? Thomas E. Long: Yes, and that was on the Mexico projects. And it really does relate to the project financing, because what you had is the last time we gave the number, we really didn't have that project financing in place. So we since have locked that up at very good rates and very long-term. But that's what really drove that one down for the Intrastate.

Got it. Thanks, guys. Thomas E. Long: Yes.

Thank you. The next question is from Eric McCarthy of Citadel. Please go ahead. Eric N. McCarthy: Hey. Good morning. I was hoping you could elaborate a little bit further on the Chesapeake contract. Chesapeake disclosed $50 million in savings in exchange for some GMP contracts. What basin does that apply to? And what's the – does it make up for the $50 million in full? And what's the ramp (1:10:04) number on that? Marshall S. McCrea: Yeah, this is Mackie again. As I mentioned earlier, we can't really get into the details of that. I think if you look at their comments more closely, they also consummated some similar type amendments with other companies. So that $50 million isn't attributed to just us. But it's throughout several of the basins that they have significant positions in, some of which we don't have a lot of business with them today, and some we do have a lot of business with them. But getting into any more details than that with our confidentiality agreement with them, we can't do that. Eric N. McCarthy: Okay. All right. That's about it. Thank you.

Thank you. Our next question is from John Kiani of Teilinger Capital (01:10:55). Please go ahead.

Good morning. Can you hear me okay? Thomas E. Long: You bet. Good morning.

Good morning, Tom. Just a few questions, please. First, the $230 million tax benefit that contributed to DCF this quarter, trying to understand – so the coverage looked like it was in the 0.8 times range without that. Should we expect tax benefits like this going forward? How should we think about coverage with or without that piece? Thomas E. Long: Yeah, very good question, John (01:11:30) and I guess what I would tell us is, is that if you really take that $230 million we won't – since we didn't really bake in anything on the other component of that, that other $50 million, if you take that $230 million, really about $120 million came about from the bonus depreciation. So I wouldn't count on that. Again, as far as the – another $80 million component came about through just lower overall taxable income was the other component. And then you have the last $24 million piece that related really to a state income tax that we had a favorable outcome on. So I think that the way I would look at it, John, (01:12:19) is that if you look at through 2016 I wouldn't necessarily bake in any type of benefit. In other words, kind of a – or expense either. In other words, I would really kind of leave that one fairly flat. John (01:12:36), I think the other thing I'd like to, since you're on this topic, I'd like to go ahead and add to it is, is that what we've really kind of looked at is really probably – you've also had maintenance capital that came up to the $142 million. Our normal kind of run rate that we're looking at next year is probably closer to $85 million a quarter. And then the other thing you had is some of the other stuff that we talked about today from some of the operational, et cetera. So all-in-all I guess I can say is that if you took the $230 million and then you backed out approximately $80 million or so of what I call items that went the other way, you're probably at about $150 million is where I would take you. And based upon that math, you're probably at about a 0.9, a little bit more. So anyway, that help?

Yeah. That makes sense. Another question, please, is when you think about the portfolio and you talked about the potential at some point for some asset sales, what do you think about some of the businesses you inherited through all the acquisitions that aren't necessarily as pipeline like? Could you sell those? What about like the Coal business that came with PVR? Things like that, that are just not as visible as some of the legacy assets. What about those businesses please? Kelcy L. Warren: Yes, and this is Kelcy, and you're correct. We do have employees there, so I need to be a little bit careful. But those type of businesses are being analyzed. And we're looking at monetizing things that do not have the promise for great cash flow going forward, or our deferred cash flow in the future. So, yes we are.

Okay. Thanks. And then last question, please. Kelcy you mentioned the potential for support and IDR holidays and things like that for your subsidiary companies. One thing I'm trying to just get a better handle on is with the pro forma debt balance for ETE being $17 billion to $18 billion, how does that work? I guess I'm getting a little confused, because it's somewhat of a zero-sum game. If ETE takes less cash, in the form of IDR holidays or sometime of support for its subsidiaries, how does it sustain and service that type of debt load in its own distribution? Am I missing something, or should I think about it... Kelcy L. Warren: Well, just think about it another way. There's going to be the need for all of the partnerships to issue new equity going forward to fund the growth and to the extent that ETE should waive IDRs on those new units that are going out, then it will. So if you follow that, that's not taking money out of the coffers of ETE. It's future dollars that would have been earned that have been forgiven or deferred.

Right, right. Okay. Thank you. That's helpful. Kelcy L. Warren: Thank you.

Thank you. The next question is from Zev Nijensohn of The Boston Company. Please go ahead. Zev D. Nijensohn: Hey, guys. Thanks for taking my question. I was hoping you could help me back check my numbers. And I'd like to focus specifically on adjusted EBITDA. But hypothetically, if you didn't spend another dime of CapEx as of 12/31/2016, can you quantify how much EBITDA on a run rate basis is on the come from projects that were I guess either approaching completion or were completed but not fully reflected during the fourth quarter? Thomas E. Long: Yeah. Well, I'm not going to probably give you an absolute dollar amount, just because we just don't give guidance like that. These projects that are all coming on are in the $10 billion to $11 billion range. I think we've always kind of given guidance that we got mid-teen type returns. I'm just giving you a balance across all of them. And as you also know, some of these things start ramping up over time, so I think that hopefully helps and that's what you can use as your guidance for each one of these various projects and how they startup. And then the timing of when we're telling you they're starting up, so. Zev D. Nijensohn: Okay. And then if I switch gears for a second, and I guess this is a question more for Kelcy. But if you think about things from a real long-term, long ball-type perspective, why not consider cutting the dividend entirely at ETE in order to give yourself a lot of coverage in terms of funding interest and doing something similar to what KMI did since you're not necessarily getting credit for it in the market right now? Kelcy L. Warren: Yes. Well, and I hear you. And it's our job here to protect the distribution. Our unitholders expect us to do that. We take that responsibility very seriously. But as I said earlier, if there is a chance that one of the partnerships would be in peril for a downgrade in ratings, ETE will do what is required to help that operating partnership. Of course the 800-pound gorilla is ETP. And we're going to be taking moves to help ETP get to 2,000, get to middle of 2017, which is all it needs. And then it's cooking and grease after that. But, so I hear you. We would like to reach into every bucket we've got before we would reach into that one, as I mentioned before, but it is a possibility. Zev D. Nijensohn: Thank you. Thomas E. Long: You're welcome.

Thank you. The next question is from Norman Hale of Stifel. Please go ahead.

Thank you. Good morning. The primary source of the pain for the energy industry which is filtered into the midstream industry is product prices. What do you guys see as being a normalization in terms of both the crude oil price and the natural gas price? Kelcy L. Warren: All of us are just like you, we read everything we can read. We listen to other people's opinions on this subject. And so, I'll just start, and Mackie maybe you can help me. I'll talk about crude for a second. We are, there's something very healthy going on in our industry. And it unfortunately is painful. Every time we've had one of these down turns, these cycles, they end up being a very healthy thing. But my goodness, they're painful. And what I mean by that is until we see meaningful reduction in drilling which translates into Mackie and Matt Ramsey making their job harder and harder, because when there's just less volume coming on, your volumes inevitably are going to be stressed. But until we see that I don't believe we're going to see meaningful improvement in crude oil prices. I just don't see it. There's too much success. These guys are drilling 8,000 foot laterals, for God's sake. I mean, and their science has improved so much. But we are beginning to see that. It's sad. We're beginning to see very few people that are going full out anymore. And then that ultimately will correct. I personally believe and this is, boy, you can – with this and a $1 you can maybe buy half a cup of coffee somewhere. But I personally believe that we're going to see this recover more rapid than people think. Unfortunately, we've got to find that balance. We've got to get crude oil production with the crude oil market in balance and then I believe there will be inevitable cuts coming out of our not so good friends over in the Middle East. And then we'll be back up on a ride. Now, I don't think $100 crude is healthy for anybody. I don't believe it is. I believe $60 to $80 crude is very, very good. So anyway, that's my view on that. Mackie? Marshall S. McCrea: And also you look at the market side of it. It's just – it's going to take time. If you look at the growth into Mexico just our projects alone are going to grow – increase the volumes into Mexico significantly beginning in 2017 and even as we mentioned earlier, some volume increases this year. With the China market and all the Eastern markets, the demand has just slowed down. If demand ever picks back up, that will help tremendously. But just from my perspective I think that without some major occurrence in the Middle East, this is just going to take time. It isn't going to be immediate, but to Kelcy's point, once it does return, we're very optimistic that it'll be very difficult for producers, for service companies to react quick enough and so we could see a pretty quick movement certainly on the oil side and probably sustain for some of period of time. It just – when is that going to take place is the big question, how soon. Kelcy L. Warren: Yeah, and I'll add. Hey, by the way, this is our last question so we're a little bit more relaxed on this one. So this is great. We're finishing up here. But Mackie, the amount of volume we're going to be moving to Mexico within – by 2018 is huge. Marshall S. McCrea: Yeah. Kelcy L. Warren: It's huge. And those things are chipping away and the point is we are seeing demand for natural gas improving. Marshall S. McCrea: Today. Today I believe it happened today. Cheniere loaded their first LNG ship, for the first time ever we're exporting LNG. That's going to increase Freeport, of course, will help to get FID. So all that takes time, but with the market growth that we already know of and that any kind of an improvement overseas, it's going to be – there's plenty of supply right now, market needs to grow to really help our situation.

Yeah. I hear you. Thanks, guys. I think you guys are doing a great job in a really tough environment. So keep up the good work. Kelcy L. Warren: Yeah, thank you. We appreciate that. Thomas E. Long: Okay. Hey, thanks everybody for the call. Good questions. And we'll be talking to you soon. Thank you.

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.