Greetings, and welcome Energy Transfer First Quarter Earnings Call. At this time all participants are in a listen-only. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host for today's call, Mr. Thomas Long. Thank you, you may begin.

Thank you, operator. Good morning everyone and welcome to Energy Transfer Partners and Energy Transfer Equity First Quarter 2016 Earnings Call; and thank you for joining us today. I will begin with a discussion of Energy Transfer Partners first quarter results followed by a growth project update, a financing and liquidity update, and a distribution discussion. Then I will provide a brief update on the merger with Williams and lastly, an overview of energy transfer equities first quarter earnings and other highlights. I'm also joined today by Kelcy Warren, Mackie McCrea, Matt Ramsey, 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 meeting of section 21E of the Security 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 Web site. Now for ETP's first 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 $1.41 billion, which is an increase of $46 million compared to the first quarter of 2015. We have continued strong growth in the liquid segment, and at SXL, which was partially offset by lower EBITDA from retail marketing as a result of the drop down of the retail asset to Sun over the last year and lower EBITDA from the midstream segment. DCF attributable to the partners of ETP as adjusted totaled $793 million, a decrease of $51 million from a year ago. The decrease was primarily a result of the drop down of retail assets and the decline in commodity prices at midstream. Now let's go over individual segment results. In the midstream segment, adjusted EBITDA was $263 million, down $47 million compared to the same period a year ago. This decrease was primarily driven by lower commodity prices, including the impact of 2015 hedges. The decrease was partially offset by higher throughput volumes, an increase in fee based revenues, and lower G&A and OpEx. We continue to experience shut ins in the Northeast as producers wait on take away from the Northeast region. Gathered gas volumes totaled 9.9 million MMBTUs per day, which is a 4% increase versus the same period last year, primarily due to higher volumes in the Eagle Ford, Permian, and Cotton Valley regions. NGL production also increased in the first quarter by nearly 61,000 barrels per day to 428,000 barrels per day compared to the first quarter of 2015. In equity, NGLs increased in the first quarter by 1,000 barrels per day to nearly 30,000 barrels per day. In the liquids transportation and services segment, adjusted EBITDA increased by nearly 35% to $227 million compared to the same period last year. The increase in adjusted EBITDA was due to higher throughput at the Lone Star fractionators, higher volume transported on the West Texas NGL pipelines, as well as the ramp up of Mariner South and increased storage margin due to strong demand on leased storage capacity as a result of favorable market conditions. NGL and crude transportation volumes on our wholly owned and joint venture pipelines increased nearly 20% to 487,000 barrels per day. This was due to increased volumes in all of our producing regions as well as our crude oil transportation pipeline in the Eagle Ford Shale. Average daily fractionated volumes increased 66% to 363,000 barrels compared to the first quarter of last year due to the startup of our third fractionator at Mont Belvieu which was commissioned in late 2015 as well as increased producer volumes. In our Intrastate segment, adjusted EBITDA increased slightly year-over-year to $179 million. This was due to increase transportation fees and newly initiated long-term demand contracts for Mexico export volumes on our Houston pipeline system. Also, while transported volumes decreased due to lower production in the Barnett Shale, we began to see this trend reverse. With first quarter volume slightly higher than the fourth quarter, due to increased demand from Mexico, and we continue to expect slight volume growth in 2016. In our interstate segment, adjusted EBITDA was $292 million, down 9 million from a year ago partially due to the repurposing of trunk lines 30-inch pipeline for the Bakken crude oil pipeline project. Moving to Sunoco Logistics, which had another great quarter with EBITDA of $349 million, this was almost $130 million higher than SXL's first quarter of 2015. Moving onto retail results, due to the transfer of the general partnership interest of Sun from ETP to ETE in 2015 and completion of the drop down of the remaining retail marketing interests from ETP to Sun in March of 2016, the partnership's retail marketing segment has been deconsolidated. And the segment results now reflect an equity method investment in limited partnership units of Sunoco LP. For the three months ended March 31, 2016 distributions from unconsolidated affiliates reflect the distributions to be received from Sunoco LP for the period, which were $30 million. For the current, all other segment adjusted EBITDA decreased to $45 million compared to $59 million a year ago, primarily due to unfavorable results from our natural resources business. Now let's move to our growth projects. We'll offer of that a brief update. Starting with the Bakken pipeline project, our JV with SXL and Phillips 66, we're very pleased with our progress in the last quarter. In April, our project management team was successful in obtaining a hazardous liquid pipeline permit from the Iowa Utilities Board for Dakota access, the last of the four state regulatory authorizations for Bakken. It was a tremendous effort by our team to obtain this permit. We expect commence mainline construction this quarter in accordance with our anticipated project schedule, and we remain on track to place the project in service by the end of this year. Next on Bayou bridge another JV with SXL and Phillips 66 partners, we began commercial operations on the 30 inch segment from Nederland to Lake Charles in April. Bayou bridge successfully concluded its expansion open season in November adding incremental committed shipper volumes to the project. Based on these commitments, the 24-inch 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 that deliveries to St. James will commence in the second half of 2017. On the rover gas pipeline, as mentioned previously, we have received the draft EIS from FERC and the public comment period closed in April. Receipt of the final EIS is scheduled for the end of July and for 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. Shifting now to Lone Star NGL, Frack three was placed in service in mid-December on time and under budget. Frack four remains on schedule to be in service by December 2016. The Lone Star Express NGL pipeline remains on schedule. We placed the 24-inch pipe in service in late April with a final completion of the 30-inch pipe expected in the third quarter of this year. It is also expected to come in under budget. On our Mexico projects, the Trans-Pecos and Comanche Trail pipelines, we'll expand our intrastate pipeline capacity to carry gas from the Permian Basin to Mexico. We have commenced construction and remain on track to be in service in the first quarter of 2017. On the Edinburgh and Oasis pipeline in South Texas, volumes to Mexico continue to grow and demand fees have completely ramped up on these fully contracted pipes. In East Texas, both the 24-inch volunteer pipeline and the 200 million per day East Texas plant, also known as the Alamo plant, came online in January 2016. The Alamo plant is currently about half full and we expect volumes to remain at that level until late 2016 or early 2017. Up in the Northeast as discussed on our last earnings call, the 2.1 Bcf per day Utica Ohio River expansion is fully in service. Volumes have built to just over our current contracted MVC amounts, and we can expect volumes to continue to meet the MVC for the remainder of the year, with volume growth continuing in 2017. On the Revolution project the pipeline and plant as well as the fractionation facility are expected to be in service in the fourth 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. Finally, in West Texas, our $200 million a day oil processing plant in the Delaware basin begin processing volumes at the end of the first quarter and went into full commercial service May 1st. We are currently at full capacity. And the $200 million a day Panther processing plant, which is in the Permian Basin, is still expected to come online in the fourth quarter of this year. Now, moving on to CapEx. ETP invested just over $1 billion during the first quarter in organic growth projects with the majority allocated to our liquids transportation and services mid stream and interstate segments. For 2016 CapEx, we now expect to spend approximately $2.8 billion of owned balance sheet organic growth capital. This is down approximately $1.4 billion from what we forecasted on our fourth-quarter call, due to project deferrals and anticipated project financing on our Bakken pipeline project. As we near conclusion of our major project backlog spend from the last couple of years, we continue to foresee significant EBITDA growth in 2017 and 2018 from the completion of this backlog. As a reminder, the majority of these projects are backed by long-term fee-based contracts. During the first quarter, we spent $46 million on direct maintenance, capital expenditures. Accordingly, for 2016 we expect to spend approximately $330 million on maintenance capital expenditures. Before moving on to discussing our distributions, let's take a quick look at our liquidity position. We ended the quarter with a debt to EBITDA ratio of 4.27 for our credit facility covenant, which continues to move down from 4.5 in the fourth quarter. In March 2016, we contributed our remaining interest in Sunoco LLC, the legacy Sunoco retail business, to Sunoco LP for $2.2 billion and $5.7 million Sunoco LP units. We used the proceeds to pay down our revolver. As a result, the outstanding balance of ETP's $3.75 billion credit facility was substantially undrawn. Also, during the quarter we issued approximately $363 million of equity under our ATM and drip programs. Taking a look at our current funding needs and strategy for 2016, we are actively pursuing project financing of the Bakken pipeline, which is expected to reduce ETP's 2016 own balance sheet capital funding requirements for approximately $1 billion. So looking at the Capitol, we still need to finance in 2016, we are forecasting $2.8 billion, of which just over $1 billion was spent in the first quarter. We plan to use the undrawn balance on our revolver to fund a portion of this capital as well as opportunistically utilize our ATM. These actions continue to be fully consistent with our goal of maintaining ETPs investment grade ratings, which we consider a top priority. In order to support ETP with its cost of equity capital in light of ETP's current common unit price, ETE has recently advised ETP that ETE intends to waive its rights to receive incentive distributions, with respect to ETP's 2016 issuances of common units beginning post-closing of the merger; whether pursuant to the ATM or other offerings of common units, through fourth-quarter 2017 distributions. As these potential IDR waivers have not been approved by the ETE board, ETE is not formally bound to these proposed IDR waivers. This reinforces ETE's commitment to support ETP. Now I'd like to touch on our recent distribution announcements. In April we announced a distribution of $1.55 per common unit for the first quarter or $4.22 per common unit on an annualized basis. This was flat compared to our fourth-quarter 2015 distribution and will be paid on May 16 to unit holders of record, as of close of business on May 6th. As it relates to the distribution going forward, we continue to be focused on improving our coverage and liquidity, which we believe are essential to rating agencies. As we mentioned in our last call, we continue to evaluate our distributions on a quarterly basis and we'll be prudent as it relates to bounce in coverage and liquidity with distributions. However, our primary objective at this time will be to maintain our investment grade rating at ETP. Now for a brief update on our merger with Williams. ETE and WNB continue to work cooperatively with the staff of the FTC as it conducts its review of the proposed acquisition. In addition, we have filed an amendment to the F4 with the SEC yesterday in response to SEC comments. In light of the ongoing SEC review process and certain provisions of the merger agreement related to the election process for WMB stockholders to make elections as to the cash ETC shares or a combination there of, ETE and WMB agree to amend the merger agreement to provide the form of election would not need to be mailed until the proxy statement for the WNB stockholder meeting is mailed. And also revise the deadline for the receipt of the election forms from on the WMB stockholders. As previously stated in our 8-K and in the F4 amendment filed yesterday, Latham and Watkins has concluded that they will not be able to provide the opinion related to the application of section 721 of the Internal Revenue Code to the contribution of the legacy WMBFF from ETC to ETE, in exchange for ETE class C units where the opinion requested as of the date of the most recent amendment so the S4. This conclusion was based in part upon the possibility that the IRS would disregard the form of this exchange and, therefore, reallocate a portion of the cash consideration paid to ETC by ETE for ETC common shares, among such common shares in the contributed legacy WMBFF. This opinion is a condition to closing of the merger. The merger agreement specifies that this opinion may only be rendered by Latham. Latham really scrubbed this issue before reaching its conclusion. After Latham concluded that it would not be able to deliver the 721 opinion, ETE consulted not only with Latham, but also with other legal advisors regarding the risks that the contribution of the legacy WMBFF from ETC to ETE would not be a transaction to which Section 721A of the code applies. These other legal advisors reached independent conclusions similar to Latham's conclusion. ETE agrees with these conclusions. The amendment to the F4 contains additional information related to this issue, and we urge you to review this filing. We believe that the inability of Latham to render this opinion as of the date of the most recent amendment to the F4 will result in the existing transaction not being able to close. Regardless of whether Williams obtained stockholder approval for the merger. On Tuesday of this week, ETE filed an answer to Williams lawsuit against ETE related to the issuance of the convertible preferred units. In addition, ETE filed counterclaims against Williams for breach of the merger agreement for refusing to cooperate with the proposed public offering of the convertible preferred units to all ETE holders. Moving on now to ETE, I'll begin with ETE's first quarter results followed by a liquidity and financing update and an Lake Charles LNG update. We will then take your questions. Turning to the financial results, first of all we were pleased with the first quarter results from 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 IDR of Sunoco LP from ETP, so Sunoco still appears in the consolidated financial statements for ETE. ETE's cash flows come from the general partner and IDRs and LP interests at ETP. 90% of the economics of the GP and the IDR's from SXL to the class H units, through the ownership of Lake Charles LNG and 100% of the GP interest, IDR's and LP interest in Sunoco LP. Our distributable cash flow as adjusted for the first quarter, totaled $349 million, an increase of $29 million compared to the same period last year. ECF as adjusted per unit for the fourth quarter was $0.33 per unit or an increase of 10% compared to the first quarter 2015. Distributions from ETP accounted for 68% of ETE total cash flows in the last quarter. SXL contributed 18%, Lake Charles LNG contributed 10%, and Sunoco LP contributed 5%. ETE announced last month a quarterly distribution of $0.285 per unit. This equates to $1.14 per unit on an annualized basis. It will be paid on May 19 to unit holders of record as of the close of business on May 6. Let's look now at liquidity and financing. ETE continues to have a healthy liquidity position. We ended the quarter with debt to EBITDA ratio of 2.87 times for our credit facility. As of March 31, 2016, there was $965 million in outstanding borrowings under the facility. Therefore, at the end of Q1 2016, the overall ETE standalone debt was $6.4 billion with a blended interest rate of 4.89% and with no pending maturities until almost 2019. In light of the downturn in the energy commodity prices and the related impact on ETE's businesses, resulting from reduced drilling activities of ETE's oil and gas company customers, ETE began to explore ways to reduce the indebtedness and improve the credit metrics of the pro forma company following the closing of the Williams merger. In March, ETE completed a private placement to certain common unit holders who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units, participating in the plan for a period of up to nine quarters, commencing with distributions in the first quarter of 2016. And to reinvest those distributions to a Series A convertible preferred unit. At the end of the planned period, the units are expected to automatically convert into 79 million ETE common units. Based on the leverage of participation in the plan by electing unit holders for the first quarter of 2016, ETE was able to reduce its aggregate cash distributions by approximately $58 million. Now turning to Lake Charles, which to remind everyone, is owned 60% by ETE and 40% by ETP. Progress continues to be made during the first quarter, and we are currently engaged in various early works projects. As previously mentioned, all regulatory approvals have been received. On February 15, Shell completed its acquisition of VG and Shell is actively continuing its due diligence on the project. Project financing efforts remain on track, and preliminary responses from the lenders have been positive. We remain on target to reach affirmative FID on the project in the fourth quarter of 2016 with construction expected to start immediately thereafter and the first LNG exports anticipated mid-2021. Before opening the call up to your questions, I would like to say that our diversified business model continues to allow our business to demonstrate resiliency in commodity markets that have been challenging. ETP is nearing completion of its major project backlog spending, which is built along long-term third-party demand fees that give us visibility into future EBITDA growth, particularly in 2017 and 2018. Our counter parties remain strong, high-quality companies or have security for performance that is well structured to mitigate risks. The underlying fundamentals of our business are strong, and we believe we'll be in great position for growth. We have a strategy in place to internally fund the remainder of ETP's 2016 CapEx program. ETE's priority is to support its core operating subsidiaries, and ETE will continue to take the steps necessary to ensure that they maintain their financial health and investment grade ratings. We remain very focused on improving our balance sheet strength by further lowering our leverage and increasing coverage. And our commercial and operations teams continue to concentrate on project, execution, and cost management. With that, operator, that concludes our prepared remarks. Please open the line for questions.

At this time we will be conducting a question-and-answer session. [Operator Instructions] Our first question comes from Brandon Blossman with Tudor Pickering Holt. Please proceed with your question.

Good morning. That was a lot packed into a short period of time. I guess I'll start with a detailed question on the merger, if you can comment on it. The S-4 related to the tax issue, there was some commentary from Williams. It looked like they had proposed some alternate deal structures. Were those proposals a non starter in terms of getting the tax issue resolved?

This is Tom Mason, General Counsel at ETE. We certainly took their proposal seriously and looked at them very closely, but as indicated in the S-4, we believe there is some serious tax issues with those alternative proposals as well, so we don't really think that that fixes the issue.

Okay, thanks, Tom, that's helpful. Perhaps an easier question, in regards to 2016 drop in growth CapEx, the $1 billion related to the project finance, any color available on the other $400 million change quarter-over-quarter?

This is Mackie. Probably won't get down to the exact dollar for each one, but wherever we can defer dollars, we are. For example, on our Revolution project, we still can live up to our contractual obligations to get the plant in service and the pipe in service by November of 2017, which allows us to defer some of those costs into 2017 out of 2016, and then there's other similar projects where it makes sense if we can push into 2017 and still live up to our obligations, that's what we're doing.

Thank you, Mackie. That's all from you for right now.

Our next question comes from Yves Siegel with Neuberger Berman. Please proceed with your question.

Not to beat a dead horse, but it is in the S-4, and you addressed it in your opening comments, but with the inability to get the Latham and Watkins opinion on the tax issue, can you just describe, what does that mean in terms of, number 1, being able to close by June 28 and if you don't close by June 28, what does that mean? And if you could, and I know I'm pushing it, but if you could, what are the economic ramifications? Is there a potential to be able to restructure this transaction?

Excellent questions, and you're not beating a dead horse, and I'd like to be really direct about this. We can't close. We don't have a transaction that can close. So I want to be very clear, we can't close this transaction. We have a merger agreement. We have obligations under that merger agreement. We take that very seriously. We intend to honor all of our commitments under the merger agreement, but we can't close this deal. We don't have a deal that's closeable. So absent of a substantial restructuring of this transaction, which Energy Transfer has been very willing and actually desiring to do, absent that, we don't have a deal. We'll work it the best we can. We think Williams will as well. We think we will engage with Williams and attempt to get a transaction that can close, but the one we have now cannot.

So is June 28 at hard date then?

I guess you're referring to part of the merger agreement states I think our transaction is not closed by June 28, then either party can walk away from this transaction. You know, it's an excellent question. I don't think anybody involved in this transaction has this -- has experience as it relates to this matter. For example, June 28 comes and goes and we don't have a transaction closed. Yes, either party can walk away from the deal. We're not really focusing on that date at this time. Rather, we are focusing on -- we don't have a transaction that can close. What do you vote on? I don't know what you take a vote about. So that's the bigger problem at this time.

Well, thanks. I'm not going to push it. Just stay tuned, I guess. Good luck.

Our next question comes from Shneur Gershuni with UBS. Please proceed with your question.

Just wanted to go back to Brian's question quickly on the CapEx side, Mackie, if I understood your response correctly, some of the CapEx is basically rolling from ‘16 to ‘17. Does this mean that your EBITDA target is, basically, still intact? And then secondly, is some of the reduction in CapEx just a function of being able to just come in under budget on a couple things and we should see higher returns on the projects? I was wondering if you could sort of talk about the cadence of the CapEx as well as the EBITDA ramp over the next, I guess two years at this stage.

Let me talk specifically about Rover. When we first announced Rover, we anticipated it having it in service by the first quarter 2017. The process of going through the FERC approval process took longer than we anticipated. That pushed the date back. We made it very public that's now July 2017 when kind of first phase, call it, from many of the power plants -- processing plants in eastern Ohio will connect to Defiance on the northwest end of Ohio. The next phase we will complete will be up to Vector for delivery into Dawn by November of 2017, and that also includes laying the laterals over into Pennsylvania and into West Virginia. So the plant that we are building at Revolution has to have a residue pipeline. Since that pipeline has been delayed and will not be in service until November of 2017, it has allowed us to push some of those dollars on Revolution into 2017. We still will hit our same EBITDA numbers that we projected. Our costs are in line and close to where we project them, and the project looks very good right now.

And maybe as a follow-up to Yves question, the 721 opinion. I was just wondering if you can give us a little bit of color with respect to why the issue is popping up now versus at the beginning. Did Latham not provide some comfort at the time that this was possible? I'm kind of curious about that. And then, secondly in your response to the June 28 date that you just spoke with Yves, can either party extend for another 90 days with notice, or is it truly an end date?

This is Tom Mason again. On the first question, yes we just realized a few weeks ago that this was an issue. And I guess how that came about is somewhat perplexing that we didn't realize that there was an issue when we signed the transaction on all parts. But I guess it was one of those light bulb kind of things that came about a few weeks ago and we were like, initially just didn't believe that there would be an issue. As we really looked into it and spent a lot of time and as the S-4 indicates, we've not only consulted with Latham, it's been an extensive amount of time looking at this issue at the highest levels to really determine whether it was the issue that it was perceived to be and they did conclude that it was a problem, a big problem. So we also engaged with other legal advisers to check, due to the significance of the issue. It did come up late kind of just a light bulb moment. On the second question, there is a provision of the merger agreement that either party can extend the so called, I think it's called the outside date, the June 28 date for 90 days if all the regulatory approvals have not been obtained by that date. We anticipate having all the regulatory approvals by that date, so we don't anticipate that the 90 day extension will come into play.

Our next question comes from Michael Blum with Wells Fargo Securities. Please proceed with your question.

One question, a couple of questions, if the deal with Williams does not ultimately get closed, would you still expect our plan to waive IDRs at ETE in support of ETP if you are a standalone company?

Well, I want to make sure I understand. Michael, this is Kelcy. The preferred units that have been issued, that's non retractable. Those units so those discounts are already done. And are you asking then do we believe that there will be distribution cuts to the ETE if we do not consummate the merger with Williams?

Either that or further support in terms of waiving IDRs on incremental common units issued and things of that nature.

Yes, absolutely. Michael, yes. ETP is in great shape, but ETP finds itself in this incredible growth vehicle that when you got this backlog of growth, and Mackie has done a phenomenal job, and Matt Ramsey and others of trying to push those dollars out as far as we can, but until those projects come online and begin to demonstrate the growth that I think everybody's going to be very pleased with, ETP needs some assistance, and as we've said in previous calls, ETE will stand up and get at that assistance. And we are going to when we can, we're going to be proposing to the board that there will be IDR waivers for any equity issued in 2016, where we waive the IDRs from the equity until 2018, when all this growth will be realized.

Second question is just an outlook. Can you provide an outlook for midstream for the rest of this year, and maybe within that context if you could just talk about the trend you are seeing in volumes by region?

Sure, this is Mackie again. If you look at a year ago 2015, first quarter versus 2016, we're up about 20% in West Texas on our volumes, and we are up about 10% in the Eagle Ford, which are two of our most active areas. We continue to see growth, and we're optimistic about Delaware and Permian basins, as Tom mentioned in the opening. We've brought on Orla. Within 30 days, it's running pretty close to max capacity. However, we have seen a significant slowdown in the Eagle Ford. We are hoping that we can keep volumes flat for the remainder of the year. There were some volumes shut in and some other issues with producers in the first quarter. We are seeing some of those volumes come back on, so first quarter compared to fourth quarter was down a little bit, but we continue to believe the Eagle Ford will hang in there, the Permian basin, Delaware will grow. The Northeast is growing, it just doesn't show. If everything that we tied into that is dedicated to us flows, our volumes would probably be up 7% or 8% at least in this quarter and ongoing quarters, but the inability to get gas out of the systems in north central Pennsylvania mainly has really minimized or made it very difficult to grow our volumes in the Northeast. But as pipeline projects are completed, certainly some that we're not a part of, but once Rover is completed, it will open up the Northeast in a big way and we'll see significant midstream benefits from that. The other areas are struggles. The Mid Continent, North Louisiana, are areas where we are doing our best just to keep volumes flat because of the amount of rigs that have been pulled out of those areas. And if you look at the first quarter 2016, it started at $42 per barrel, fell to 26, went back up to 30, and I think the average was in the low 30s. Probably about as challenging of a WTI commodity and hence the impact on the liquids related that we've seen in years. We feel like we've kind of weathered the storm. We know we've got, you know, a challenge the rest of this year, but we are extremely optimistic for the long-term.

Okay, Mackie, do you think that Q1 is the bottom for midstream earnings?

We sure hope so. I mean, if you can tell me that WTI stays where it is and goes up, I'll say absolutely. The trend right now is for oil to continue to strengthen. We hope that continues. There's opinions all over the board of where it may go, but we'll hang in there or continues to go up, hence dragging liquid prices with it, we'll continue to see an improvement in our POP contracts and we'll continue to see improvement and hopefully more rigs moving back into these areas when we have such a significant presence.

I'll add one thing to that. I think we are from discussions that we're having with the producers, I mean, it's not euphoria of there, but at least we're starting to see a lot of discussions around producers as WTI has ticked up. As Mackie said, that ties in with additional volumes and liquids and particularly the Permian and Eagle Ford. There's quite a bit of discussion amongst our customers about things moving forward at these higher prices and the activity starting to pick up.

Last question from me just on Revolution, can you talk about where that stands in a little more detail? I know that was like originally a 1.5 billion potential project with commitments. Ca you talk about where the timing sits with that?

Let me say again, Our guys did a great job on that project. It is incredible rocks and reserves. There are tremendous other opportunities up there to add to that business. I don't know if we've done a public update, but the 1.5 billion has been significantly reduced. The primary reason is our original route on our 30-inch took kind of a bigger loop, kind of a safer route to get to Revolution from the field. We were able to through the process of buying right-of-way find a much shorter route, and so that saved us a couple hundred million dollars or will save us a couple hundred million dollars. So the costs are down. We are moving forward on a project. We do anticipate having it in place and in service by November 2017. We do expect volumes to be there, and we are in conversations, not only with our foundation shipper about increasing volumes, but also with others. It's very important that commodity prices hang in there, that WTI stays where it is and goes higher. That's a tough area until you get better outlets, but it all kind of comes together when Mariner East, SXL franchise that's growing almost daily to move liquids to the East Coast at Marcus Hook, and then when Revolution comes online, we'll be able to offer the full solution all the way from the wellhead to loading ethane and propane on ships. Great project and we expect to have it in service by November 2017.

Our next question is from Heejung Ryoo with Barclays Bank. Please proceed with your question.

Starting with a follow-up on Revolution, how much is in your 2016 CapEx versus 2017 at this point? Is it mostly, was the 2016 pretty much all pushed out to the 2017 spending?

Helen, this is Tom. Clearly, that was a piece of the deferral.

We spent probably about 40% so far this year. We will probably spend another 20% or 30% remaining for the rest of this year. We'll push the rest of it into 2017.

So essentially, 60% or 70% will be spent this year and the remainder next year in order of magnitude?

Yes.

This project scope itself, you're saving a lot of money on the right-of-way side, but like the frac capacity that you're going to put in Marcus Hook, the processing capacity, has there been a significant change in those facilities?

No. We're building a 200,000 day cryo at Revolution there west of Pittsburgh. We are building facilities to be able to batch liquids into Mariner East down there in Houston and we're in the process of building the frac at Marcus Hook with the help of SXL so nothing's changed. Certainly, we'll have the ability once the commodity prices really strengthen to add to the project and add additional cryo space and additional frac space. Now, the fractionator that we're building does handle more volume than just Revolution, so it will have additional benefits and synergies with the SXL assets at Marcus Hook.

And that's a 440 frac, correct?

A 440?

I'm sorry, the size of that frac. Could you remind me the size of the frac?

I believe at 60,000 barrels per day.

And then on that pool, the project financing going on, is it the expectation to -- are you going to consolidate the DAPL debt at Energy Transfer? Also on the costs, it seems like you're going to get a whole lot better costs by doing project financing. Do you have a sense at this point for that may be at?

First part of your question as we will not be consolidating, that being a joint venture, it will not be consolidated. That'd be what we call, you know, off balance sheet type financing. As far as the cost piece of it, it's very early in the process but I would say that it is a very competitive cost of financing. You'll clearly be lower in the single-digits as far as interest rates go.

And then lastly the comment on Lake Charles, so did I -- and I apologize if I missed this. But did you say FID fourth quarter this year and that construction will start immediately? Could you talk about the commercial side, the contracting side, and also is there a potential for that, the economics to you could be changed, or do you expect it could be the same as what you communicated in the past?

This is Todd Carpenter with Lake Charles LNG. We're still on track. On the marketing side, again, Shell is making a careful evaluation of the all of their projects right now, and they're -- on this project we provide the financing and we provide the project. Shell will handle the marketing of it. That's probably a more appropriate question for them.

In terms of economics, I know in the past you guys talked about like 15% type of poll agreement on the EBITDA being generated. Is that still a good working assumption to use, or could that term get renegotiated?

Yes, Helen. We don't really have any updates. In other words, what we've been communicating is still the same as far as the economics go on that.

Our next question is from Gabe Moreen with Bank of America. Please proceed with your question.

Can I ask Michael’s question a little bit differently. In terms of the IDR waivers on the incremental ETP unit issuance, can you maybe just talk about any others, I guess support for ETP. You are half contemplated, whether it's waiving an absolute dollar amount of IDRs or targeting a specified coverage ratio at ETP and whether you -- how you thought this was sort of the best solution? And then also given the timing dependence of the incremental IDR waivers, does that imply you'll be issuing a little bit less of ETP on the ATM in the second quarter to see how the merger settles out?

This is Kelcy -- I had my thing on mute. For example, I have asked that all the revenue generated from the preferred be directed to ETP. Tom Long has that available at his discretion to use solely for the benefit of ETP. As you know, the preferred was also raised because we had to show the rating agencies how we were going to begin to handle this load of debt post the Williams merger, but absent that, that is earmarked for ETP. In addition, any equity issued, as we've said. We've got to get board approval, and we can't do that yet so this is our intention. Any equity issuance by ETP in 2016, IDRs on that equity will be deferred to 2018. That is not the total fixed Gabe. I think to answer your question, there will be a series of other things that ETE will do to support ETP until it can get through into the latter part of 2017.

And on the last part here. As far as the ATM, how much will it be, how active will it be I really wouldn't want to guide you down below the levels that we saw in the first quarter. In other words, we're going to be opportunistic in how we issue under that program, but I would probably stay within the same range as what you just saw with the first quarter.

Tom, I think just to clarify, the IDR waivers would only kick in post closing of the merger.

Good point, Tom.

So then to clarify, in terms of those three assets, it sounds like the cash you are saving on the preferreds at the ETE might be an explicit IDR waiver from ETE to ETP. Is that correct?

That's correct.

And then just a quick question on Dakota Access, the Army Corps of Engineers permits are still outstanding. Is there a timeframe by which you would need those permits received to start construction in the second quarter?

Dakota Access.

As Tom mentioned, and I've got to say this again, our team did such an incredible job getting that project off the ground and bringing it to where it is today, likely seeing all over the country. There's a lot of opposition to pipeline projects. Certainly, getting permits on that project has been difficult. We were very pleased getting a critical permit in Iowa, and we are really down to a lot of permits, but they're all coming from the Army Corps of Engineers. We are optimistic that we will receive those shortly, hopefully in a matter of days or weeks at the most, and we continue to be very optimistic that we'll have that pipeline built and in service by the end of the year.

Our next question is from Jeremy Tonet with JPMorgan. Please proceed with your question.

Just wanted to turn to the balance sheet a bit more here, I was wondering if you could share any thoughts with us as far as what the equity needs might look like for the balance of the year. Now that you're kind of able to smooth out the CapEx spend a bit here, it seems like that would be incrementally positive as far as maybe less equity needed. Could you provide any thoughts for us there?

Clearly, we had this plan in place for sometime as to everything from the SUN drop. As you've seen, we are very excited we were able to execute on that, get that in the first quarter like we had disclosed at the yearend call, so basically, sitting here with a credit facility that's basically undrawn right now. You're right. We do have optionality. Saying that, the real focus is to continue to look at the credit metrics, we're going to keep a balance of funding through the year here with opportunistically, once again using the ATM to continue to demonstrate, the balance sheet. Keeping the balance sheet credit metrics in line with what the agencies are anticipating. Let me just add a little bit more. I kind of go back to the previous question. I really wouldn't want to kind of guide you down from where we were in the first quarter as far as issuances go there. We'll evaluate that quarter-by-quarter.

And then just looking at the Eagle Ford, it seems like you guys have had some pretty good success relative to peers out there as they faced more declines. I'm wondering if you could expand a bit on kind of the secret sauce there. Are you guys winning market share, or how are you delivering strong results there?

Well, I'd be remiss to not brag about our team. I think we have the best team in the industry. We focus on what the producers asked for, the type of services they asked for. We tell them where we are going to build it, and we do our best to build on time, to build in a way that we'll be efficient and run reliably. I think her our record has helped us get where we are at. In the Eagle Ford, our strategy was to build a 30 inch down the very heart of the rich gas play, so we are really about as close as anybody can be to the entire length of the Eagle Ford rich portion of that play. We have kind of gone from almost nothing three or four years ago to 1.4 or 1.5 BCF per day. As I mentioned earlier, we've increased it by about 350,000 from first quarter 2015 to first quarter now. We've also in some cases have been very aggressive. If there's an opportunity to go pick gas off of a competitor, we do that. It certainly may mean the margins are tighter than we like, but as Kelcy has emphasized for the last 10 years is that we can't control margins. Those are negotiated. We do the best we can. What we can control to the best of our ability is volumes, and it's very important to us and we pride ourselves on doing the best we can to keep our systems full, even in challenging times that we're going through like today.

Is there a similar dynamic with the fracs in Mont Belvieu? It seems like volumes ramped up quite quickly there. Just wondering, is that your own volumes or are you taking market share there as well?

It's both. Steve Spaulding has done a fantastic job with his team. We've got three fracs built very quickly over the past several years. We've got another frac coming on at the end of this year. He's dying to somehow get other fracs going. Probably a little premature for that, but there's a lot of gas I'm sorry, a lot of liquids that we do frac. A lot of our customer producers prefer us to pay them to tailgate our processing plant and to deal with all the transportation fracking. We do a lot of that ourselves. As I mentioned earlier, whatever the producer desires, if they'd rather take it in kind and negotiate with Steve at the frac with his team or with others, Steve has done a really good job of, one making sure all our contractual obligations are met, and then filling that in, whether it's opportunities to pull liquids off of competing fracs at Mont Belvieu.

One last one, just as far as level of ethane rejections you're seeing across your system, how is that looking right now? Do you see that, trend reversing and specifically for the Eagle Ford and East Texas assets, do you see more opportunity there?

If you look at it as a whole, there's a lot of positives toward ethane. If you look at the crackers that have come online over the last two or three years, if you look at the export growth that's projected, you know, there's certainly growth at marcus Hook. There's significant growth that's being built out of Mont Belvieu. So we do see ethane growing in the future fairly significant. Pretty optimistic on ethane pricing, as far as rejection of recovery, we're probably a little different than most of our competitors in that we evaluate the state of Texas daily on what makes the most sense for our entire franchise. Not only the processing fees but also the transportation liquids and the frac and other benefits from a day-to-day perspective, we recover, what's the best interest for our customers and for our bottom line.

Our next question is from Kristina Kazarian with Deutsche Bank. Please proceed with your question.

A couple quick clarifications, so I know how nonrecourse debt works, but Moody's treatment of it has been more varied, can you just talk to me about relating to DAPL/ETCOP, and have you chatted with them yet? Is any portion counted against your leverage?

Christina, actually a very good question, I will say that between the agencies they all look at it a little differently, whether they use it on a consolidated basis or unconsolidated. You're exactly right. Moody's does really focus on a consolidated basis. You know, we do show it to them both ways. You know, as we go through it. I think the key to it is the second part of your question is very important in the sense that we did lay all this out for them early on. That's the reason earlier when I answer the question about we've been executing on our plan, we have stayed right in line with what we've been showing them since last year of how we were going to go through this. And so they understand everything from executing on the drop, to this project financings, off balance sheet. So this is exactly how we've laid it out to them and they are very aware of it.

The second quick clarification, going forward more, calendar year 2017 CapEx, you know, what the change today on 2016 could imply for that? It looks like I would chart the trend down toward a lower number, more like something like $2 billion-ish. Am I thinking about that trend right and any comments around how I should be thinking of magnitude there?

Yes. Christina, I'll answer the first part of your question. Are you thinking about a correct? Yes. It's probably a little bit early for us to give our 2017 guidance at this time. We're still doing probably a little more analysis on that. You can anticipate that coming out, you know, sometime this year. You're absolutely thinking about it correct.

Perfect. And last clarification one for me, I know you guys touched upon some of the regions that have volumes that have been particularly strong especially in the Eagle Ford. In the past, we talked about NBCs. Can you remind me which regions you guys have these in and how much they helped out during the quarter?

Demand charges?

And volume commitments.

That's a very broad question. The reason I'll answer it that way, we have a mix of contracts. If you pick the shale, we have a mix. Our focus has always been to put as much demand charge on our business as possible. There are areas even in West Texas where it is acreage dedications that don't have a strong as many demand components to it. In the northeast and lot of our new projects, like oars they're all demand based, of course all our interstates are. It's a pretty broad mix between fee-based, demand, large amount demand, or just POP or just pure acreage dedication depending on the basin and the customer.

I get it is a broad question. How about if I pick the Eagle Ford and just hone in on that one, can you just remind me how contracts are generally structured there?

Yes. The vast majority of the contracts are 85% to 90% demand based similar to our fracking business on the NGL side.

Our next question comes from Darren Horowitz with Raymond James. Please proceed with your question.

I'll be quick, because a lot of ground has been covered. Kelcy, just have one question. In your opinion, from a structural perspective, and I apologize in advance are asking this question, but what would a deal look like that you could close? Is it as simple as an all equity structure with the right terms that has been kicked around for the past several months in the press, or is it much more than that?

You know, I would like to say, Darren, and I'll do the best I can to answer that. Obviously, we've made it clear that we think an all equity structure is better for both us and Williams. You've got to realize these people are going to be unit holders of us going forward, or shareholders, whatever the case may be. The burden this resulting combined entity with that much debt, that's just not good business judgment. So we would prefer a restructured transaction that would remove the cash component and equitize that and by the way, that could be structured pretty easily without all the CCR nonsense that's in the merger now. We would like that, but we can't speak for Williams. We don't know what they might be open-minded to doing.

Our next question comes from Ted Durbin with Goldman Sachs. Please proceed with your question.

Just on the interstate itself, it looks like based on the FERC filing, this new Tiger Tariff with Chesapeake is going to reduce revenues by $55 million to $60 million. I guess are there any offsets that you negotiated maybe in midstream or other parts of the businesses to talk about that?

This is Mackie. We certainly negotiated with them around Tiger and around some desires that they had. I believe that number is a little bit high this year. It's not quite as high as that. There are some other settlements or negotiations that we did with them in other non regulated assets that certainly add additional revenue, add new business in the future. And so as a whole, not only have we -- we have taken some pain in the next couple years, but we've added business not only on Tiger by extending contracts but also added business in other shale areas out past 2030 and beyond.

And then on Rover, are your shippers asking to defer to them some of their commitments? And then can you talk to -- is there actually a ramp in returns that we should model, or should we just come online at the six to eight times build multiple you've guided us to?

We are really not probably, we don't of a policy where were going to get into conversations where any kind of requests we have right now. Right now all of our customers are 100% demand day one on Rover. We still have 150,000 left, and we're aggressively trying to sell that. We're certainly open to restructuring anywhere in the country where it makes sense for our customers and for us, but right now everybody is expected to come online with their volumes day one [indiscernible].

There are no further questions at this time. I'd like to turn the call back over to Thomas Long for closing comments.

Yes. And thank you, everyone, once again for joining us today. I think kind of going back to the opening comment on the questions, you know, a lot packed into a short period of time. I think that sums it up well here. We do a lot of great things happening here, as you can see. You know, from our quarter results. As we look at ’16, where executing very well on everything that we said we're going to execute on. Like I said, as we look out through the year and the years beyond, we feel like we are very, very well positioned, continue to get through the down cycle we have here right now. Thanks again, everyone.

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