Greetings. And welcome to the Energy Transfer Partners’ First Quarter Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Jamie Welch, Group CFO. Thank you. You may begin.

Good morning, everyone. And welcome to ETP 2.0. Thank you for joining us today. With me is Tom Long, who joined ETP as our Chief Financial Officer, following the merger of Regency with Energy Transfer Partners, that was completed last week. I am also joined by Kelcy Warren; Mackie McCrea; John McReynolds; and other members of our senior management team who are here to help answer your questions after our prepared remarks. We’ve got to change things up for the call this morning. With me sitting in anchors chair, Tom, will assume that role from next quarter on. We had an extremely business quarter in quarter one and we have even more than usual to talk about this morning. I'll begin with highlights from the first quarter then give a rundown of new growth initiatives and recent developments. We will then update you on our continued execution on already announced growth projects. I'll then invite Tom to provide a brief summary on Regency’s quarter one performance. We will finish with a discussion on our and update on the Regency merger and then ETE’s highlights. Following that we will take questions. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities and Exchange Commission 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. Let me start with quarter one results, I will discuss first standalone results and highlight those on a pro forma basis for the merger. We had a very good quarter overall and for the most part tracked street estimates…

Thanks, Jamie and good morning everyone. Looking at Regency’s financial results for the first quarter of 2015, compared to the first quarter of 2014, adjusted EBITDA increased to $282 million, compared to $205 million in the first quarter of 2014, which included 11 days contribution from PVR. This was primarily due to increases in the gathering and processing, contract services and NGL logistics and natural resources segments. For gathering and processing, adjusted segment margins increased to $268 million compared to $166 million as a result of the acquisition of PVR and Eagle Rock, which were partially offset by operating impacts in the Permian as a result of the severe winter weather in January of 2015, as well as lower commodity prices. Total gathering and processing throughput increased to 5.8 million in MMBtus per day compared to 2.7 million in MMBtus per day. And NGL production increased to 168,000 barrels per day compared to 101,000 barrels per day as a result of the acquisitions of PVR and Eagle Rock, as well as increased volumes in West and South Texas and in North Louisiana. For contract services, adjusted segment margin increased to $70 million from $56 million and revenue-generating horsepower increased to $1.3 million compared to $1.1 million, primarily due to horsepower additions in South and West Texas, as well as Colorado. Utilization for the first quarter was 96%. DCF, which for the first quarter of 2014 was adjusted to include a full quarter contribution from PVR decreased to $166 million for the first quarter of 2015, compared to $181 million last year. This decrease was primarily due to lower pro forma adjusted EBITDA, inclusive of PVR's first quarter 2014 contribution, which was primarily the result of lower commodity prices. Also contributing to the lower DCF was higher interest expense. Regency’s growth capital spend in the first quarter was $531 million, including $92 million related to the Lone Star joint venture and maintenance capital was $22 million. Looking ahead, the 200 million cubic feet per day Mi Vida plant in the Permian is on-line. This plant is part of a joint venture with a key producer in the region and volumes are expected to increase throughout the year. Additionally, in North Louisiana, the 200 million cubic feet per day Dubberly processing plant and related NGL pipeline came online in mid-April and volumes are expected to reach capacity by year end. In the Northeast, construction of the Utica Ohio River expansion continues, And Phase I of the project is expected to be in service at the end of June 2015, with Phase II coming on-line in Q3 of 2015 and the Harrison County lateral is expected on-line by year-end. In South Texas, volumes are expected to continue growing on the Eagle Ford ended Edwards Lime joint venture. Commercial synergies are expected between these gathering systems and the nearby ETP processing plant. And with that, I'll turn the call back over to Jamie.

Thanks, Tom. Before moving to results from Energy Transfer Equity, we want to touch on our distribution announcement and give you an update on our Regency merger. Last week, we were pleased to announce the seven straight quarterly distribution increase to ETP to $1.015 per unit or $4.06 per unit on an annualized basis. This represents a distribution increase of $0.32 per common unit on an annualized basis, or 8.6% compared to the first quarter 2014. And it will be paid on May 15 to unitholders of record as of the close of business tomorrow. Among the MLPs that have reported so far, about half have held their distributions flat and a handful have produced it. So, we feel very pleased to be able to share with our unitholders the benefits of our diversified business model and the growth projects we've been investing in. The standalone ETP, our DCF coverage ratio was 1.18 times. We think this is a tremendous achievement, given the backdrop of the current commodity price environment. When you pro forma for the Regency merger that closed April 30 by including Regency’s DCF for quarter one and the issuance of another $172 million ETP common units, the DCF coverage ratio goes to 1.04 times. That is before any synergies that we expect to realize from the combination of the two partnerships. To that end, we will discuss synergies from cost savings and commercial opportunities now. As we mentioned earlier, we closed the Regency merger last Thursday, April 30th. The new ETP organizational structure took affect from day one with people in the new role. We are very proud of the work done by the integration committee in quarter, backing the merger of the two organizations and the streamlining that has been done. As a result of the…

[Operator Instructions] Our first question comes from Shneur Gershuni with UBS. Please state your question.

Good morning, guys. First of all, thank you very much for some of the details with respect to Regency. It sort of helps us to tie up the thought process on it. You had outlined cost savings of $160 million to $225 million, but you did not sort of outline the commercial synergies. I was wondering how we could think about that. Is that a scenario where the backlog of opportunity grows for Regency? Or alternatively, is it a scenario where you spend less CapEx to achieve the same returns that you’re already looking for? I was wondering if you can sort of give us some color on how to think about that.

Shneur, this is Mackie. Really a little bit of both and we are certainly early on in recognizing all of the entities that between our different partnerships. But if you look at certain aspects of it in East Texas the chance that we have and we can ship on is around, there is also planned delays and/or even some situations we may not have to build plants. You look in the Northeast which we see is a huge growth platform for ETP with the success that Regency had and with some activities that we hope to announce soon with our some significant synergies there on both cost savings, on the boarding, spending some capital but also securing the volumes that we are negotiating, the both parties are negotiating this time. So as we continue to integrate the access, as we continue to analyze what we own also at East Texas, I am sorry out to West Texas, will continue to recognize significant value in cost savings and then revenue growth throughout all those areas.

Great. Thank you for the color. And maybe as a follow-up. Could we talk about the Lake Charles project given the impact of the BG merger with Royal Dutch? And as part of that, can you also remind investors the relative stake that ETE versus ETP has in the project?

Yes. Sure, Shneur, it’s Jamie. So the Lake Charles LNG or that liquefaction project is owned 60% by ETE and 40% by ETP. As we said in our prepared remarks that there was the announcement in April of the Shell takeover of BG Group which we expect to close in the first part of 2016. We are right now continuing down the path as if nothing has happened. As far as our timing is concerned, we've got our draft EIS that we mentioned. We have now actually received permit that we have received earlier this week. We’re continuing to get continue with our interaction with our EPC contractors and we’re sort of shortlisting the various consortia that we are engaging with. So we are right now continuing to try to be in a position that we are ready to in fact sanction the project in the early part of 2016, which will happen no doubt after the BG Shell merger happens but hopefully shortly thereafter.

Okay. And one final question with respect to the $1.3 billion for the Mexico pipeline projects, do you have a return profile that we should be thinking about, maybe expressing multiple returns?

I think Shneur, Mackie is going to jump in here too. But look I think much like Mike can again talks about they have six times EBITDA for their projects. I think we consistently look at our buckets on the sort of 7 to 8 times basis. And I think two projects both Trans Pecos and Comanche Trail fit within that category. We have partners that we potentially that we’re negotiating with right now and that we will own an equity stake and that we expect to announce. So our stake will obviously be a piece of the overall portion of the project, but it certainly fits within the profile of those economic boundaries on returns.

Great. Thank you for the color, guys.

Thanks, Shneur.

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

Good morning, guys. Mackie, if I could I just wanted to go back to your comments on the opportunity setup in the Northeast. And I know it's in the nearly stages per Jamie’s comment on the Revolution Project. But I'm just thinking about additional volumes in the Rover and then of course liquid volumes on Mariner East with Rover. Obviously, the nameplate is 3.25 BCF. Are you still thinking that you can get 1.5 into Michigan and Canada? And more importantly, how much incremental throughput do you think that could add to Rover? And then on the liquids side with Mariner East I would assume that that would be more backstopping face to East which was an incremental 275,000 barrels a day. I know that scalable. But I'm just curious as to your thoughts from an expandability perspective, how much throughput do you think that could represent?

Yes. We talked about this a lot yesterday. We would love to talk more about Revolution. We will over the next week or so be able to expand on that. But it will add a tremendous amount of value to not only our growth in G&P in the Northeast but also to Rover. We have already secured capacity on Rover from this project. We also have secured capacity from Mariner East too with this project and it will do nothing but continue to see residual volumes into Rover and other products into as it fills Mariner East project. In addition to that, there is other projects very close that we are working on that will also be great standalone projects but also continue to feed and be very synergistic with both Rover and with SXL’s NGL system.

Okay. And final question for me just down on Mariner South. Just thinking about the 200,000 barrels a day of batch propane and butane and volumes across the dock ramping. With all the CapEx that you all are spending in order to get purity product into Bellevue and ultimately effectively down to that dock, what do you think the scalable opportunity set is, not just in terms of incremental capacity but in terms of CapEx, maybe the opportunity for purity ethane? Or just from a cargo perspective, the ability to more efficiently get cargoes across the dock and move more barrels?

We could be more optimistic, really it’s SXL footprint both at market first on East Coast and at Nederland and our partnership with them on Mariner South and with extensive negotiation and discussions we’re having, it’s hard to quantify how big that can get. No doubt we need to find a way to export more propane, more ethane and it’s going to happen over the coming years. And we believe both Nederland end markets will play a significant role on that growth from the U.S. and ETP will play a significant part of that at Nederland no doubt.

How likely Mackie do you think it is that we could see kind of say volumes, vapor control stabilized, ultra light sweet volumes move across that dock or an extension of that dock at some future point?

I would say it’s very likely, both at dock and also some other terminals and some other areas we’re looking at a along the Gulf Coast. We continue to look for those type of opportunities.

All right. Thank you.

Our next question comes from Brian Lasky with Morgan Stanley. Please state your question.

Good morning.

Hey, Brian.

Just starting on Lake Charles really quick. I was wondering, Jamie, if you could just provide us a little bit of context around your conversation with BG. And how do they think about Lake Charles vis-à-vis their other Brownfield opportunities? Do you see any risk to timing potentially from that context? And then also in your discussions with them, are there any concerns about terms being renegotiated there?

Let me deal with the last aspect of your question first. Nothing has come up as it relates to the commercial arrangement between ourselves and BG recognizing that -- we look at that on a very simplistic basis, which is when we look at our tariff, which is sub $2.50 compared to what else is out there. As far as other projects are concerned, we think that speaks for itself. It’s the most cost competitive project that you could ask from a control standpoint or from a shipping standpoint. As it relates to BG’s timing, we are continuing down the path. As I said, we’ve just got to draft EIS and we got I think very much clean bill of help. We have air permit that we just got issued. So we are making I think very good progress on continuing to in fact check the box on the key development milestones as we move forward. So I think right now we have not been told to deviate from that path or the timing of that path and that probably coincides I think. We’re very closed to very much with the expected timing for the merger closing the BG and Shell.

Got it. And that’s I don’t know if I flip-flopped BG and Shell there, but that’s consistent with your conversations with Shell at this point in time?

We haven't been talking to Shell directly. We obviously have our joint venture with BG. We've been talking to the leadership of the BG including how -- including the CEO. And so obviously, we think we’ve got pretty good information and intelligence on exactly how Shell is thinking about the project.

Got it. Thank you. And then in terms of Revolution Project, realizing you guys don't want to get into too many details at this point in time. Could you just help us framing the relative CapEx opportunity, just in terms of order of magnitude there?

Sure. I guess this time we will be ending up -- probably going to be the neighborhood of about $1.4 billion.

Okay. And that's kind of gathering and processor fractionation and what else is kind of involved in?

Yes. All those and processing and of course pipeline residue and some liquid pipelines.

Got it. And are there -- is just like one major producer backing this year or multiple producers involved, how do this kind of originate?

As you are really good about asking [Technical Difficulty]. We won’t answer that when we are under the confidentiality.

Okay.

But you are anxious [indiscernible] over ETP but also for our affiliate companies and so we’ll be very open and vocal once we can talk about that.

Got it. Jamie, just on the timing of the up sea, you still thinking to fall here?

On the C corp form, we are finalizing the discussions with the service so we can get us 721b rolling issued. And we’ve been distracted on obviously getting the merger closed and then sort of focused I think on trying to get the C corp forms started and get that ball rolling. So I think whether it’s like for end to the year, I think it’s Kelcy’s comments from the last call.

And then in terms of the ETE distribution, there is some step-up Jamie, just assumed that kind of consistently throughout the year, is that how to think about that, the incremental?

Yes. We never do things without a lot of premeditated thought. And so obviously, we wouldn’t have moved to the $0.04 level if we didn't think that people might interpret it that way. So you will have no objection from us if you think that that’s what we will end up doing.

Perfect. And just one last one in terms of the order of magnitude kind of your low hanging fruit commercial synergies, how would you size that kind of relative to the cost synergies that you guys stated earlier?

No until that commercial synergies, relative to the 225, 160 to 225

Just in terms of the low hanging, I realize things are going to come up over time, but just in terms of kind of low hanging fruit stuff?

Yes. As I mentioned earlier probably that very clearly, we’re really, really all in, but there is no doubt to have significant synergies. We know when these cases are mentioned that we had a largest system in West Texas and Delaware basin. We’re working on numerous projects of not only adding assets but also tying our assets together that exist out there and then also in North East with early stages of really truly recognizing what those synergies and benefits will be. But no doubt, they’ll be significant.

Okay. I’ll jump back in the queue. Thank you.

Thanks, Brian.

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

Hey, Ted.

Hi. Good morning. Just coming back to the Bakken pipeline, I guess, first housekeeping ones. Are you putting any value on the extra transfer of the 30% to Sunoco you certainly provided with the GPs about the market value you’re putting there?

You broke up a little bit. I think the question was, are we putting a value on the transfer. There is a full capital reimbursement obviously for the 30%. And the other arrangements as it relates to between ETP and SXL, we have not disclosed at this time.

Okay. And so just sort of philosophically here, we’re transferring 30% now. Do we think longer term does the rest of it [Technical Difficulty] Sunoco because that’s your crude oil platform, just more about sort of in the near-term would you see financing [Technical Difficulty] ETP. Just sort of tell us how to get with the longer term for the Bakken?

No. We don’t anticipate the ownership change anymore. But let me say this, we couldn’t be more excited to have SXL as the premier oil transportation pipeline and partnership in the country by far and bringing them on board and they’re also going to operate. It’s going to add significant value. So we’ve taken a very good project and I believe or we believe, making a great with bringing them in, but we don’t anticipate any changes in ownership.

Can we talk about Rover in terms of the capital budget there? I think you sort of changed how are you going to get volumes up in the Canada. Is there any change to the CapEx forecast on Rover?

I think we went through it in February, there was we saved obviously about $600 million in total for the reduction of the hundred and plus miles reduction of pipe that we had delay through Michigan. So that was already reflect -- and that is now reflected obviously in what we filed with the earnings release and what we will file tomorrow with the Q.

Got it. And then last one for me, if you can just talk a little bit more about King Ranch? What’s the volume now going to the plant, maybe any sense of the EBITDA that is generating? How do you see that ramping overtime, whether it’s adding, I guess, third-party volumes or what not?

This is Mackie again. Let me just say, we are also very excited about that project, albeit its been there awhile but it’s a perfect place to be very synergistic with not only our Eagle Ford growth but also with some other growth and almost this quarter again in getting closer to Mexico in delivery of products. As far as EBITDA, it’s too early for all that and volumes are very good. Its probably about two-thirds full right now. We anticipate ramping that up over the next 12 to 18 months and in fact we are also looking possible adding additional facilities there, cryogenic facilities and even possibly fractionation service. So it’s a great location and there is synergistic with all of our other assets at South Texas.

Great. I’ll live with that. Thank you.

Thanks, Ted.

Our next question comes from Brandon Blossman with Tudor, Pickering, Holt. Please state your question.

Good morning, gentlemen.

Hey, Brad.

Actually you hit most of everything, I’ll just try to put some incremental color on the integration synergies here. One, really wide range here. I guess, what would drive you to one end of that range or another? And then how would you characterize the review to date? Does it been exhausted review and you think that you pulled out all the cost savings possible or is there still the possibility of incremental diligence and more to come?

Let me take the last expect first. I think we said in the remarks based on our initial estimates. So there’s always the prospect and possibly there could be more to come. I think, this is -- this doesn’t begin and end with the fact that we’ve now closed the merger and people are sitting in their roles. I think overall those typing is something you do everyday and you think about how you can make your business more streamline and more efficient and I think that very much is synonymous with the way we are thinking about. So this sort of range right now could in fact, obviously, improve overtime depending upon how we move forward. As far as the range is concerned, look there’s a lot of things in here, there’s some balance sheet management and what we do and how we did some things, how we think about some things, there’s probably at least 12 plus categories of cost that fit into that overall bucket just on the cost side and within then there is a significant amount of subset within each of those categories. So that’s what ends up giving the element of a wide range at $65 million of sort of low to high I think -- we didn’t think it was incredibly wide. But, nonetheless, I think, we thought that it was reasonable and appropriate and what we think it reflects our expectations.

And let me add, Jamie, this is Kelcy. We are done on staff reduction, so I am going to be very clear on that and so when we give you that range, our numbers can creep over in and get very impersonal. But from a human resources standpoint we are done and we lost some great people as a result of this merger and it’s -- unfortunately its part of business, but we have nothing else to do there.

Okay. Fair enough. That color is definitely helpful. I appreciate it. And then just another follow-up on the King Ranch acquisition, could you characterize it more as an attractive acquisition on kind of current multiples and deal metrics or is this really an acquisitions as a development platform with lots of interesting opportunities on a go-forward basis?

I’ll -- its Mackie, I’ll talk briefly about that, every single time, this is without fail, when you can find a platform Midstream asset this thing operated by someone who’s primary economic driver is not the Midstream business, you can never fail ever, I mean, of course, you go overpay, but that's essentially what this asset is. It’s been owned and operated by Exxon Mobil for years, very well by the way, they are great operators. But their primary driver, economic driver was Exxon Mobil production. Mackie and his team will absolutely change that and it will be operated with the primary economic driver being gathering and processing liquid deliveries, all the things that we do and do well. And I think you’ll if you give us a little time and I think you’ll be very impressed with what Mackie and his team does.

Okay. Great. That one will be interesting to watch. Thanks that all for me.

Our next question comes from John Kiani with Teilinger Capital. Please state your question.

Good morning.

Hey John.

I am thinking about the benefits of especially the synergies that you highlighted for ETP and the Regency transaction. How should we think about conjunction with the CapEx that you’ve been discussing today as well? How should we think about the distribution growth rate at both P and E over the medium term? And are we going to see the benefit of the synergies in the form of just better coverage overtime or is the $0.02 a quarter at P that we’ve been running at and the new $0.04 at E something that over time can improve?

Well, I think the synergies when you look at them on a pro forma coverage, if you get to comfortably over 1.1 times and you look at the overall capital budget that ETP has in front of it on a direct basis for the remainder of this year and into 2016, there is no one in the industry that has this amount of capital to deploy on the tremendous quality of projects that we have. So from our standpoint, I think our view has been, we've been very methodical. We’ve done the $0.02. I think we know what people have anticipated that our job is to get us through on a very consistent methodical basis through the end of next year and when you have projects of the quality of Bakken and Rover and Lone Star Express come online in 2017 that’s transformational for this partnership. It truly is transformational. And that I think is what our focus is immediately. We got -- I’ve got to ask the question on ETE. We were very deliberate on what we did as far as on the $0.04. We understand how people may interpret that. And I think we feel very comfortable with it. Our job is at the end of the day is shepherding ETP and SXL through this tremendous amount of capital to get them to the end of ‘16 and that commodity price environment, which remains pretty challenged.

That makes sense. And I guess just further on that with the $0.02 a quarter that ETP is growing out right now, it translates to on roughly 8% or so and it sounds like the benefits of both the CapEx and the transaction could provide upsides of that over the medium term. The cost of capital at P despite all that is not very attractive. What do you think about that and what are you prepared to do to try to improve the cost of capital there if it remains this way in the market?

Well,. I feel a little bit like what we did in November where we highlighted the various levers of alternative equity that can be boring to pay. They obviously help mitigate the issuance of units at a greater than 7% yields with an IVR obligation on top. There are things obviously as the drop downs are one, you saw that obviously in stage and what we did last month where we did a 95% cash, 5% units. And obviously continuing the drop-down story with SUN whether that’s on a sort of current timetable or even if the markets allow on a accelerated timetable. So more cash back debt is obviously one avenue. We got the stake in PES. We’ve got various sort of elements here within the overall business that we think we can harvest and monetize that allows ETP to bring equity into the system, keep its credit metrics at sort of the 4.5 times and allow us to maintain very, very much, very stable investment grade ratings. And I think significantly improve the prospects of its distribution growth going forward.

Okay. Thank you.

Thanks John.

Our next question comes from Helen Ryoo with Barclays. Please state your question.

Yeah. Thank you. Good morning. So I am just going to ask a couple of quick questions. First on Mexico project, could you talk about the contract duration and project return also. Are there any other Mexican projects in the work, I remember you mentioned a couple of other opportunities during the analyst meeting so if you could provide an update, that’ll be great?

Yeah Helen. This is Mackie. I do remember talking about those. Mexico’s going through transformational changes and their process of expanding their certain [indiscernible] transport done in the U.S. with 42-inch scope pipeline through our country and will continue to have RFPs for other countries to join and build that network out and that was net along with more of the United States. And so the first project that we started feeding early this year was a 42-inch that tied into the South Texas, the two projects that we’ve announced are connecting to also new projects on the Mexican side. So yes they will continue to expand and that work will continue in our side to play a big role on bringing bargains through our systems to Mexico.

Okay. And is this -- these two projects are they 10 plus years punch back life and also is the return consistent with your sort of five to seven type of cash return?

Yes, the seven question is consistent with the seven type multiple and these are 25 year returns.

Great. And then just on the Bakken project, I guess, Jamie -- you mentioned that the regulatory process is going well but there were some talks about some changes in Iowa in terms of the exercising eminent domain. So could there be possible that if the regulatory issues persist that there could be a delay in this project or do you have a very good handle on the project timing at this point.

At this point, we feel very good about the project time. We think we have the best team in the country to do these types of projects. Certainly they are not easy, certainly anywhere if you ask they golden pipe, they are going to find the oppositions just the nature of the business these days. But we don’t see anything, any types of hurdles that we’re concerned of that getting over. And right now, we are on track and have it build by January 2017.

Okay. And then just lastly on the factory and IV, the -- I guess your comment was both are fully subscribed and could you -- are they or the contract, I think we pay long-term 10-plus years take or pay. And also in fact IV, I mean Frac IV cost is 450, Frac III was I think 300 and of course Frac IV is a bit larger but is the cost difference pretty much related to the size or is there anything else that contributing to the Frac IV project cost?

Well, I talk about the cost -- when you talk about the cost on these frac, many times there is a subjugated piping and interconnects. And so the early frac didn’t have as far as any. We didn’t anticipate more on the 7 frac. We are building a bigger frac on 20%. We are also creating more connectivity to other markets throughout the entire Mont Belvieu area.

And then -- I’m sorry, on the contracts?

Yeah. Sorry, on the 7 frac. The demand, the beauty of all of our frac is they all are approximately 9% demand. So with regards to whether the price, whether the volume show up or not, we get 19% revenues that we forecasted and these are typically about 10 years, some of 15 years, typically 10-years wins.

Okay. Great. Thank you very much.

Our next question comes from Abhi Rajendran with Credit Suisse. Please state your question.

Hi. Good morning, guys.

Hey, Abhi.

Just a couple of quick one. Can you give us an update on the buyback at ETE? Have you used -- I’m just kind of looking ahead for the rest of the year, how you are thinking about that? I think last time you had said that you want to, kind of keep a decent amount of powder for the back half of the year, any update on that would be helpful.

Okay. So the short answer is we have not done anything on the buyback. I think we are very clear we are waiting for the merger to in fact close. And we also said, I think in the prepared remarks that now that we’ve completed the merger, we’ve got the coverage. We can look to deploy dry powder, if you will with the access coverage and utilize that to in fact start the buyback. We would be very selective and disciplined on how we in fact tackle it. So, I think that’s pretty much where we are.

Okay. Got it. And just a quick follow-up on that. I think coming back to the Up-C 73:01, you obviously bought back a bunch of stock already last year. Is the idea that you buyback some more before you go through the Up-C because that’s what you will use to put into the C-Corp of vehicle? Any color there will be helpful.

The short answer is the buyback which we’ve done -- when we announced the buyback, it was done on the basis of pure retirement of units, much like what we did last year. If we decide to get recycle units as part of some sort of, as part of a C-Corp form then obviously that would be a different use. And we think more about the overall size of the buyback and what would we do. So, I would say we sort of divorced the two. The buyback is very much, we were happy to retire a bunch of units because we feel we’re undervalued to C-Corp, so a completely different question and at the perfect time, we will consider what we do.

Okay. Got it. And last quick one from me. Just maybe looking out over the next couple of years in the past you’ve talked about possibly using the -- once Lake Charles gets to the finish line and you get your Lake Charles LNGs, MLP, up and running to possibly use that potentially rollout some projects. Can you just talk a little bit about the environment there how you are seeing? Some of these other projects kind of progress in this environment, if that -- has maybe changed at all or are you still constructive on that?

Look, from our standpoint, whether it’s on the pipeline side and I think pretty much on a pipeline side is where we see a lot of the initial interactions with lot of these LNG projects. Everyone seems to have an LNG project, whether they are small, whether they are mid sized, whether they are larger size. None of them seem to have any customers other than those that obviously -- that most folks like you have me run on. So, I think our view point is look, if the markets stabilize LNG and Gulf Coast, if you’ve got sub $3 gas is probably something at the right price that will make a lot of sense to a lot of people. I think right now, we are in a hiatus and I think people obviously are just spending a lot of time on development. We have done very little to show growth. So, we still talked to people. We talked to much people, I think as it relates to just pipeline connections, hookups but we do get a pretty good sense of what’s out there and what’s going on.

Okay. Got it. Thanks a lot for the color.

Our next question comes from Jeremy Tonet with J.P. Morgan. Please state your question.

Good morning.

Good morning, Jeremy.

You guys have covered a lot of ground this morning, so just had a couple of housekeeping items. I was wondering if you could give us any thoughts as far as how taxes could play out or any rules of thumb there for the balance for the year.

I would say as it relates to Holdco, now that [Mr. White] [ph] has assumed command and control on the tax side, we’ve actually -- I think have done a much better job of actually forecasting what our overall cash taxes and cash tax profile look like. I think our expectation right now for 2015 is that we will be relatively flat, meaning they will not be -- it will not be a source of cash nor a use of cash, which is a very good asset from our standpoint. And was obviously part of the original engineering and design that we’ve done by folks like Brad when we first set up ETP-Holdco. So, I think, look, we can probably take that offline and give you some more color, Jeremy, sort of as it goes along as to how to think about it. But our intent is always being to try to take some of that noise out of the system and make it relatively benign and black.

That’s helpful. Thank you. And then just one last one, the obligatory M&A question. Just wondering if you could expand a bit more on how you see the environment out there and overall, is it still widespread between bid/ask spreads and do you see any room for improvement in that over the course of the year if conditions are challenging?

Yeah. This is Kelcy. We are -- believe it or not, we are running full speed under the water here in the second duck. But we’ve not had any traction on anything. We are a little bit surprised actually. We thought we would see because of the frac spread contraction and how long it’s been down with commodity prices that we would see more opportunities. We’ve not seen them but we are -- it is not a good thing for an MLP to be our size with their family and pretty much all of the family members without the correct combination of M&A and organic growth. And so we recognize, we need to do some more M&A. We need to analyze some opportunities. But we are a little frustrated around that. We are just not getting the traction that we’d hope to get.

Great. Thanks for that. That’s it for me.

Thanks, Jeremy.

Ladies and gentlemen, there are no further questions at this time. I will turn the conference back to Jamie Welch for closing remarks. Thank you.

Well. Thank you for everyone’s time this morning and we will talk to you next quarter.

Thank you. This concludes today's conference. All parties may disconnect. Have a good day.