Energy Transfer LP (ET) Q4 2014 Earnings Report, Transcript and Summary

Greetings and welcome to the Energy Transfer Fourth Quarter Earnings Conference 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 Mr. Martin Salinas, Chief Financial Officer for Energy Transfer. Thank you, Mr. Salinas you may now begin.

Thank you, operator, and good morning, everyone and thanks for joining us today. I am joined by Kelcy; Mackie; John McReynolds; and Jamie and other members of our senior management team who are here to help answer your questions after our prepared remarks. We had another busy quarter and have lots to discuss this morning. In addition to talking about some of ETP's key accomplishments and providing a quick update on our announced growth projects, I'll also highlight a few points regarding our fourth quarter results which were very strong again this quarter. I'll then turn the call over to Jamie to discuss ETE's activities and other updates. Then we'll open up the call to take your questions. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the SEC Act of 1934. These are based on our beliefs, as well as certain assumptions and information available to us. I'll also refer to adjusted EBITDA and DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. Let's start with our recent distribution increase where we are pleased to announce in late January the sixth consecutive quarterly distribution rate increase for ETP to $0.9950 per unit or $3.98 per unit on an annualized basis. This distribution represents an increase of $0.30 per unit or 8.2% on an annualized basis as compared to the fourth quarter of 2013 and was paid on February 13 to unitholders of record as of February 6. And we managed our distribution coverage ratios to a healthy 1.12x for the fourth quarter and 1.27x for the full year. Needless to say our strong diversified asset platform continues to perform very well. We are very confident we will continue to deliver increased unitholder value through increased distributable cash flow as we execute our goals of bringing online significant organic growth capital underpinned by fee-based commitments, balanced with strategic accretive acquisitions as demonstrated with the recent announcement of the ETP-Regency merger. We want to assure you that given the volatility and uncertainty in the commodity markets today, we like everyone else in the energy business are extremely focused on cost and returns on projects we are pursuing. We will remain prudent in our decision-making process, selecting only those projects that offer acceptable rates of returns on our investments with limited risk and that provide strong, stable, distributable cash flow. With that, let's talk about some of our growth projects starting with a couple update on the Rover natural gas pipeline project. First, our partner in the project AE–Midco has exercised its option to increase its interest in the Rover project from 20% to 35% leaving ETP with a 65% interest in the project and reducing our required cash outlays. There are no more options from third parties to take any equity interest in Rover so the 65% ETP, 35% AE–Midco split will be the final ownership percentages going forward. As a reminder, ETP will be the construction manager and operator of the pipeline. Second, we have signed a long-term agreement with Vector Pipeline and its affiliates for firm transportation capacity to deliver gas to markets in Michigan and the Union Gas Dawn Hub in Ontario, Canada as part of the Rover project. The capacity arrangement with Vector not only provides seamless transportation services to certain Michigan markets and to the Dawn Hub for our Rover Shippers, but also eliminates the need for us to build approximately 125 miles of 42 inch pipeline. This arrangement also allows us to minimize project timing risk, while maintaining the overall rate of return on the project. The capacity of Rover remains unchanged at 3.25 Bcf per day with a minimum of 1.3 Bcf per day being transported into Michigan and/or Canada. Plans are underway to make the necessary modifications to the proposed project route and to file the final plan with the FERC later this month. Pending legislative approval Rover is expected to be in service from the production areas to the Midwest Hub near defiance Ohio by the end of 2016 and from the Midwest Hub to markets in Michigan and the Union Gas Dawn Hub by mid-2017. Now, moving on to the Bakken project where based on firm contractual commitments received to-date our takeaway capacity out of North Dakota will be over 450,000 barrels per day. The capacity can be increased to as much as 570,000 barrels per day. And as a result of our open season process, we are in discussions with several shippers about commitments that would underpin such an expansion. In light of cancellations and issues other companies have announced regarding their potential projects out of the Bakken, we are excited about the opportunity to further expand our project. It will clearly be the preferred outlet for producers and other shippers both from a cost and market access perspective. The pipeline project is scheduled to be in service by the end of '16 at a cost of approximately $4.8 billion to $5 billion. ETP and Phillips 66 will each contribute the capital to fund the project in accordance with their ownership percentages. That being 75% for ETP and 25% for Phillips 66. And on a separate but related topic, we continue to be in discussions with SXL and expect that they will ultimately have an equity stake in the project. We're also currently in the midst of our opening season for the Bayou Bridge pipeline project which we are jointly pursuing with Phillips 66. Bayou Bridge was directly linked to Nederland to refining markets in Lake Charles and St. James, Louisiana. We view this project as a natural fit with the Bakken project. And, of course, the project alliance well with Sunoco Logistics' major presence at Nederland. Depending on the outcome of the open season, we expect deliveries to the St. James Hub to begin in the second half of 2017. And we look forward to updating you on that project when we conclude the open season process. Looking next at the Eagle Ford and Eaglebine rich gas producing areas; the two new 200 million cubic feet per day cryogenic gas processing plant projects, that being the East Texas plant and the REM II plant, plus the 70 mile 24 inch Volunteer Pipeline, we announced in early November, remain on schedule for completion. REM II should be in service by June of this year and the East Texas plant and Volunteer Pipeline are both expected to be in service by the end of the year. Our Eagle Ford and Eaglebine processing capacity is about 1.4 Bcf per day currently and these two new cryogenic plants will expand that to 1.8 Bcf per day by the end of this year. Continuing then to Midstream value chain to our Lone Star NGL projects, starting with our Mariner South project. This joint project between Lone Star and Sunoco Logistics is now in service. And to remind you, Mariner South integrates SXL's existing Nederland Marine Terminal and pipeline from Mont Belvieu to Nederland with Lone Star's Mont Belvieu fractionation and storage facilities. Bottom line, it creates a world-class LPG import/export operation on the Gulf Coast with the capacity of 200,000 barrels a day of batching propane and butane and 24-hour ship access in the Gulf Coast. Mariner South is supported by long-term fee-based commitments and the total propane volumes exported which began in late January will continue to increase monthly and we expect the terminal to be capable of operating that capacity in the second quarter of this year. Speaking about Mont Belvieu facilities, recall that we along with Regency announced in November that Lone Star will be building a third liquids fractionator at our facility at Mont Belvieu which will bring Lone Star's total fractionation capacity to 320,000 barrels per day. The third fractionator is fully subscribed by long-term fee-based contracts and will enable us to handle the growing volumes on Lone Star, our Justice pipeline and other NGL pipelines delivering NGLs to Mont Belvieu. Factory remains on-schedule to be online by the December of this year. We also announced in November that Lone Star plans to build a 533 mile, 24 and 30-inch NGL pipelines from the Permian Basin to Mont Belvieu and also to convert Lone Star's existing West Texas 12-inch NGL pipeline into a crude oil condensate line. We expect these projects combined will cost between $1.5 billion and $1.8 billion and the new NGL line should be in service by the third quarter of 2016 and the NGL line conversion should be ready in the first quarter of 2017. Lastly, to update you on our projects to export natural gas into Mexico. In January, we placed into service our 51 mile Nueces Crossover pipeline which is a 36-inch pipeline with the capacity of 800 million cubic feet per day connecting the Houston pipeline system to the NET Mex 42-inch pipeline that delivers gas into Mexico. Our second project which should come online by the second quarter of this year is a 24 mile Edinburgh extension which will connect with the Houston pipeline at the border of Mexico. It has a capacity of 130 million cubic feet a day. Also a consortium which we are a member of, has been successful in two RFP processes with CFE for building new 42-inch pipelines from the Waha header system in West Texas to the Mexican border at Presidio and El Paso. ETP will be the construction manager and the operator of these two pipelines and upon completion will move up to 2.5 billion cubic feet per day. The Waha header system will have multiple pipeline interconnects including connections with the ETP Intra and Interstate pipeline networks. So let's summarize our CapEx spend for 2014 and I will lay out what we intend to spend in 2015. For growth CapEx in 2014 ETP invested more than $600 million during the fourth quarter of this year and more than $1.6 billion for the full year with the majority allocated to our Midstream, Interstate and Liquids transportation and services segment. Including our direct growth capital expenditures at ETP and indirect growth capital expenditures at SXL and Sunoco LP, full year 2014 growth CapEx was more than $4.1 billion. And for 2015, we are currently targeting $4.3 billion to $4.7 billion in growth CapEx. This range reflects our current ownership in the Bakken and Rover projects, but excludes our impact in the Regency merger to which we anticipate updating our CapEx estimates after the completion of the merger. In addition, SXL expect to spend between $1.8 billion and $2.2 billion in 2015 for those projects they are working on and Sun's growth CapEx is estimated to be between $155 million and $250 million for 2015. Before I turn your attention to our fourth quarter results I'd like to quickly brief you on our liquidity position. As of December 31, we had $570 million of borrowings on our revolving credit facility and we ended the year with a debt-to-EBITDA ratio as defined in our credit agreement of 3.87x. I am also pleased to say that earlier this month, we amended ETP's revolving credit facility to increase the capacity from $2.5 billion to $3.75 billion primarily to support the growth initiatives on the combined ETP and Regency organizations after the merger closes. The increase in new revolver is just one of the many initiatives we have to manage our liquidity and financing needs given the expected retail drops to Sun, the Bakken exchange with ETE, the potential transaction with SXL for an interest in the Bakken project itself and our ATM equity program. We believe these initiatives will provide financial flexibility, while supporting our investment-grade ratings. Now for our fourth quarter 2014 results. We had another very solid quarter overall. Adjusted EBITDA on a consolidated basis totaled $1.3 billion, that's up $296 million compared to the fourth quarter of 2013. DCF attributable to ETP partners totaled $623 million, an increase of over $140 million over the same period a year ago. The Midstream liquids transportation services and retail segments delivered particularly strong performances again quarter-over-quarter. In our Midstream segment volumes continue to grow and adjusted EBITDA increased by $37 million compared to the same period a year ago, primarily driven by an increase in fee-based revenues due to the continued expansion of our Midstream platform in both the Eagle Ford and Permian Basin regions. Gathered gas volumes totaled almost 3.5 billion cubic feet per day which is up more than 1 Bcf per day versus the same period a year ago. In addition, NGLs produced and equity NGLs continue to increase with production being up almost 82,000 barrels per day compared to the fourth quarter of 2013. This increase was primarily due to increased production from our customers in the Eagle Ford Shale area and increased volumes resulting from an increase of 320 million cubic feet per day and processing capacity at both our Jackson and Rebel processing plants. In the liquids transportation and services segment, adjusted EBITDA increased by $65 million compared to the same period a year ago also driven by increases in fee-based revenues from our transportation and processing and fractionation activities. Our NGL pipeline systems also transported approximately 442,000 barrels a day up an impressive 161,500 barrels per day versus this time last year. We also had a slight increase in storage margin due to the increased throughput activity around our Mont Belvieu facilities. And as it relates to fractionation volumes they increased by more than 88,000 barrels a day compared to the fourth quarter of 2013, primary due to the addition of our second 100,000 barrel a day fractionator that was placed in service in late 2013. As it relates to our natural gas transportation pipelines, starting with our Interstate segment; where transported volumes were lower than a year ago, primarily due to warmer weather in the fourth quarter of 2014 compared to the much colder weather in the fourth quarter of 2013. Although transportation volumes were down for the quarter, our Interstate adjusted EBITDA as compared to the same period a year ago was principally impacted by the deconsolidation of Lake Charles LNG. Transportation margins were actually up almost $4 million, primarily due to higher transportation revenues on our PEPL system. As it relates to transported volumes on our Intrastate segment those were down compared to the same period a year ago and adjusted EBITDA was down approximately $7 million. The decrease was mainly favorable to lower storage margins offset by increased transportation fees and natural gas sales. As we look to our Investment in Sunoco Logistics, which churned in another solid quarter in Q4 with a $27 million increase in adjusted EBITDA as compared to Q4 2013. SXL experienced higher volumes and increased margins from refined products and NGL trading partially offset by lower results from our crude oil pipelines. And lastly, but certainly not least, our retail marketing and distribution segment continued to outperform expectations in the fourth quarter demonstrating its resilience in volatile markets and serving as a nice hedge to some of our other businesses. This segment reported $295 million of adjusted EBITDA for the fourth quarter, which included approximately $66 million from Sunoco LP and $229 million from the remaining retail marketing and field distribution assets that we plan to drop down at the Sunoco LP. We have delivered strong results from the acquisition that we have completed over the last 17 months including the previously announced Aloha acquisition, which closed in mid-December. The business also benefited from exceptionally high fuel margins in the fourth quarter related to the sharp decline in the cost of crude oil and wholesale gasoline in this time period. We also are very well underway in executing our strategy to drop down the high quality retail and field distribution assets from ETP to Sunoco LP. We completed the first drop down to Sunoco LP on October 1 of last year, and we expect the next drop to consist the legacy Sunoco Wholesale Field Distribution business, which is almost entirely comprised of qualified income, we expect it to generally similar in size to our first drop-down and are working towards a plan to complete it over the next 30 to 60 days. That concludes the highlights for ETP. I’ll now turn the call over to Jamie. Jamie?

Thank you, Martin. There was a lot to get through and good morning everybody. The main headline since our last call was at January 26 announcement of the planned merger of Regency and ETP. This is a unit for unit transaction valued at about $18 billion including $6.4 billion of Regency’s debt. I hope by now you’ve had a chance to review the news release, as well as the investor presentation posted on our website that provides more detail as to highlights and benefits of the merger. The bottom line is we expect this merger will take ETP to the next level in our growth strategy, and it reinforces our position as one of the strongest and most diversified midstream companies in the U.S. It creates the opportunity for higher long-term distribution growth for ETP than what have been possible on a standalone basis. We filed the Hart-Scott-Rodino clearance last week and we expect to file our dropped proxy next week. We still anticipate closing the merger in the second quarter. As you may be aware, we filed an amendment last night to the merger agreement that modifies the transaction structure for the merger with Regency to become a subsidiary of ETP, as compared to the price structure which provided for Regency to merge directly into ETP. This change was motivated in large part by a desire to provide more flexibility under covenants related to ETP’s and Regency's outstanding debt. In addition, this structural change removes the requirement for an ETP unitholder vote. Also we converted the $0.32 per unit cash payment to an equivalent payment of ETP units, measured on ETP's unit price just prior to closing. This minor modification in the form of consideration simplifies and accelerates the SEC filing process for the merger. Switching topics; at our analyst day in November, Kelcy mentioned that we had analyzed the financial impact on the various entities at a $50 crude price. He indicated that each of the companies could withstand that environment even if it desisted through year-end 2016. The speed and steepness of the crude oil price decline has taken many by surprise. We believe that we will be in this low up for longer cycle, and as such this was one of the driving influences behind the merger of ETP and Regency. Lastly, we announced the intended SXL GP/IDR in Bakken Exchange at our analyst day. The terms were approved by the conflicts committees of ETP and ETE and disclosed in a press release issued on December 23. The Bakken transaction moves ETE closer to our strategic objective of becoming a pure play general partner and adds incremental exposure for ETP to this exciting project. We expect this transaction to close in a couple of weeks. As part of the transaction, which we outlined, ETP would receive 30.8 million ETP units currently owned by ETE; ETE's 45% interest in the Bakken pipeline, which would give ETP 75% of the Bakken project with the remaining 25% owned by Phillips 66; $879 million in cash, plus $26 million of reimbursements for Bakken development expenses, less construction related amounts funded by ETE for the Bakken project, which were approximately $140 million through year-end 2014. In exchange, ETE would receive an additional 40% interest in the SXL GP/IDRs represented by additional Class H Units to be issued by ETP. This entitles ETE to receive 90.05% of the GP and IDR cash flows from SXL from January 1, 2015 and a reduction in existing IDR subsidies from ETE to ETP in 2015 and 2016. Moving over to liquidity and financing; earlier this month ETE amended its revolving credit facility to increase the capacity to $1.5 billion, which gives us additional financial flexibility. ETE intends to shortly launch a debt financing. The proceeds of that financing and ETE's revolver will cover the cash component to complete the Bakken SXL Exchange transaction. In addition, ETE's Board of Directors has approved a $2 billion ETE common unit buyback program, which is intended to be used opportunistically and will be utilized and sequenced from time to time depending upon the trading price activity and performance of ETE's common units. Now segueing to the Lake Charles LNG, the notices scheduled from FERC that was issued on January 26 has reset the timeframe under which we are working in terms of the Final Investment Decision or FID on the project. FERC has set August 14, 2015 for the release of the Environmental Impact Statement or EIS on the project, and November 12, 2015 as a federal authorization decision deadline, which is 90 days from the date of the EIS. Based on the FERC schedule, the FID for the project has been pushed to 2016. We continue to meet our development milestones and both BG and Energy Transfer remain fully committed to the project and the timetable, as Lake Charles remains one of the lowest cost and most flexible LNG supply options in BG's global portfolio. We've also received EPC bids from each of the various consortia involved in the invitation to bid. We're working through those bids as the pricing in commercial terms. Both BG and Energy Transfer are optimistic, that once that is finalized and the project is sanctioned Lake Charles is likely to be the lowest cost LNG project in the U.S. Transitioning now to the financial results; as a reminder, ETE's cash flow comes from the general partner and IDRs and LP interest at ETP and Regency; currently from 50% of the economics of the GP and – of the IDRs from SXL, through the Class H Units and through our ownership of Lake Charles LNG. Our distributable cash flow as adjusted for the three months ended December 31, 2014 totaled $243 million or $0.45 per unit, an increase of $58 million compared to the fourth quarter of 2013. Distributions from ETP accounted for 54% of ETE’s distributable cash flow in the latest quarter; SXL contributed almost 19%, Lake Charles LNG more than 15%, and Regency 12%. Pro forma, the SXL Bakken Exchange the future contribution from SXL reflected by the distributions on the Class H Units were almost double from these historical levels. For the full year 2014, adjusted DCF climbed by $176 million or approximately 25% to $895 million. ETE’s Board last month declared a ninth consecutive increase in a quarterly distribution to $0.45 per unit or $1.80 per unit on an annualized basis. Our distributable cash flow coverage ratio was one times for the fourth quarter and 1.03 times for the full year. The quarterly cash distribution represent a 30% increase in distribution per unit compared to a year ago. It will be paid today to unitholders of record as of February 6. The increase reflects our continued confidence in the growth prospects for ETE. In closing, before opening the call to your questions, I would like to say that it has been an outstanding year for the Energy Transfer family. We are very proud of our performance and of the value that we have created and returned to our unitholders. Where other U.S. companies in the energy space may see threats from the current uncertainty of commodity prices, we see a once in a lifetime opportunity. With the growth projects we have coming on line this year, we believe we can continue to build value for our unitholders. We had been very deliberate and methodical with our distribution increases over the last two years. Even in the current environment, we believe that we can sustain these current growth levels at ETP, SXL, SUN, and ETE going forward. We appreciate the continued support of our customers and our investors, and we appreciate the hard work of our employees who have helped make this happen. Operator, that concludes our prepared remarks, please open the line for questions.

[Operator Instructions] Our first question is from Abhi Rajendran of Credit Suisse. Please go ahead.

Hi, good morning guys.

Hi, Abhi.

Couple of quick questions. Can you just touch on, you know, obviously you announced a big buyback, could you just touch on how you’re thinking about the base of executing it of the – you know that it'll be opportunistic kind of depending on trading, but is it – are we talking a couple of quarters, a couple of years, just any color there would be helpful?

I think Abhi, right now it’s just going to sit on the shelf. We did it because we continue to think ETE is undervalued. I think we’ll direction from Kelcy, as we look at the trading activity on ETE’s unit processing where we see weakness, and we think that there is the opportunity to in fact retire more units then we’ll capitalize on that opportunity. So it’s open-ended, it’s not that we’re not going to execute it one quarter, I think it’s too big for that, I mean that's just not realistic. But we will be very mindful of sort of taking direction as we sort of see opportunities that we think make sense.

Okay, got it. And then just a quick one on Lake Charles, obviously the comments you guys have made are certainly reassuring. As we look ahead sort of over the next couple of quarters, could you touch a little bit on maybe some of the milestones we should be looking at, whether it's more in the BG side, in terms of them sort of signing up contracts or if it’s EPC process we should be following, just where should we be looking at to track the progress on Lake Charles?

I think a couple of things Abhi, there probably won’t be a lot of – there won’t – a publicity around the whole EPC bid process, it’s a process that will happen in house with BG the various contractors and ourself as we work through their terms and their pricing. Obviously you will continue to monitor BG on their quarterly calls and what they say around their commercial activity, as it relates to the volumes or cargoes. And then for us really until we sort have greater definition and specificity on the EPC side and what the ultimate price is, which then obviously derives what our tariff is. For us that will be then I think the guiding post as to when we decide to launch the financing. So for the next several months, I think, it’s going to be pretty low-key, which it’s just – it is what it is and we've got a lot of work in front of us, a lot of wood to chop, and to get to an FID, which is obviously what we’re focused on.

Okay, got it. And then just one last question from me. With regard to SUN, how you’re thinking about sort of timing and completion of the remaining drops from ETP, and then also eventually the possible GP move up to the ETE level? Thanks a lot.

This is Martin. As we talked about on our prepared remarks, we’re focused on the next 30 to 60 days to complete the second drop, as we also mention we’re targeting the qualified income operations that are embedded within ETP, that’s kind of be our first focus, and then it’s the non-qualified income that will then move. We still think we’re still on track for call it 24 to 30 month process to get all the drop-downs completed. With respect to the exchange of the GP and IDRs of SUN moving up to ETE, again, as we continue to grow the distribution and increase the value of the GP and IDRs through that increase, we’ll look at targeting that exchange, you know it could be late 2015 into 2016, that will depend on the timing and the speed of our drops.

Okay, got it. Thanks a lot.

You bet.

Thank you. The next question is from Brad Olson of TPH. Please go ahead.

Hey, good morning guys.

Hey Brad.

Hey Brad.

A quick follow-up on the buyback announcement equity; am I right to think of this strategically as kind of a plan B in your back pocket, while you look for M&A opportunities or is the announcement of the buyback more of an indication that the bid ask spread remains too wide, at least for the time being in the M&A market where you're looking?

Let me – my view and Kelcy will also chime in here is we divorced this from M&A activity, we don't influence M&A activity. So I suppose what we see in front of us is we see the prospects for ETE given our cash flow growth and then pro forma the Regency deal that is apparent to us that ETE is undervalued even at current price levels, and we wanted to take the opportunity to capitalize on that and we set up the buyback program. As far as on the M&A side, I think we've said look if there is something that makes sense and it’s in our will house and it has the right risk reward balance to it and we think it creates long-term value for our unitholders then we’d certainly look at it. We haven't had that opportunity – we haven't had that opportunity and I'm not sure whether that our bid spreads are still significant between the buyers and sellers, as I think we’re being more focused on making sure that our house is in order during what is being a fairly I would say torrid couple of several months as it relates to commodity prices around this.

That’s helpful color. I guess when I think about the buyback and what you're trying to achieve there, definitely an agreement that equity remains very undervalued, especially in light of all the accretion coming out of a potential Regency merger. When you think about what could correct that valuation discount and you weigh two different options, say a buyback on one hand and on the other hand you know, I guess the market doesn't seem to be discounting the Regency accretion. Do you plan on doing more just in terms of press releases or presentations to provide color around what the synergy number could potentially be from the Regency merger and how that all flows up to Energy Transfer equity at the end of the day? It seems like a much lower cost way of closing that valuation gap than a buyback.

Yeah, Brad, this is Kelcy. That’s a great question. It’s something that you should expect. We are prioritizing however our sensitivity to the human resource emotion part of this deal. We are being very careful even -- and I recognize these our unitholders listening this call and don’t have the same sentiment that we do towards the people, but I think the value will be corrected in time, and at this time, I don’t think it would be the right thing for us to do is to be overly boastful of cost that we’ll be extracting from the organization until we properly have time to analyze that and communicate that correctly, and be respectful of those that maybe involved.

Okay, got it. Thanks for that color Kelcy. Just one follow-up, jumping back to Lake Charles if I may, I realized that you guys have kind of provided contacts that the reason that FID has been pushed back. Here is really just a FERC timing issue. Now understanding that, that some of the nuances of the BG call, maybe lost, as I don’t follow BG, it did sound as though BG’s management was significantly less constructive than you all are being on this call, specifically saying things like, you know there is still a lot of wood to chop both on the off take side and the EPC side, and then an FID was hard to predict what was likely pushed way back into 2016. Is there anything that you guys can do to help me kind of reconcile their messaging with kind of what we’ve heard today on the call?

Brad, sure. We did receive our bid, so we obviously are working through on the EPC side, and that’s going to take us some time, just given the scope and size of the overall project. BG is in transition obviously, they’ve got a new CEO who joined what, three weeks ago. They are themselves going through the transition, having started commissioning out of the Queensland project and obviously what's going on with Brazil and obviously with crude prices around this. I think that continuing their discussions on the volume – with customers on the volume side, but it remains our expectation that we – and in conjunction agreement with them that we are just moving through on the development milestone basis and the earliest we could see an FID would be January and that's what we’d ideally like to see, but there may be some slippage in that and we respect it, but our current intent is to try to get ready so that we are able to take an FID decision and we've obviously got some milestones to go.

Got it. And just one last one, this one is on Rover. In light of the decision to beef that capacity on Vector, is there anything that you’ve seen in terms of right of way acquisition or kind of open houses that you posted in Northern Ohio that makes you nervous about any of the kind of development trends that you're seeing in that part of the country. Obviously you’ve kind of crossed Michigan and Canada off the list, but are there any challenges that remain in Ohio that gives you any [indiscernible]? And that's all for me.

The answer to that is no. We – the FERC process on building a pipeline of this size takes time. We believe we’re probably one of the best and most experienced partnerships in the country to accomplish a project like this. We were having probably more difficulties or more conversations right away north of Vector than we’ve had in other projects in the past. It certainly was behind some of our thinking, what we’re going to do at Vector and also doing what FERC has asked us to do and looked at other alternatives, but by and large the remainder of the right away out of West Virginia, out of Pennsylvania, across Ohio and partly through Michigan, we feel very good about the achievement of this project, own time and under budget or at budget in a minimal.

Thank you. The next question is from John Kiani of Teilinger Capital. Please go ahead.

Good morning.

Good morning, John.

Hey, John.

Jamie, you talked a little bit about the M&A market, I'm assuming you were talking perhaps a little bit more from a corporate perspective, but what about producers that have midstream assets that perhaps need to raise capital, do you think that there might be some opportunities for you all there?

Short answer is sure. I mean we’re still seeing activity, we saw the Coronado announcement last week or so. So we continue to think that there will be folks that will look to try to monetize assets, and in fact if you can think of a differential between trading multiple for an upstream producer and what they could possibly get for their midstream assets if they have the right contracts in place, it’s probably a pretty nice arbitrage and much more effective than writing debt or equity and obviously the current environment. So I think you probably hit on to a virtual patch, that I'm sure every banker on Wall Street is going to be focused on and we’ll look at those opportunities as they come and as I said it, if they seem to fit what we’re looking for and what ideally suits us then that will make it quite attractive.

Got it. And then on the Regency transaction, I certainly appreciate the comments Kelcy that you made and you’ve made as well Jamie about just the sensitivity around the human resource part of that transaction. Are you able to just give us a little bit of clarity or understanding around post-transaction close, how long it will take for us and for the market to see the benefits of the transaction in the form of the ETE distribution?

This is Kelcy. We’ve established – I’ll do the best I can to answer that. We’ve established an immigration committee; it consists of two parties from two people, from Regency and two from Energy Transfer Partners. They reported up to Mackie and then ultimately to me. They are going through announces right now and there will be certainly cost reductions experienced in 2015, and we believe substantial reductions experienced in 2015. Mackie and his team have already identified a lot of commercial, these the ones that are the most fun because these are the ones where are you combine hydraulics, you reduce compression, you improve recoveries, you reduce fuel, those are the ones that are firm on the cost side they don't involve reduction of a job. And we’re finding more of those actually than we anticipated. So we’re going to see a quite a lot of efficiencies derived in 2015, however I don't think the unitholders on this call are going to see your full bank for your buck until 2016.

I think John, the last point, your question on the ETE distribution, I think it is such a long way to go between now and closing. We’ll look at it; Kelcy and I will sit down, we’ll talk about it, we’ll work out what makes sense, we know that there is accretion in there, we don’t know what else will be occupying our time and focus and attention at that point. So I think it’s premature to think about how we would think about any increase in distribution of ETE as a result of incremental cash flow from the Regency transaction.

Got it. And just one last question please, the Waha to Presidio header system and the pipeline through to Mexico. Have you all talked about the timing and your ownership interest in that projects or can you please?

Certainly we can talk about the timing, in fact as we sit here and listen to conversations how exciting it is from ETP’s perspective on all these projects from Bakken, from Marcellus and Utica, and we’re very excited about our business South to Mexico. We began flowing here recently, the first project in South Texas being next two projects that we will work on, we expect the FERC to come on, or really both of them to come on in the first quarter of 2017, and we are finalizing the negotiations and everything is on track to that timeline.

And is there any residual, how do we think about any residual volume benefit in the Intrastate System from this and Nueces Crossover and the other pipeline projects you have going into Mexico?

That’s probably, even more exciting part of those projects and that probably most of you all know, we’ve built out a pretty hefty Intrastate system of which a lot of capacity has been available over the last two or three years because of decline in different areas and this is going to really help us fully utilize that, albeit in a different hydraulic direction, but we see significant upstream benefits for transporting by probably mid to late 2017, an additional 3 plus Bcf through our Intrastate System to complete these projects.

Got it. Thank you very much.

Thanks John.

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

Hi, good morning guys.

Hey, Schneur.

Most of my questions have been asked and answered, but just kind of wanted to come back to, I guess, the buyback for a second here and sort of think about it in a different context. Early last year there was some discussion about creating somewhat of an up sea structure. Assuming everything closes RGP’s currency that disappears at this point. Is there any thought to renewing the interest in the up sea structure? Could the buyback of the units be held in treasury and support the evolution towards an up sea structure? Just wondering if you can sort of talk about that a little bit?

As far as the buyback is concerned could we use it for alternative the units that we retired for alternative uses? Absolutely. The up sea was a structure that we, I want to say, analyze is probably the best word. Last year spent a lot of time thinking about it. And we should have shelved for various sundry reasons, so I think look – could that be somewhere in the crystal ball. The boss needs to tell us what he wants to do at any particular point in time. So, I think but right now it is not on our immediate game plan.

Yeah, but however I would say that I think it hoops us. There will be opportunities that will come our way, that we will most certainly need to find a way to integrate a sea corporation in our partnership structure. As you guys know we have done this time and time again, but it creates complexity and it is always a challenge from a tax perspective. Having a sea corp currency that resides within the family is a smart thing for us to do. So I think you will see something coming out of us this year.

Just a follow-up question and I have realized in your responses to some of the other questions that it is hard to sort of calculate the benefits for Regency at this point right now and you kind of want to close the transaction first and so forth. But when we think longer term about ETP's, I guess, distribution CAGR over the next, let's say, three years is it fair to conclude that that CAGR has probably gone up by couple 100 basis points kind of as a result of putting the two entities together?

Schneur, this is Martin. I think it is a combination of a lot of things. We spent the last five years riding the ship. Back in 2013 we resumed distribution rate growth. We did it methodically given that we are trading back into the water. I think when you see not only the ETP Regency merger and Kelcy talked about the commercial synergies that we see from that and a lot of the benefit of combining these assets. When you tack-on what we built on Lone Star, you tack-on the Eagle Ford, the Permian, you tack-on Bakken and Rover that gives us significant amount of confidence that our distribution rate growth will continue given these assets come online, you sprinkle that with M&A and that are substantially fee baked in nature that we get that benefit. And then by the way we've got a retail platform that just get in our ballpark right now. All that combined gives us the confidence of continuing our distribution rate growth.

And one final question with the – I guess, there was an amendment towards Regency and ETP merger agreement. Does it sort of shifted to all stock now so therefore you just require a Regency vote or do you need both Regency and ETP vote on a go-forward basis?

So, Schneur, there were two things with the amendment; one was the modification in the structure to what's called a forward subsidiary merger, a triangular merger that's what I call it. But it allowed Regency to be a subsidiary of ETP and it gave us more flexibility as we thought about. The debt covenants going forward, the flexibility within ETP without we recognize and understand the debt of Regency will continue – will be guaranteed by ETP, we will have the investment grade rating much like ETP but it gave us more flexibility. As a result of transaction structure we now no longer need an ETP unitholder vote so the only vote we need is for Regency and of the Regency unit it is a simple majority and almost 25% of the units are held by ETP and ETE and we under the merger agreement have agreed to vote in favor of the transaction. That's one aspect, the second aspect was we converted the $0.32 was about $133 million based on about 410 million units for Regency outstanding. We convert that from cash to units, those ETP units. Those ETP units will be priced as of prior to closing, but it now meant that there was no cash in the transaction, there is an all unit transaction.

Great. Thank you very much for the clarification and good luck, guys.

Thanks, Schneur.

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

How are you doing guys? Two quick questions; number one, what are your thoughts with the recent volatility in crude around the retail marketing profits that we may experience in Q1? And second of all, what is the total debt number at the end of the fourth quarter? Thank you.

Hey, Ross, this is Martin. I'll answer the second question first. Our total debt on a consolidated basis was $19.3 billion. That includes not only ETP debt, but also SXL and Sunoco LP. With respect to the first question, unfortunately Bob has to – his Sunoco call, but I'd say that we started off strong with respect to retail margins. Obviously, we've seen a little bit of volatility over the last several weeks. We have a very diversified business now when you combine the Sunoco legacy system with the previously known Susser system and operations is around the south. So, we expect another strong quarter coming up for retail business. And Bob and his team has done a great job managing the operations as we continue to see volatility in the space.

Great. Thanks so much, Martin.

You bet.

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

Thank you. Good morning. So, Jamie, you made earlier comments about your expectation of this weak price environment, for long time and that you see this little bunch in a life time opportunity. I mean, one could argue that energy transfer as a family is probably set – has a most flexible structure to buy any type of Midstream assets. And if we see it once in a type – once in a lifetime opportunity, then this will probably be a good time for you to do deals. But my question is should we expect you to use the individual – the LPs being used as the acquisition currency or first right deal maybe you would consider something at the ETE level but then if you don't – you end up not doing enough. Is there something else you could do at the ETE level like getting an IRS ruling on being able to issue more ETE units to make that possible? Could you maybe share some thoughts around that?

Thanks, Helen. Wow, there is a lot in that question. As far as structure of deals, we have done deals down at the LPs, you know, Sunoco was done with ETT, Southern Union was done at ETE, Susser was done at ETP. So we are pretty flexible. We will go where we think this make sense from a compatibility, from a strategic standpoint and where we've got the – what we think is we are offering the right overall consideration for the seller and they are happy to take that consideration. So I think we are flexible where we would go. I think you've certainly heard from us before that only I would say in certain circumstances and they are very limited there would be willingness for us to do something at ETE. We recognize that that may some point come about and we do not take that off the table, but it is also a currency that is extremely highly valued given Kelcy's ownership and given how we think about the overall value proposition. So I think you've got flexibility on one side, on the second side we certainly would roll it out. Is there something else we can do? You asked about the IRS ruling, we have been working on that. So I think we will – you'll probably see something over the course of the next 6 to 9 months that you'll have some statement in one of our public filings that indicate that we have navigated through that channel.

That's very helpful. Thank you. And then just some quick follow-ups on the Rover project with the Vector deal what's the updated CapEx, total CapEx and the EBITDA expectation?

This is Mackie. The overall CapEx right now has been reduced in the range of about 3.6 to 3.8 kind of range low to high 5s. I don't believe we've disclosed any EBITDA or any revenue numbers that come out of that project.

Okay. So out of that 3.6 to 3.8 you guys would be putting in 65%. And I think in the past you considered doing some project finance and I guess that's off the table this will be all coming out of the Energy Transfer?

Helen, this is Martin. So, in terms of project level financing that still remains in place. Our intention is to project finance at the Rover level for various reasons. But that will be something that we'll do and we'll look at an optimal structure so that we put the right amount of debt in there and then the equity portion will obviously come from our 55% ownership and then AE–Midco is 35% share.

Great. And then one last one, on the Bakken project you talked about potentially increasing the capacity to 570,000 and in your own discussion with some shippers what should we expect in terms of timing and how does – is there bit of more sort of CapEx needed to bring it up to 570,000 and what would be the return. Any changes in return if you were to bring it up to that level?

Helen, this is Mackie again. As I mentioned earlier, all the projects we have is certainly one of the most exciting projects and the R&D of the collapse in oil prices actually has been a significant benefit to that project, primarily because to the pipelines that were proposed kind of go in east or really having trouble getting their project off the ground and one other large pipeline project that was in the work for some period of time has been abandoned. So, we couldn't be more excited about this project and about fully selling the max capacity of up to 570,000 a day. We do have ongoing negotiations with several different producers, shippers that are in the net capacity and we are confident that once we bring that on in 2016 that we will be at that 570,000 barrels a day level. The incremental capital is insignificant when related to the additional revenues involved with adding that additional 120,000 barrels a day.

Okay. That's very helpful. Thanks.

Thanks, Helen.

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

Thanks. Just one quick question from me. As related to the buyback can you just remind us or talk about where are you comfortable or what are the outer limits leverage at ETE and should we think of that as a gating factor on the buyback program?

Michael, it is a very good question and the short answer is absolutely. You know we've been very open, transparent and communicative with the rating agencies and we've always said S&P and Moody's we look at sort of four times, no more than four times debt-to-EBITDA on a standalone basis at the ETE level. So will always be a constraint. We, obviously, recognize and I think most of the analysts did as well that there was a big jump in cash flows from '14 to '15 they will roll up in subsidies and various other things that most people were factoring in. And then obviously you have the increasing cash flow from Regency. So it is certainly – you should be very mindful of it because we are and we have committed the agencies that we won't basically breach that threshold and we will – will have to live within those guidepost to give this plenty of flexibility.

Thank you. The next question is from Brian Lasky of Morgan Stanley. Please go ahead.

Good morning. Follow-up for Jamie, in terms of the Lake Charles just with the EPC arrangement – your arrangement with the BG is financing. Is there anything from a timing perspective that has kind of an end date to it? Is there any kind of expiration or anything that we need to worry about if the project should get pushed behind kind of beginning of 2016?

Well, typically on the EPC arrangement just like any of our projects that we undertake or anybody undertakes we have large capital projects where you undertake on a turnkey basis meaning you are shifting the risk, if you will, over the EPC contractor. They normally put a specific date of which the price that they are proposing is good before in fact they get a reopener, and that’s supplied certainly across the board the other LNG projects that had been done in the U.S. Right now we’re working through it. I mean you can always just work through these things and obviously the deflationary environment around this, both on capital and resources and human resources meaning is probably working to our advantage. The deferment and delay of a lot of other large capital projects is probably going to work to our advantage, so there is nothing out there that is concerning or troubling from our standpoint as far as working to what is now an extended schedule.

Got it. That makes sense. And then sort of from an financing perspective and then an agreement with BG perspective, that’s obviously there is no timing contingencies there, correct?

Correct.

Then in terms of following up on Helen's question, do you think the appetite or the willingness of ETP to engage in M&A has changed post the RGP, how would you characterize that?

Do you want to take that Kel?

Yeah. Our appetite is strong, very strong. We are looking at a lot of things, we’re studying this very carefully, for people on this call, this is going to sound odd to you, almost sadistic, but I was disappointed to see a rebound in crude prices that I believe is temporary. I was excited to see who might be more vulnerable if we saw this market continue a downward trend and stay there a little bit longer, I know that sounds odd, but this will when wealth is created – during these times, I do think that will occur. And we are carefully a lot of different scenarios, there are varying partnerships that exist out there that are well-run, great assets, but let’s face it, commodity price downturns are more impactful to those particular assets maybe than they are to the family of Energy Transfer. We fully intend to capitalize on that, I think it’s a little early. However we’re not seeing any bargains right now, but we do think they’re coming. And we remain open-minded to use the ETE currency, but it’s going to need to be a pretty special deal for us to do that.

But you’re still kind of comfortable using the ETP currency, you don’t think kind of the circumstances that could have changed there meaningfully from a M&A appetite perspective since doing the RGP deal?

No, no, no. I don’t think so at all. Mackie is constantly, I promise he’s got 10 opportunities in his mind right now, when one plus one equals more than two, guaranteed and it’s all commercial driven, all hydraulic, all fuel, all coverage, all efficiencies, they are there. And we have – the family has proven that there is a growth opportunity for peak we will execute upon on that and if there are IDR subsidies required to make that deal happen we will do that. So cost of capital is not an issue for ETP, and it will continue to grow and M&A is very much part of that growth – that approach.

Perfect. Thanks Kelcy. And then just one last question, Jamie, how do you kind of think about the buyback relative to potentially increasing your distribution whether it be a step up or a trajectory change over time there, and where do you kind of see yourself getting the most bang for the buck at these kind of levels, absent kind of M&A entering the picture, how do you think about that?

Brian, we look at the return on capital in two respects, I suppose buying back units if you asked Kelcy or myself today would be without a doubt the most compelling use of our liquidity and capital. There would be not a shadow of a doubt. We are being very I think systematic in how we thought about our distributions, we’ll continue to be systematic about that and we will – I think we’re not going to have one at the expense of the other, I think the two could work in tandem, but this is going to be a conversation that is -- that will be played out to be candid over the next four, six plus months, we’ve got to close the transaction. First we got to see how what happens around us, we got to see the environment in which we are, we got to see how ETP, ETE’s unit price is performing. There are so many uncertainties, but it’s nice to know that we've got, I think a pretty attractive situation unit that we are – we will be able to capitalize on.

I agree. Perfect, thank you very much guys.

Thank you.

Thank you. We have no further questions at this time. I would like to turn the floor back over to Mr. Salinas for any closing remarks.

Great. Again, thank you this morning for your time and attention. And everybody have a great day.

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.