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 for key ETP direct segments. Adjusted EBITDA on a consolidated ETP basis pre-merger totaled $1.15 billion, which is down $57 million, compared to the first quarter of 2014. However, please recall that first quarter 2014 benefited significantly from the Polar Vortex that was hardly if it all present in first quarter 2015 and from the sale of our AmeriGas unit ownership stake and the sales of ProLiance that occurred in 2014. Distributable cash flow attributable to ETP partners as adjusted totaled $692 million, a decrease of $52 million from a year ago on a ETP standalone basis, but above street consensus. Pro forma with the Regency merger combined adjusted EBITDA was $1.37 billion, compared to $1.34 billion for quarter one 2014. Pro forma DCF was $857 million in the latest quarter versus $844 million a year ago. Now let's go over the individual segment results. In the Midstream segment, higher volumes offset commodity price declines. I'm sure that probably surprises some people. Adjusted EBITDA on a standalone basis increased by $27 million, compared to the same period a year ago, primarily driven by an increase in fee-based revenues on assets recently placed in service in the Eagle Ford Shale and Permian Basin, and to a change in contract terms on our Southeast Texas system to fee-based from non-fee based. We also experienced lower SG&A expense in the Midstream segment due to a reduction in employee costs. Pro forma for the Regency merger adjusted EBITDA from Midstream grew by $82 million to $319 million. Gathered gas volumes on the ETP systems totaled almost 3.7 million MMBtu per day, which is up about 1.1 million MMBtu per day versus the same period last year. NGLs produced and equity NGLs continue to increase last quarter. ETP standalone production was up about 66,000 barrels per day, compared to the first quarter 2014 and pro forma for Regency, NGLs produced were up nearly 132,000 barrels a day. In the Liquids Transportation and Services segment, adjusted EBITDA increased by $38 million, compared to the same period last year, which was a nice beat versus street estimates. NGL transportation volumes on our wholly-owned and joint venture pipelines increased from a year ago by more than 131,000 barrels a day. Three quarters of that was due to an increase in NGL production from our Jackson processing plant and volumes transported to our Mont Belvieu facilities via our Justice pipeline. The remainder was from volumes transported out of West Texas on our Lone Star pipeline system as producers ramped up production. Transportation volumes totaled 438,646 barrels a day in the last quarter. Average daily fractionated volumes increased more than 69,000 barrels a day from a year ago to 226,041 due to the ramp-up of our second 100,000 barrel a day fractionator at Mont Belvieu, which was commissioned in late 2013. All-in-all, we realized significant revenue increases for transportation and processing and fractionation. In our Interstate segment we are delighted to report that adjusted EBITDA comparisons were very positive and exceeded street expectations based on high margins. We expect high margins to continue as we see the level of natural gas demand continue to drove supply for the Gulf Coast and as Mexico increases its significant volume growth plans from the U.S. Intrastate volumes were allow from a year ago due to lower production from shippers in the Barnett Shale. However, we continue to see tremendous opportunity to capture meaningful transportation volumes for Gulf Coast LNG projects to Mexico and to petrochemical markets along the Gulf Coast. In our Interstate segment transported volumes decreased by about 192,400 MMBtu per day, due to warmer weather along the Panhandle pipeline and along the Sea Robin pipeline as a result of a customer maintenance-related outage. Adjusted EBITDA for the Intrastate segment decreased about $23 million from a year ago, resulting from the lower level of new Bakken loan activity given the extreme backwarded curve that occurred during the unusually cold weather in quarter one 2014. SXL had another solid quarter in a challenging market environment with a $13 million increase in adjusted EBITDA compared with last year's first quarter. This mainly reflects expanded crude oil marketing margins and higher crude and products pipeline throughput volumes, partly offset by lower terminalling results. The Retail Marketing and Fuel Distribution segment contributed $129 million of adjusted EBITDA for the first quarter, which includes approximately $44 million from Sunoco L.P. and $85 million from the remaining Retail Marketing and Fuel Distribution assets we plan to dropdown to Sunoco L.P. over the next 24 months. The latest dropdown we announced last month included just under one-third of our legacy Wholesale Fuel Distribution business. This is entirely qualifying income. Merchandise sales more than tripled and fuel volume sold grew by 35% as compared with last year's first quarter. This is in large part due to the Susser acquisition at the end of August along with the Aloha and [Tigermarket] [ph] acquisitions. However, the prior year benefited significantly from market dynamics connected to weather and other products supply opportunities, which offset some of the improvement from acquisitions in the year-over-year comparison. Typically quarter one is the slowest quarter for Retail and while we believe this dynamic continued in 2015, the Retail segment did delivered solid results and exceeded its internal budget. From an operational perspective, we delivered same-store Retail fuel growth in our Pad 1 region and while our strikes sites in Texas and surrounding regions were impacted by demand declines in the Permian Basin and surrounding areas. Our continued strong growth in Houston and I-35 Corridor largely offset it on a same-store basis. We also delivered strong growth in same-store merchandise sales in all markets except for the impact of tobacco in Virginia markets where demand is most affected by tax regulation. The $170 million drop in EBITDA versus a year ago in the all other segment was mainly due to the disposition of our investment in AmeriGas and the sale of ProLiance in April 2014 that I mentioned earlier. And a $21 million lower contribution from our investment in PES, which is filed to go public. These three items drove most of the decline in adjusted EBITDA from first quarter 2014 to the first quarter of 2015. Interestingly, if you added back the prior EBITDA contribution from AmeriGas and ProLiance, our total adjusted EBITDA for 1Q 2015 would have actually exceeded adjusted EBITDA for the first quarter 2014. On transactions and dropdowns we had a couple of significant transactions with our affiliated partnerships that concluded in the last 60 days. In March, we completed the previously announced Bakken-SXL transaction with ETE. As part of that transaction, ETE transferred 30.8 million ETP common units, ETE's 45% interest in the Bakken pipeline project and $879 million in cash to ETP in exchange for 30.8 million newly issued Class H units issued by ETP. When combined with the existing 50.2 million class H units, ETE is entitled to now receive 90% of the economics of the GP/IDRs of SXL. In connection with this transaction, ETP also issued 100 class I units, which pay distributions in order to reduce the IDR subsidies from ETE to ETP by $55 million in 2015 and $30 million in 2016. In April, we concluded our second drop-down of assets from our retail marketing segment to Sunoco L.P. ETP contributed a 31.58% interest in Sunoco, LLC, which is a wholesale fuel distribution business. Sunoco L.P. paid $775 million in cash and issued 795,482 new SUN units valued at $41 million to ETP in exchange. We intend to drop all of the remaining wholesale distribution and retail marketing assets of Sunoco, Inc. to SUN over the next 24 months. Yesterday, we announced the transferred SXL of 30% interest in the Bakken project effective as of April 1st. As a result of this transfer, ETP now holds a 45% remaining stake and Phillips 66 owns 25%. We will give you a more detailed Bakken update shortly. Now before we update you on existing growth projects, we have a couple of new ones to share with you. The Revolution project, we are working on this significant new project. We expect to be making an announcement about this new project located in the Marcellus in the very near future. The project will not only serve the gathering and processing growth vehicle for ETP in the Northeast, but also bring gas volumes to our Rover pipeline and liquid products to SXL’s Mariner East project. So stay tuned. On Monday, we were excited to announce a fourth NGL fractionator at Mont Belvieu, Frac III and IV are currently under construction. And they will provide offtake for the new Lone Star Express pipeline that I'll update you on in a moment. Frac III is a 100,000 barrel a day facility that we expect to place in service this coming January. Frac IV will have a capacity of 120,000 barrels per day and it is expected to come online in the fourth quarter of next year. These two projects will bring our total fractionation capacity to 440,000 barrels per day at Mont Belvieu. Both fractionators are fully subscribed by long-term fee-based contracts. We will continue to evaluate further fractionation expansion opportunities, both at Mont Belvieu and elsewhere. Now turning to a couple of relatively new growth projects that we have mentioned before in passing. First of all, there is a Bayou Bridge project that we are pursuing with Phillips 66. Bayou Bridge will directly link Nederland to refining markets in Lake Charles and St. James, Louisiana. We are pleased with the results of the open season and are optimistic about moving forward on the project and hope to make an announcement in the in the near future. As we stated on our last call, we view this project as a natural fit with the Bakken project which we will talk about shortly. We are continuing to expand our interstate pipeline capacity to carry gas from the Permian basin into Mexico with a pair projects Trans-Pecos and Comanche Trail that will pick up supplies from multiple interstate and intrastate pipeline at the Waha Hub, including ETP’s vast inter and intrastate pipeline network and deliver the natural gas to the board. ETP will be an owner and manage construction and operate the header in both pipelines. We expect both of these to be in service in the first quarter of 2017. The Trans-Pecos pipeline includes 143 miles of 42 inch intrastate natural gas pipeline and a header system. It will interconnect with Mexico's Ojinaga pipeline at the border near Presidio and will provide nearly 1.4 Bcf per day of pipeline capacity with a 6 Bcf a day header system. It is expected to cost about $700 million. The Comanche Trail pipeline will include 195 miles of 42-inch intrastate natural gas pipeline from the Waha Header to the border just south of El Paso and connect with the San Isidro pipeline. It will provide at least 1.135 Bcf per day of capacity and is projected to cost about $600 million. We are excited not only to be a part of these two significant projects but also to be a large player in delivering gas volumes throughout pipeline network to the 6 Bcf per day Waha Hub for ultimate delivery to Mexico and other potential markets along the board. At the end of March, we closed on the King Ranch project acquisition from Exxon Mobil for total purchase price of $370 million. This acquisition includes a 750 million cubic feet a day gas processing plant of 42,000 barrel per day NGL fractionator, an 8-inch NGL pipeline that delivers products to Corpus Christi and the ETC KR pipeline, which consists of 165 miles of 16 to 24-inch mainline and gathering pipelines. This project gathered gas from ETP’s Eagle Ford system, the Conoco Lobo system and the ETC KR pipeline. Residue gas is delivered to our HPL system, to the Agua Dulce Hub and the NGL’s are transported to end users including DOE and the ASO and Refiners in Corpus Christi. This gives us the opportunity to transport additional Eagle Ford volumes through our existing system as well as Vicksburgvolumes and from other areas of South Texas. This acquisition also provide a platform for adding new processing and fractionation facilities as needed in South Texas. Moving out to existing growth projects that have just gone into commercial service but will do so before year-end, starting with the Lone Star NGL projects, which are now 100% owned by ETP, following the merger with Regency. I’ll start with the quick progress update on Mariner South, which is a partnership with SXL. Mariner South integrates SXL’s existing Nederland Marine terminal and pipeline from Mont Belvieu to Nederland and ETP's Mont Belvieu fractionation and storage facilities. As we reported last quarter, this LPG export-import facility started operating in January and we are now capable of loading the full capacity of the facility. Moving next to the Eagle Ford and Eaglebine rich gas production areas where two new 200 million cubic feet per day cryogenic gas processing plant projects are underway. The REM II product plant is scheduled to go in service in July and we have moved up the in-service date on both the 24-inch volunteer pipeline and East Texas plant from January of next year to the fourth quarter this year. These two plants will expand our Eagle Ford and Eaglebine processing capacity from about 1.4 Bcf per day currently to about 1.8 Bcf per day. Rover pipeline, we are on track and on budget for the 3.25 Bcf a day Rover gas pipeline project. We have purchased all the major materials and we are on schedule and on budget with our right-of-way acquisition and in the process of finalizing various agreements and construction contracts. Pending regulatory approval, Rover still expected to be in service from the Marcellus and Utica 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. We expect to receive the drop in environment impact statement from the FERC by June. We are on 65% of the Rover pipeline in partnership with AE-Midco and we’ll manage construction and operate the pipeline. Bakken pipeline. We are also continuing to advance the Bakken pipeline project. Our project team is currently focused on permitting and right-of-way acquisition in anticipation of construction later this year and through 2016 subject to the timing of permits and regulatory approvals. We are seeing good progress in our permitting and regulatory proceedings. And so we continue to plan for an in-service date by the end of 2016. Commercially, based on shipper commitment that we have contractually secured today, our project scope now provides for aggregate takeaway capacity out of North Dakota of approximately 470,000 barrels per day. That takes us closer to our ultimate target of 570,000 barrels per day. We remain in active discussions with multiple parties about additional shipping commitments. So we are optimistic about the prospects to continuing to build upon our current commitments and to achieve 570,000 barrels per day levels. The Lone Star Express NGL pipeline and conversion project is now under construction. ETP will build 533 miles of 24 and 30-inch natural gas liquids pipeline from the Permian basin to Mont Belvieu and also convert Lone Star’s existing West Texas 12-inch NGL pipeline into a crude oil/condensate line. 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. CapEx update, ETP invested about $1.2 billion during the first quarter in growth CapEx projects with a majority allocated to our liquids transportation services, midstream and intrastate segments. When you include our indirect growth capital expenditures at SXL and Sunoco L.P., quarter one consolidated growth CapEx was more than $1.6 billion. With the ETP and Regency merger now complete and with some additional growth projects, we are now forecasting full year 2015 CapEx for ETP in a range of $5.6 billion to $6 billion. With SXL taking a 30% interest in the Bakken pipeline project, that removes approximately $500 million of CapEx from ETP’s 2015 growth CapEx budget. As a result, the SXL’s CapEx has increased to a range of $2.4 billion to $2.6 billion. Before moving on to discussing our distribution and Regency's results, let's take a quick look at ETP’s liquidity position. We were very active in quarter one. On a GAAP basis, we ended the quarter with a standalone debt-to-EBITDA ratio of 4.25 times and approximately 4.75 times pro forma for the Regency merger before synergies. Under our credit facility, the ratios were 4.05 times on a stand-alone basis and 4.62 times on a pro forma Regency merger basis. We issued a total of $2.5 billion of new senior notes in early March and three tranches, with interest rates ranging from 4.05% to 5.15% and maturities ranging from 2025 to 2045. This enabled us to reap our outstanding amounts on our revolving credit facility. We then increased the capacity on our revolver by $1.25 billion to $3.75 billion in total. As of March 31, we had no outstanding borrowings on that facility. We also raised approximately $135 million of equity during the first quarter, under both our ATM and DRIP programs. In addition to these financings, the drop-down of almost 31% interest in our wholesale fuel business to Sunoco LP gave us cash of $775 million in April and the Bakken SXL transaction with ETE gave us net cash proceeds of $817.3 million. These financings and transactions with our affiliate partnerships gave us ample liquidity to support the growth initiatives of ETP now that the Regency merger is closed. We have no plans at present to do any overnight equity offerings in the foreseeable future and we have no other debt maturing this year. Now, I will turn it over to Tom, who will give you an overview on Regency's results for the first quarter and provide a brief update on legacy Regency growth projects.

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 work done by that committee and the many men and women at both ETP and Regency, we are today in a position to share with you formally our expected cost savings from the merger and our organizational streamlining. Our initial estimate for annual recurring synergies is a range of $160 million to $225 million per year, but that includes only cost reduction, the personnel balance sheet management and non-personnel costs. Most of these cost savings will be realized in our results before the end of 2015. The cost savings estimate excludes severance and transition costs, most of which will roll off by the end of this year. This range does not include any commercial synergies from the combination of the two platforms. These are more difficult to quantify with an exact dollar amount. We are, however, very confident that the operational benefits we expect to be realized from the merger will be a material net-net positive and we expect that to be reflected in topline growth and new opportunities in the future. To put all of this in perspective, the synergy range based on our quarter one distribution would comfortably bring us to a strong 1.10 times pro forma coverage ratio. We remain confident in our unique diversified platform and our cost funding ability to continue to grow our distributions and distributable cash flow in the very deliberate and methodical manner that we have employed over the last two years. So now switching over to ETE. I should point out that the merger of Energy Transfer Partners and Regency results in a material increase in distributable cash flows to Energy Transfer Equity, as can be seen in our first quarter results. With the closing of the SXL Bakken exchange transaction, the DCF contribution to ETE from SXL reflected by the distributions on the Class H Units has almost doubled. Overall, we increased our distribution to $0.49 per unit, a 14% increase from our prior distribution growth trajectory. Let’s now look at liquidity and financing. ETE substantially increased its liquidity in the first quarter. In February and March, we borrowed $850 million under our senior secured Term Loan C agreement to fund the cash component of the SXL Bakken exchange transaction at an all-in rate of approximately 4%. You'll remember also in February, we amended ETE's revolving credit facility to increase the capacity to $1.5 billion, which gives us additional financial flexibility. Therefore, at the end of quarter one 2015, the overall ETE standalone debt was $5.5 billion with the blended interest rate of 4.6% and no pending maturities until almost 2019. With a strong distribution coverage of 1.21 times that we opted to maintain for quarter one, this now allows us to focus on the debt side of our balance sheet by looking to extend our maturity runway and various other initiatives that we believe will continue to drive value creation for ETE holders. For example, we might consider accelerating the Sunoco LP, GP, IDR exchange with ETP. That should be very attractive to ETP, allowing it to continue to manage its overall unit count and its ideal obligation while being highly beneficial to ETE in the longer term. Additional cash on hand and balance sheet strength also allows us to commence as we see appropriate our $2 billion unit buyback program that the Board approved in February. We will of course be opportunistic in our purchases depending on price and trading performance of ETE common units. Clearly, we are well-positioned for even stronger distribution growth going forward, and we have a lot of optionality in where and how we drive value for our unitholders. On the Lake Charles side there were couple of material developments in April regarding our Lake Charles LNG project, which to remind people is owned 60% by ETE and 40% by ETP. On April 10th, the draft Environmental Impact Statement for Lake Charles LNG and the expansion of the Trunkline interstate pipeline was issued by the FERC. ETE/ETP and BG were pleased with the FERC’s findings and recommendations. It moves the Lake Charles LNG project one step closer towards our goal of achieving FID in 2016. On April 7th, BG Group and Shell announced a proposed takeover of BG by Shell. We understand that merger is expected to close in early 2016. In the interim, BG and Energy Transfer remain focused on completing the development milestones for the project as we move towards FID. Like the broader investment community, we see the BG Shell merger as a material net positive for our Lake Charles LNG project. In particular with the unique structure of our project and the fact that we continue to believe that Lake Charles is likely to be the lowest cost LNG project in the U.S., Lake Charles LNG seems highly compatible with Shell stated LNG project objectives. Turning now to the financial results, as a reminder ETE’s cash flow now comes from the general partner and IDRs MLP interest at ETP, which now includes Regency, not extending the economics to the GP and IDRs domestic sales through the Class H units and through our ownership of Lake Charles LNG. Our distributable cash flow as adjusted for the first quarter totaled $321 million or $0.59 per unit, an increase of $122 million compared to the first quarter 2014. Distributions from ETP and Regency combined accounted for 74% of ETE’s total cash flow this quarter, SXL contributed 14% and Lake Charles approximately 12%. ETE’s Board last month declared a 10th consecutive increase in our quarterly distribution as I mentioned earlier to $0.49 per unit or $1.96 on an annualized basis. Our distributable cash flow coverage ratio as I also mentioned was 1.21 times for the first quarter. The quarterly cash distribution represents a 37% increase in distribution per unit compared to a year ago. It will be paid on May 19th to unitholders of record as of the close of business tomorrow. Before we conclude, I would like to provide some clarification on the recent NOPA from the IRS on which we have received a number of questions over the last few days. On Tuesday, the IRS released the comment proposed regulations governing the definition of qualifying income under 7704 of the code, which is the key determinant for MLP treatment. We are pleased by the clarity of the proposed regulations. Based on our review, we believe there is no impact from these regulations on any member of the Energy Transfer family. In particular, any concerns about Sunoco LP are misplaced. Our current end user sales are in our corporate subsidiaries that is PropCo at Sunoco LP and under ETP Holdco in ETP. So that taxed the C Corporations with dividends from those C Corps being treated as qualifying income when received by MLPs. All wholesale and bulk sales are in fact confirmed as being qualified income under the NOPA. We hope that now clears up any questions. So before opening the call to your questions, I would like to say that some incredibly exciting things are happening across the Energy Transfer family that we believe will build strong value for our unitholders. We are extremely proud of our performance. Where distribution growth has been flat or sluggish at many other MLPs this quarter, we have continued our increases and we expect to be able to maintain our increases through this touch cycle. The benefits of our diversified business model are clearly starting to shine through. Our overall growth capital is without peer today and sets up ETP for another period of transformation by the end of next year. We have demonstrated that we can grow and thrive in the current commodity price environment, and from this challenge we are realizing opportunities and capitalizing on them. We appreciate the continued support of our customers and our investors, and we appreciate the hard work of our employees who have helped us to make this happen. Operator, that concludes our prepared remarks. Please open the line for questions.

[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.