Energy Transfer LP (ET) 2015 Q1 法說會逐字稿

Greetings, and welcome to the Energy Transfer Partners first-quarter earnings call.

(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 McCrae, John McReynolds, and other members of our Senior Management team who are here to help answer your questions after our prepared remarks. We are going to change things up for the call this morning, with me sitting in the anchor's chair, Tom will assume that role from next quarter on.

We had an extremely busy quarter in quarter one, and we have even more than usual to talk about this morning. I will 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 will then invite Tom to provide a brief summary on Regency's quarter one performance. We will finish with a discussion on our distribution, an 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 will also return refer to adjusted EBITDA and distributable cash flow or DCF, both of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website.

Let me start with quarter one results. I will discuss both 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 our 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 at all present in first quarter 2015, and from the sale of our AmeriGas unit ownership stake, and the sale 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 am 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 [$318] 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 continued to increase last quarter. ETP standalone production was up about 66,000 barrels per day, compared to the first quarter of 2014, and pro forma for Regency, NGLs produced were up nearly 132,000 barrels a day.

In the liquid 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 are now wholly-owned, and joint venture pipelines increased from a year ago by more than 131,000 barrels per 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 to 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 higher margins. We expect higher margins to continue, as we see the level of natural gas demand continue to draw supply to the Gulf Coast, and as Mexico increases its significant volume growth plans from the US. Interstate volumes were lower 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 in 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 interstate segment decreased about $23 million from a year ago, resulting from the lower level of new park and loan activity, given the extreme backwardated curve that occurred during the unusually cold winter 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 end products pipeline throughput volumes, partly offset by the 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 LP, and $85 million from the remaining retail marketing and fuel distribution assets we plan to dropdown to Sunoco LP 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 acquisitions. However, the prior year benefited significantly from market dynamics connected to weather and other product 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 deliver solid results and exceeded its internal budget. From an operational perspective, we delivered same-store retail fuel growth in our Pad one region, and while our Stripes 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 deliver strong growth in same-store merchandise sales in all markets, except for the impact of tobacco in our Virginia markets, where demand is most affected by tax regulations.

The $117 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 has filed to go public. These three items drove most of the decline in adjusted EBITDA from first quarter of 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 of 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 dropdown of assets from our retail marketing segment to Sunoco LP. ETP contributed a 31.58% interest in Sunoco LLC, which is our wholesale fuel distribution business. Sunoco LP 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 transfer to SXL of a 30% interest in the Bakken project effective as of April 1. 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 as a gathering and processing growth vehicle for ETP in the Northeast, but will also bring gas volumes to our Rover pipeline, and liquid products to SXL's Mariner East projects, 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 will 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 our Bayou Bridge project that we are pursuing with Philips 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 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 of projects, Trans-Pecos and Comanche Trail, that will pick up supplies from multiple interstate and intrastate pipelines at the Waha hub, including ETP's vast inter- and intrastate pipeline network, and deliver the natural gas to the border. 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 least1.135 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 border.

At the end of March, we closed on the King Ranch project acquisition from ExxonMobil for a total purchase price of $370 million. This acquisition includes a 750 million cubic feet a day gas processing plant, a 42,000-barrel per day NGL fractionator, an 8-inch NGL pipeline that delivers product to Corpus Christi, and the ETC KR pipeline which consists of 165 miles of 16- to 24-inch main line and gathering pipelines. This project gathers 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 NGLs are transported to end users, including DOW and [Nieto] and refiners in Corpus Christi. This gives us the opportunity to transport additional Eagle Ford volumes through our existing system, as well as Vicksburg's volumes and from other areas of south Texas. This acquisition also provides a platform for adding new processing and fractionation facilities as needed in South Texas.

Moving now to existing growth projects that have just gone into commercial service, or 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 will start with a 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 plant is scheduled to go into service in July and we have moved up the in-service date on both 24-inch Volunteer pipeline and the East Texas plant from January of next year to the fourth quarter of 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 per day Rover gas pipeline project. We have purchased all of 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 is 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 draft environmental impact statement from the FERC by June.

We own 65% of the Rover pipeline, in partnership with AE-Midco, and will 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 have seen 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 the shipper commitments that we have contractually secured to date, 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 for continuing to build upon our current commitments and to achieve the 570,000 barrels per day level.

The Loan Star Express NGL pipeline and conversion project is now under construction. ETP will build 534 miles of 24- and 30-inch natural gas liquids pipeline from the Permian basin to Mont Belvieu, and also convert Loan 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 2017.

CapEx update, ETP invested about $1.25 billion during the first quarter in growth in growth CapEx projects, with a majority allocated to our liquids transportation services, midstream, and interstate segments. When you include our indirect growth capital expenditures at SXL and Sunoco LP, 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 [4.5] times pro forma for the Regency merger before synergies. Under our credit facilities, the ratios were 4.05 times on a standalone 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 in three tranches, with interest rates ranging from 4.05% to 5.15%, and maturities ranging from 2025 to 2045. This enabled us to repay 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 our 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 dropdown of a 31.5% 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.

Thank you, 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 MMBtu per day, compared to 2.7 million MMBtu 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 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 online. 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 1 of the project is expected to be in service at the end of June 2015, with Phase 2 coming online in Q3 of 2015, and the Harrison County lateral is expected online by year-end. In South Texas, volumes are expected to continue growing on the Eagle Ford gathering system, and the recently expanded Edwards line joint venture. Commercial synergies are expected between these gathering systems, and the nearby ETP processing plants.

And with that, I will 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 that seventh straight quarterly distribution increase for 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 of 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 reduced 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. For 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 30. The new ETP organizational structure took effect from day one, with people in their new roles. We are very proud of the work done by the integration committee, in quarterbacking the merger of the two organizations, and the streamlining that has been done.

As the result of the work done by that committee, and the many men and women of 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 estimates for annual recurring synergies is a range of $160 million to $225 million per year, but that includes only cost reductions for personnel, balance sheet management, and the nonpersonnel 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 positive, and we expect that to be reflected in top line growth, and new opportunities in the future.

To put all of this in perspective, the synergy range based on our quarter one distribution, will comfortably bring us to a strong 1.1 times pro forma coverage ratio. We remain confident in our unique diversified platform, and our corresponding ability to continue to grow our distributions, and distributable cash flow in a 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 flow for 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.

Next, 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 will 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 a 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 IDR 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 are 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 10, 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 2016. On April 7, 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 developmental 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 US, Lake Charles LNG seems highly compatible with Shell's 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 and LP interest at ETP which now includes Regency, [90%] of the economics for the GP and IDRs from SXL 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 of 2014. Distributions from ETP and Regency combined, accounted for 74% of ETE's total cash flow in the latest quarter. SXL contributed 14%, and Lake Charles LNG approximately 12%.

ETE's Board last month declared our 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 1.12 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 19 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 for comment, proposed regulations governing the definition of qualifying income under 7704 of the code, which is a 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 they are taxed as C-corporations, with dividends from those C-corps being treated as qualifying income when received by our 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 tough cycle. The benefits of our diversified business model are clearly starting to shine through.

Our overall growth capital is without peer today, and set 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 make this happen.

Operator, that concludes our prepared remarks. Please open the line for questions.

Thank you.

(Operator Instructions)

Our first question comes from Shneur Gershuni, UBS.

Good morning, guys. First of all, thank you very much for some of the details with respect to Regency, it sort of helps us tie out 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. So I was wondering how we could think about that?

Is that a scenario where the backlog of opportunities 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 could give us some color on how to think about that?

Shneur, this is Mackie. Really a little bit of both. We're certainly early on in recognizing all of the energy between our different partnerships. But if you look at certain aspects of it, in East Texas, there are plants that we have, where we ship volumes around. There are also plant delays and/or even some situations we may not have to build plants. If you look in the Northeast which we see as a huge growth platform for ETP, with the success that Regency's had some with some activities that we hope to now assume, there are some significant synergies there on both cost savings, and on avoiding spending some capitals, but also securing the volumes we're negotiating, that both parties are negotiating at this time. So as we continue to integrate the assets, as we continue to analyze what we own also out in East -- I'm sorry, out West Texas, we'll continue to recognize significant value in compensation and in revenue growth throughout all of those areas.

Great, thank you for the color. And maybe as a follow-up. Can 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 the liquid fractionation 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 have got our draft VIS that we mentioned. We have now actually received our air permit, that we received earlier this week. We are continuing to get our interaction with our EPIC contractors, and we are short-listing 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.

Great. 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 expressed in a multiple or returns?

I think, Shneur, Mackie is going to jump in here too, but I think much like Mike Hennaing talks about, their 6 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 the two projects, both Trans-Pecos and Comanche Trail fit within that category. We have partners that we potentially, that we are negotiating with right now, that 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, Schumer.

Our next question comes from Darren Horowitz with Raymond James.

Good morning, guys. Mackie, if I could I just wanted to go back to your comments on the opportunities that have been in the Northeast. I know it's in the early stages per Jamie's comments 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 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 liquid side with Mariner East, I would assume that would be more backstopping Phase 2 of East, which was the incremental 275,000 barrels a day. I know that's scalable, but I'm just curious as to your thoughts from an expandability perspective, how much throughput do you think that could represent?

We've talked about this a lot yesterday. We would love to talk more about Revolution, we will very -- probably in 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've already secured capacity on Rover from this project. We also have secured capacity for Mariner East too, with this project, and it will do nothing but continue to feed residue volumes into Rover, and other products into SXL's 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 SXL NGL's systems.

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 Belvieu and ultimately, effectively down to the dock, what do you think the scalable opportunities, that 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 cargos across the dock, and move more barrels?

We couldn't be more optimistic really, its SXL's footprint, both at Marcus Hook on the East coast, and at Nederland, and our partnership with them on Mariner South. And with the extensive negotiations 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, it's going to happen over the coming years, and we believe both Nederland and Marcus Hook will play a significant role in that growth from the US, 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 condensate volumes, vapor controlled, stabilized, ultra light, sweet volumes move across that dock, or an extension of that dock at some future point?

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

Okay. Thank you.

Our next question comes from Brian Lasky with Morgan Stanley.

Good morning.

Good morning, Brian

Just starting on Lake Charles real quick. I was wondering, Jamie, if you could provide us a little bit of context around your conversations with BG, and how do they think about Lake Charles vis-a-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 the terms being renegotiated there?

Let me deal with the last aspect of your question first. Nothing has come up as it relates to their commercial arrangement between ourselves and BG. Recognizing that we look at it 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 yes, that speaks for itself.

It's the most cost competitive project that you can ask, from a control standpoint or from a shipper standpoint. As it relates to BG's timing, we are continuing down the path. As I said, we've just got our draft EIS, and we just got, I think, a very much clean bill of health. We have our 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, with very close -- very much the expected timing for the merger closing for BG and Shell.

Got it. And 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 BG, including the CEO. And so, obviously we think we have got pretty good information and intelligence on exactly how Shell's thinking about the project

Got it. Thank you. And in terms of the Revolution project, realizing you guys don't want to get into too many details at this point in time, could you just help us frame maybe the relative CapEx opportunities, just in terms of order of magnitude there?

Sure. I guess, at this time, we'll go ahead and announce it, probably going to be in the neighborhood of about $1.4 billion

Okay, and that's gathering and processing or fractionation, and what else is involved?

Yes, all of those, and processing, and of course, pipeline residues and (inaudible) pipelines.

Got it. And are there -- is this like one major producer backing this, or you have multiple producers involved? How did this originate?

You are really good about -- (laughter -- multiple speakers). We won't answer that, when we are under a confidentiality. (Inaudible -- multiple speakers) -- believe me, we are anxious to talk about it, it is a big deal though for ETP, but also for our affiliate companies. And so, we will be very open and vocal once we can talk about it.

Got it. Jamie, just on a timing of the [up-C], are you still thinking of the fall here?

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

And then, in terms of the ETE distribution, the recent step-up, Jamie, just assume that kind of consistently throughout the year, is that how to think about that there, so the increment?

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

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

You want to talk about commercial synergies relative to the $225 million, once it gets to $225 million?

Just in terms of the low hanging, I realize things are going to come up over time here, but just in terms of low-hanging fruits?

Yes, as I mentioned earlier, probably not very clearly, we're really early on. But there is no doubt there is going to be significant synergies. We know in East Texas, as I've mentioned that we see, has the largest system in West Texas, in Delaware basin. We are working on numerous projects, of not only adding assets, but also tieing our assets together that to exist out there. And then, also in the Northeast, with the early stages of really truly recognizing what those synergies and benefits will be, but no doubt they'll be significant.

Okay. I will jump back into the queue, thank you.

Thanks, Brian.

Our next question comes from Ted Durbin with Goldman Sachs.

Just coming back to the Bakken pipeline, I guess, a first housekeeping one, are you putting any value on the actual transfer of this 30% to Sunoco? (Inaudible -- technical difficulties)

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

Okay. And so, just philosophically here. We're transferring 30% now, do we think longer-term -- does the rest of it ultimately belong to Sunoco, because that's your crude oil platform? Just more about sort of in the near term or does the financing (inaudible --technical difficulties), Just sort of tell us how you are thinking about the longer-term for the Bakken?

No, we don't anticipate the ownership changing anymore. But let me say this, we couldn't be more excited to have SXL (inaudible) it is the premier oil transportation pipeline and partnership in the country, by far in our opinion. 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 it 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 you are going to get volumes up into Canada. Is there any change in 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 100 mile-plus reduction of pipe that we had to lay through Michigan. So that was already -- and that is now reflected, obviously, in what we filed with the earnings release, and what we'll file tomorrow with the [Q].

Got it. And then last one for me, if you could just talk a little bit more about King Ranch, what are the volumes now going through the plant, maybe any sense of the EBITDA that is generating? How do you see that ramping up over time, whether it's adding third-party [ARP] volumes or whatnot?

This is Mackie again. Let me just say -- we are also very excited about that project, albeit it has been there a while, but it's a perfect place to be very synergistic, with not only our Eagle Ford growth, but also with some other growth in Olmos and Vicksburg and getting closer to Mexico, and delivery of products.

As far as EBITDA, it's too early for all of that. And volumes are very good, it's probably about two-thirds full right now. We anticipate ramping that up over the next 12 to 18 months. And in fact, we're also looking at possibly adding additional facilities there, possibly cryogenic facilities, and even possibly a fracination facility. So it is a great location, and very synergistic with all our other assets in South Texas.

Great. I will leave it at that, thank you

Thanks, Ted.

Our next question comes from Brandon Blossman with Tudor Pickering Holt.

Good morning, gentlemen.

Hi, Brandon.

Actually, you've hit most of everything. I'll just try to put some incremental color on the integration synergies here. One, fairly 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? Has it been an exhaustive review, and do you think that you've 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 aspect first. I think we said in the remarks, these were our initial estimates. So there's always the prospect and possibility there could be more to come. I think this doesn't begin and end with the fact that we have now closed the merger, and people are sitting in their new roles.

I think overall, belt-tightening is something you do everyday, and you think about how you can make your business more streamlined, and more efficient. And I think that, very much is synonymous with the way we're thinking about it. So this -- the sort of range right now, could in fact obviously improve over time, depending upon how we move forward.

As far as the range is concerned -- look, there's a lot of things in here. There is some balance sheet management, and what we do and how we do some things. How we think about some things here -- there are probably at least 12 plus categories of cost that fit into that overall bucket, just on the cost side. And within there, there's a significant amount of subset within each of those categories.

So that's what ends up giving you this -- the element of a wide range, at $65 million of that sort of low to high, we didn't think was incredibly wide. But nonetheless, I think we felt that it was reasonable and appropriate, and what we think; it reflects our expectations

Let me add though Jim, this is Kelcy. We're done on staff reductions. So I want to be clear on that, and so when we give you that range, numbers can creep over in and get very impersonal. But from a human resources standpoint, we are done. We lost some great people as a result of this merger, and unfortunately it's 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, would you characterize it more as an attractive acquisition on current multiples and deal metrics? Or is this really an acquisition as a development platform, with lots of interesting opportunities on a go forward basis?

I'll -- Mackie, I'll talk briefly about that. Every single time, this is without fail, when you can find a platform midstream asset that's being operated by someone whose primary economic driver is not the midstream business, you can never fail, ever. I mean, of course, you can overpay, but that's essentially what this asset is. It's been owned and operated by ExxonMobil for years, but very well by the way. They are great operators.

But their primary driver, economic driver was ExxonMobil 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 of the things that we do and do well. And I think if you'll -- if you give us a little time, I think you'll be very impressed with what Mackie and his team does

That will be interesting to watch, thank you. That's all for me.

Our next question comes from [John Kiani] with [Teilinger Capital].

Good morning.

Hey, John.

In thinking about the benefits of, especially the synergies that you highlighted for ETP and the Regency transaction, how should we think about, in 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 and over the medium term? And are we going to see the benefit of the synergies in the form of just better coverage over time? Or is the $0.02 a quarter at P that we have 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 -- I got asked 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 will feel very comfortable with it. Our job at the end of the day is shepherding ETP and SXL through this tremendous amount of capital, to get them to the end of 2016, in a 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 at right now, translates to -- I don't know roughly 8% or so. And it sounds like the benefits of both the CapEx and the transaction could provide upside to 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 various levers of alternative equity that could be brought into P, to obviously help mitigate the issuance of units, at a greater than 7% yield with and IDR obligation on top.

There are things of -- obviously the dropdowns are one. You saw the obviously in spades, and what we did last month, where we did a [95] cash 5% units. And obviously, continuing the dropdown story with Sun, whether that's on a sort of a current time table, or even if the markets allow on an accelerated timetable.

The more cash back, that is obviously one avenue. We got the stake in P, yes. We've got various other 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 it's credit metrics at that sort of 4.5 times, allow us to maintain very much very stable investment grade ratings and I think, significantly improve the prospects of its distribution growth going forward.

Great. Thank you.

Thanks, John.

Our next question comes from Helen Ryoo with Barclays Capital.

Thank you, good morning. So I'm just going to ask a couple of quick questions. First on Mexico project, could you talk about the contract duration and project return? Also all there are any other Mexican projects in the works? I remember, you mentioned a couple of other opportunities during the analyst meetings, so if you could provide an update?

Yes, Helen. It's Mackie. As everybody probably knows, Mexico is going through transformational changes, and they're in the process of expanding their system, kind of like Energy Transfer has done in the US with 42 inch skeleton pipelines throughout their country. They will continue to have RFPs for other countries to join and build that network out, and that will connect along the border of the United States. And so, the first project that we started feeding earlier this year was a 42-inch that tied into 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 their network, and we will continue on our side to play a big role on bringing volumes through our systems to Mexico.

Okay. And this, are these two projects, are they 10-plus years contract life? And also, is the return consistent with your sort of [5] to [7] type of project return?

Yes, the second question is consistent with a 7 type multiple, and these are 25 year agreements.

Great. And then just on the Bakken project. I mean, Jamie, you mentioned that the regulatory process is going well, but there are some talks about changes in Iowa, in terms of them exercising eminent domain. So could there be -- is it 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 timing. We think we have the best team in the country to build these types of projects. Certainly, they're not easy. Certainly, any where in the US if you build a pipe, you are going to find opposition. It's just the nature of the business these days. But we don't see anything, any type of hurdles that we are concerned about getting over. And right now, we are on track to have it built by January 2017

Okay. And lastly on the Frac III and IV, I guess the comment was both are fully-supplied, and could you -- are they -- are the contracts take-or-pay long-term 10-plus years take or pay? And also, Frac IV seems, Frac IV costs is [$450 million], Frac III was I think [$300 million], and of course, Frac IV is a bit larger, but is the cost difference pretty much related to size? Or is there anything else that contributing to Frac IV project cost?

Well, I'll start with the costs. On the -- when you talk about costs on these fracs, many times there's associated piping and interconnects, and so the earlier frac didn't have quite as many. We do anticipate more on the second frac. Yes it is -- we are building a bigger frac, about 20%. We also are creating more connectivity to other markets throughout the entire Mont Belvieu area.

(Multiple speakers). I'm sorry, on the contracts

Yes, on the demand -- the beauty of all our frac, is they're all approximately 9% demand. So regardless of whether the volume show up or not, we get 90% of revenue that we forecasted. And these are typically about 10 years, some are 15 years, but typically 10 year agreements.

Great, thank you very much.

Our next question is from Abhi Rajendran with Credit Suisse.

Hi, good morning, guys.

Hey, Abhi.

Just a couple of quick ones. Can you give us an update on the buyback at [ETE]. Have you used any -- just kind of looking ahead for the rest of the year, how you are thinking about that? I think last time you said, how 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 short answer is, we have not done anything on the buyback. I think, we were very clear we were 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 our deploy dry powder if you will, with the excess coverage, and utilize that to in fact, start the buyback, we'd be very selective and disciplined in how we, in fact, tackle it. So I think that is pretty much where we are.

Okay, got it. And just a quick follow-up on that. I think coming back to the up-C, you obviously bought back a bunch of stock already last year. Is the idea that, you buy back some more, before you go through the up-C, because that's what you will use to put into the C-corp vehicle? Any color there would be helpful?

The short answer is the buyback was 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 go recycle units as part of a -- some sort of -- as part of a C-corp form, then obviously that would be a different use, and we'd think more about the overall size of the buyback, and what we would do. So I would say we've sort of divorce the two. Where the buyback is very much -- we were happy to retire a bunch of units, because we thought were undervalued. So C-corp serves a completely different question, and at the appropriate time, we'll consider what we do.

Okay, got it. And last quick one for 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 LNG MLP up and running, to possibly use that to potentially roll up some projects. Can you talk a little bit about the environment there? How you're seeing some of these other projects progress in this environment, if that has maybe changed at all, or if you're still concerned about that?

Look, from our standpoint, whether it is on the pipeline side, and I think pretty much on the pipeline side is where we see a lot of the initial interactions with a lot of these LNG projects. Everyone seems to have an LNG project, whether they are small, whether they are midsized, whether they are larger size. None of them seem to have any customers, other than those that obviously, that most -- the folks like you, Abhi, write on.

So I think our viewpoint is, look, if the market stabilized, LNG in the 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're in a hiatus, and I think people are obviously just spending a lot of time on development, with very little to show for it. So we still talk to people. We talked to most people, I think as it relates to just pipeline connects and hookups, but we do get a pretty good sense of what's out there and what's going on.

Got it, thanks a lot for the color.

Our next question comes from Jeremy Tonet with JPMorgan.

Good morning.

Good morning, Jeremy.

You guys have covered a lot of ground this morning. So I 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 of the year?

I would say as it relates to Holdco, now that Mr. Whitehurst has assumed command and control on the tax side, we've actually I think 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'll be relatively flat, meaning that they will not be a source of cash, nor a use of cash which is a very good answer from our standpoint. And it 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 off-line, and give you some more color, Jeremy, so as it goes along, as to how to think about it. But our intent has always been to try to take some of that noise out of the system, and make it relatively benign and flat.

That is 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 spreads], and do you see any room for improvement in that over the course of the year, if conditions are challenging?

Yes, this is Kelcy. We're, believe it or not, we are running full speed under the water here, just like a duck. But we have not had any traction on anything, we're a little bit surprised actually.

We thought we would see -- because mostly because of frac spread contraction, and how long it has been down, with commodity prices that we would see more opportunities. We have not seen them, but we are -- it is not a good thing for an MLP to be our size, with our family, and pretty much all of the family members, without the correct combination of M&A and organic growth. So we recognize we need to do some more M&A. We need to announce some opportunities, but we're a little frustrated right now. We're just not getting the traction we hoped 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'll 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.