Thank you and good morning everyone. Thanks for joining us today.

Just based on the number of press releases that we’ve made over the last several weeks, including the one just this morning, we certainly have a lot to talk about, particularly, targets that we are pursuing and we expect will bring significant distributable cash flow growth to the partnership over the next several years and further increase our scale and diversification of revenue stream. And in addition to bringing you up to speed on our growth initiative, we’ll also make certain comments about ETP and ETE financial results for the first quarter of 2011.

I’ll also encourage you to visit our website to access the earnings release we issued yesterday after the market close. And during this call, I’ll make forward-looking statements within the meaning of Section 21E of the SEC Act of 1934 based on our beliefs as well as certain assumptions and information that’s available to us.

And as always, Kelcy, Mackie, John McReynolds and other members of our senior management team are here with me to answer your questions after our prepared remarks. Okay.

Before going to our growth initiatives, I would like to discuss our Q1 results. Our adjusted first quarter EBITDA was $471 million, down about $42 million from the first quarter of last year.

The decrease was primarily due to lower storage margin on an adjusted basis or a cash that is -- but not only lower storage growth realized our results, but also decrease results from a year ago given the current [market additions] that we saw during the first quarter, I’ll touch about on that in here a little bit. Also, adjusted EBITDA from our intrastate transportation and midstream segments declined slightly or affected by higher adjusted EBITDA from our intrastate segment as FEP and Tiger are now in service and generating cash flow.

I will remind everyone that FEP and Tiger’s fast growth will continue to grow in 2011 and the demand will increase mostly in Q3 and Q4 of this year. In addition, year-over-year EBITDA was impacted by the sale of MEP, which has an adjusted EBITDA of almost $19 million in the first quarter of 2010.

On a distributable cash flow perspective, we saw $337 million this quarter compared to about $385 million in the first quarter of 2010. And for the first quarter of 2011, we will pay ETP unit holders $3.575 on an annual basis per common unit on May 16th.

And I just mentioned our distribution rate, we are confident we will see a rate increase in the near future. I know its fine to say, after any significant margin disruption or operational issues; we expect to grow the rate by no later than the third quarter of this year.

Now, I’ll go into a little bit more detail about the performance on our business segments starting with our intrastate business. Overall, transportation volumes continue to show resilience in long-term market conditions with our intrastate transportation segment having experienced an almost 5% increase going from roughly 11.3 Bcf a day in the first quarter of 2010 to almost 11.9 Bcf a day in the first quarter of this year.

The two testaments are not only our integrated transportation system, but also our commercial team working diligently to keep our pipes full. The net increase in volumes transported was primarily from increased production of our customers under long-term contract.

That was partially offset by a decrease in interruptible volumes mainly due to lower base of differentials between the West and East Texas market hubs. And the point of reference, the other spotlight difference between the implications was approximately zero in the first quarter of ‘11 compared to about a nickel in the first quarter of 2010.

And when looking at our operating income for the quarter, intrastate had $144.1 million compared to $134.2 million in 2010. I will just add to that a couple of factors.

Margins from the sale of natural gas increased $5.2 million in the first quarter of this year as compared to the first quarter of last year, primarily due to systematic optimization activities, some of which was due to better pricing on the retained fuel hedges. In addition, we experienced an increase in transportation fees for the period which are likely related to the increased volumes that I previously mentioned.

Our storage margins did increase $7.8 million primarily by carrying a larger volume of inventory out of the withdrawal season are subjected to mark-to-market impact of the spread between its spot and forward prices narrowing during the period. And as you know this year's natural gas withdrawal season ends a little earlier than usual and we elected to defer the withdrawal of this gas out of our Bammel facility until next winter.

Adjusting to remove the non-cash gain allowances on storage related and the related inventory to past storage margin was $25.7 million this quarter compared to roughly $54 million in the quarter of 2010 its about $38 million decrease; again driven by storage margin decrease in this quarter compared to the same period last year. And regarding our storage facility, we have about 35 Bcf contracted under the fixed fee contract that puts us about 50% of our storage capacity that is locked up under fee based arrangement.

And as of March 31st, we had approximately 30 Bcf in the ground for our own account; as I mentioned before, we look to withdraw in 2011-2012 winter season. And moving now to our intrastate segment where we’re seeing significant growth.

Our operating income was $52 million for the quarter, an increase of $20.5 million compared to last year and that’s finally due to higher revenues from taking the Tiger pipeline in service in December of 2010. And in terms of volumes, it may increase attributable to Tiger was partially offset by slightly lower volumes on our Transwestern pipeline.

And as well FEP began full in service in January of this year and it contributed roughly $8.2 million of EBITDA to ETP for the first quarter. Our share of distributions coming from ETP was roughly $5 million in the period.

Now I’ll turn our intention to the midstream segment where we continue to see very healthy volumes in gathering, treating and processing, primarily through our Godley plant. Our operating income decreased slightly to $49.5 million this quarter compared to $52 million last year, which included approximately $2 million impact in extreme cold weather that we experienced in February.

Our gross margin did increased $5.9 million but was offset by $6.6 million in operating expenses along with the increased depreciation and amortization expense in our growth projects that will take some service throughout the year. In addition, we had $2.2 million decline in SG&A which have offset some of the increases in both OpEx and depreciation and amortization.

While overall NGL production did increase as a result of higher production by our customers, equity NGL production did decrease year-over-year as we continue to pursue a higher concentration of volumes under fixed-fee contracts. And looking forward, we expect to realize the benefits of our investment in our midstream segment and certainly see strong growth for the next several years as new projects come online mainly through our initiatives in the Eagle Ford Shale as we expand our service capabilities and leverage off our existing platform and of course I will go into a little bit more detail about what we are doing in the Eagle Ford.

Turning our attention to the Propane segment, we did see an 8.3% decline in volume which was really driven by weather patterns and customer conservation. Weather this quarter was 2.7% colder than normal compared to weather being 5.3% colder than normal in the same period of 2010.

Our first quarter operating income was a little less than $120 million, down about $70 million for the first quarter of 2010. Okay, let's talk about some of our recent developments from a growth perspective.

And I will start with the acquisition of LDH, actually Lone Star NGL or Lone Star, a new name of our JV. On Monday, May 2 we as being ETP and Regency completed the acquisition of LDH Energy from Louis Dreyfus Highbridge Energy.

If you recall the JV is 70% owned by us and 30% by Regency. The total purchase price for the acquisition including working capital and other adjustments was $1.972 billion, $1.38 billion being ETP's 70% share and to recap, Lone Star owns and operates a natural gas liquid storage fractionation and transportation business.

Stored assets are really primarily located in Mont Belvieu, Texas, one of the largest NGL storage distribution and trading complexes in North America. Its West Texas pipeline transports NGL through a 1,066 mile intrastate pipeline system that originates in the Permian Basin in West Texas, passes through the Barnett Shale production area in North Texas and ends up at the Mont Belvieu Storage and Fractionation Complex.

In addition, it also owns and operates processing and fractionation assets, and are primarily located in Louisiana. And we've made substantial progress towards integrating the operations in personnel and expect to substantially complete our integration at the end of the second quarter.

We also have everyone on board from an employment perspective and are very happy to know their excitement in joining the Energy Transfer/Regency team. I can't say how enthusiastic we are about this acquisition which as we've already mentioned, significantly expands our asset portfolio by adding an NGL platform with storage, transportation and fractionation capabilities.

This really gives us a competitive advantage as we approach our customers with a full fleet of midstream services and we are already seeing this advantage today as we seek new growth projects. The latest one being a new 100,000 barrel per day fractionator that we had jointly announced this morning with Regency.

This project which we expect to span approximately $350 million to $375 million and put into service sometime in early 2013, will be supported by equity NGL volumes coming from ETP's existing and soon to be completed assets, and the returns on the fractionator are expected to be attractive and accretive to our unit holders. In addition to the fractionator, we are also looking at expanding the West Texas pipeline, build an additional storage capacity at Mont Belvieu for which we have the ability to add nine incremental wells on land we already own and increase our processing capacity in Louisiana.

These projects and others may well lead to investments for the JV exceeding $1.5 billion over the next couple of years. I also want to reiterate how NLP friendly these assets are.

The existing assets generate substantial fee-based revenues, over 70% much of which are supported by long-term contracts and we definitely see the ability to improve profitability on these contracts as they renew given the current market environment. In addition, we expect the projects we are pursuing will not only increase distributable cash flow, but will also increase the percentage of fee-based revenue.

And from a financing perspective and I am only talking about ETP here, we finance our contribution to the JV from our existing revolving credit facility. In order to do so, we got ahead of the closing date and raised a little less than $700 million in proceeds through the largest NLP equity offering ever completed.

Not only were we looking to take financing risk off the table, but we also keep our commitments to maintaining investment grade credit metrics; a commitment that we will continue to uphold. And as of May 04 and taking into consideration, the financing of the acquisition’s purchase price under our credit facility, we have roughly $1.3 billion outstanding on the facility which gives us the ability to be opportunistic as we arrange longer-term financing to repay those borrowings.

Okay, let’s talk about ETP specific projects. Several quarters ago, we commented on our need to be a bigger player in the Eagle Ford and guess what; we’re well on our way to reaching that goal.

On April 21st, we announced an expansion of our rich Eagle Ford mainline of REM project after having entered into a long-term fee-based arrangement with a number of key producers in the area, including Rosetta, SM Energy and Anadarko to provide natural gas gathering, processing and liquid services from the prolific Eagle Ford Shale. To facilitate these agreements, which includes volume commitments in excess of 540 million MMBtu used per day of natural gas, we plan to significantly expand our previously announced REM pipeline in South Texas and construct a new processing plant in Jackson County Texas.

The REM pipeline expansion which will extend from the Chisholm Pipeline in DeWitt County east into Jackson County will add roughly 70 miles 36-inch or potentially 42-inch pipeline to the initial 160-mile, 30-inch REM pipeline that was announced back in January of this year. And when fully constructed, the REM pipeline will consist of approximately 230 miles of pipeline with a capacity of 600 million cubic feet per day.

Completion of the initial phase of REM is scheduled for the fourth quarter of this year and completion of the expansion project is scheduled for completion in the first quarter of 2013. And as it relates to the Jackson plant, it will have approximately 600 million cubic feet a day capacity and can be expanded to 800 million cubic feet a day.

The plant is scheduled for completion in the first quarter of 2013 as well and associated with the REM related projects, we are also looking at building an NGL pipeline to provide liquid takeaway in the Jackson plant and deliver those volumes over to Mont Belvieu, although we are contemplating a partnership with another entity which will bring better value to our unit holders. The total cost of the REM pipeline, the Jackson plant and the NGL pipeline is expected to approach $1.25 billion based on our produciary needs for capacity.

And I’d like to point the contract supporting the South Texas growth initiative are primarily fee based with minimum throughput commitment equals to about 80% of the capacity and (inaudible) 10 years. However, we expect that [prop] volumes will end up being closer to 100% of capacity based on the activity we’re seeing.

Another recent and exciting project that we announced with the agreement to form a 50-50 JV with Enterprise Products Partner to design and construct a crude oil pipeline from Tulsa, Oklahoma to Houston, utilizing the existing renewed pipelines an roughly 580 mile project with originating in Cushing, Oklahoma both EPP and Enterprise would each contribute existing assets to the JV including our 240 mile 24 inch diameter natural gas pipeline located in Texas. If I have to convert that pipeline from its state of natural gas transportation to crude oil.

In addition by utilizing infrastructure already in place and all of the existing pipeline rather away for roughly 350 miles of new construction, we expect the pipeline to be in service much sooner than competing projects out there. Subject to sufficient commitment from shippers and the required regulatory approvals, the new pipeline is expected to be in service by the fourth quarter of 2012.

The JV partners would share commercial responsibilities with an Integrated Project Team responsible for the construction of the pipeline and Enterprise will ultimate serve as the operator. We are very eager to enter the business of transporting crude oil and we believe this will raise the further opportunity as we meet our customer’s [midstream] needs.

In addition the JV will increase our scale of operation and further diversify our cash flow stream are being been supported by consistent and stable revenue coming from principally fee based contracts. I would also like to provide a brief update on some of our other areas of growth that we have highlighted previously.

Liberty, the construction of Liberty pipeline, if you recall the JV was also announced for the 12 inch NGL pipelines, that will primarily service for most of [Houston] and East Texas is proceeding quite nicely. We expect the project to be in service by the end of the third quarter of this year and in North Louisiana and in Haynesville shale which are now up and running, we continue to see increased volume as it produces still the committed capacity.

We are currently transporting more than 1 bcf per day and expect that to increase to average over 1.2 bcf a day over the remainder of 2011. These are also looking good without Tiger expansion of 400 million cubic feet a day and we expect to have that expansion in service by October 1st if not sooner.

And we saw that this expansion is fully contracted for 10 years. And as it relates our North Louisiana gathering systems we also continue to see increased volumes with volumes being at Tiger at 400 million cubic feet a day and could see that grow as producers continue deliver volumes in to Tiger.

And in the northeast we’re currently transporting nearly 40 million cubic feet a day on a Bobcat pipeline and more than 40 million cubic feet a day on a Jarvisville extension. The main volumes of 200 million cubic feet a day are still anticipated by the end of the third quarter of this year.

And to sum it all up we’ve been working quite hard and see additional growth opportunities for ETE and its certainly paying off. We have build this partnership by listening to our customers and producers and we’ve heard them loud and clear.

They wanted extended services primarily in the NGL areas related businesses and we are that solution for them. I’ll now go through a couple of CapEx numbers.

We did invest $186 million in the first quarter of 2011, of that $38 million related to the Tiger pipeline and roughly $140 million from our interstate transportation and midstream segment, much of this related to our Eagle Ford Shale project. The remainder was spent in our propane and others segments.

And based on the project we’ve announced including the one we did this morning and other successful development primarily in Eagle Ford Shale we’ve revised our estimated growth CapEx upward for the remainder of 2011 and now it's expected to be between $600 million and $650 million for our midstream and intrastate segment, roughly a $150 million to $190 million for our interstate segment and 15 to 25 for propane. That’s an overall increase in growth CapEx for 2011 of $165 million for $185 million for what we've estimated at year end.

Our maintenance CapEx was just under $20 million this quarter and we expect to spend between $90 million and $110 million for the remainder of 2011. In addition we anticipate contributing almost $250 million to $300 million to our joint ventures in 2011 including $50 million to $75 million to Loan Star principally for the [fractionator] that we announced this morning.

This doesn't yet include any amount for our JV with Enterprise and we will be providing additional updates as more information becomes available about that specific project. That pretty much roughs up ETP discussion point.

I would like to make a few comments about ETE before I turn to questions. For the quarter ETE had approximately $125 million and distributable cash flow, that's an increase of almost $7 million from the fourth quarter of 2011, primarily driven by increased cash flows from ETE ownership interests in both ETP and Regency as a result of the respective equity issuances again primarily from the LDH acquisition.

When looking at first quarter 2011, distributable cash flow through the first quarter of 2010, we experienced increased interest expense primarily from the issuance of the $300 million preferred unit to GP in connection with the Regency GP acquisition and from the successful debt offering completed back in September of 2010. As it relates to distribution to ETE unit holders we did announce a $0.02 increase this quarter are roughly 3.7% grows from $0.54 per unit on a quarterly basis to $0.56 per unit which we pay to ETE unit holders on Thursday May 19.

Of the numerous growth initiatives underway at both ETP and Regency, we expect ETE's cash flow to continue to grow and therefore the distribution rate as well in the years to come. With that operator let's open up the line for some questions.

With that operator, let's open up the line for some questions. Thanks everyone.

Just a couple quick questions as it relates to the press release. The Lone Star press release that you guys put out, of the 100,000 barrels a day fractionation capacity at their new facility, how much capacity is ETT going to utilize under those 10-year contracts that you outlined?

As we said today, approximately 80%, but we anticipate that being 100% in the very near future.

Okay. And how much additionally storage capacity is Lone Star going to develop there?

In regards to this fractionator, we are re-activating one existing cavern and building two additional caverns.

Okay. And then, Mackie, last question for me, I am just trying to get a feel for how much capacity you think is going to be filled by y-grade coming from Jackson County down to Belvieu?

I mean it seems like if you move forward with that 20-inch line, that's 340,000 barrels a day, you've got plenty capacity to accommodate a ramp from the Eagle Ford Oil from West Texas. So, any color there that you could give us will be appreciated?

Sure. We continue to see some pretty incredible curve coming from the producers in the Eagle Ford.

So it’s hard to say where we end up barrels-wise, but we certainly have some high hopes for significantly more barrels in the future. In addition of that, there needs to be a line built from West Texas and we intend to play a big role on that and so, this is kind of the first leg in getting us to West Texas.

On the fractionation project 350 to 375 does that include just the cost of the fractionation or does it also include related infrastructure?

It includes the latter; includes the store facilities we’re developing. It includes a significant amount of interconnectivity to all fracs, to all the pipelines and (inaudible) more markets.

Okay, great. And then, sorry please go ahead.

And just convey in addition to the fracs now.

Okay, got it. And then you talked about the NGL takeaway capacity out of Jackson that you could either build it by yourself or did you mean joint venture – and if you were to go with another option which is to go with a joint venture partner, would you be building with the joint venture partner or use an existing line?

Possibly either. We have third-party discussions both utilizing existing lines and partnering up on the NGL line.

Okay. And if you were to build this, how much do you think you need to spend in order to have that 340,000 barrels a day capacity?

We estimate $250 million and $300 million if we build the entire 130 miles 20-inch pipe.

Right. And this will be in the joint venture; so you would be splitting the cost with Regency if you were to do that?

As we sit here today, this is a ETP NGL line from Jackson…

Okay. Yes, okay.

And then just moving over to the crude line, the JV with EPT, I think in the press release, you mentioned this line would account for 40% of the system and I am wondering if that means that the value of the asset you are contributing would account for 40% of the JV. In other words, you would be, may be contributing the remaining 10% in capital?

Yes. What we are doing is it’s not a 584 mile pipeline, and 240 miles of that of existing system that we’re converting to crude.

And then we will share the capital required to build all the pipes that need to be build on each end 50/50 with enterprise.

Okay.

It is Kelcy, its worth noting that even though that pipeline is in fact owned by Energy Transfer, there are contractual rights that enterprise owns in the top-line in perpetuity that it really roll back to purchase – its kind of a jointly owned line.

Okay. The pipeline you are contributing is kind of jointly owned by enterprise?

No, Helen we own it.

Okay.

But enterprise does have contractual rights to abuse the line and so therefore it’s – I just want to be clear that this is truly a partnership where we are both involved in the contribution of this pie.

Okay, got it. And how much capital do you think you may have to contribute to make it a 50-50 joint venture?

On that one Helen, this is Martin, you know we’re still going through the discussions with producers and so ultimately how big is pipeline from a diameter perspective is yet to be determined. Also just kind of given the competitiveness of this pipeline, we’ve not given cost estimate.

So at this time, we’ll probably pass on that, but certainly as we find our producers, you know get the required volume commitment to move forward with this which we’re very optimistic that we’ll get there; we’ll share more that information, but for now its given where we are in discussions and that’s something we probably won’t provide in depth.

Yeah Helen let me add, we are pretty excited about this. It's pretty easy for us to state that this will be substantially less cost than any of the competing projects that I have seen that have been announced for pushing to the Gulf Coast.

The cost of the existing pipe and also you know just to – there is less environmental impact that is good to have in the State of Texas; it should be – this line should be built faster and substantially at less cost than any of the alternatives out there.

Okay, great. And then the last question would be, you know are these new projects are pretty must fee-based project; I would think that the frac, the crude oil pipeline and you know I am not sure about the processing, the REM processing plant whether that would be 100% fee-based or there would be some commodity components there?

The gathering, processing the NGL line and the frac are all significantly fee-based contracts; half percentage to [demand charge].

Okay. Even the REM plant?

Even the REM processing plant, yes.

Hi, given you got this new platform for growth and Louis Dreyfus assets and you know continue to conservation on the propane side; I was wondering if you could kind of outline what your strategy is for propane and whether that’s changed or you can be doing deals to try to keep that flat or what’s the strategy there?

Yes, propane has consistently been a good business for us and as you know and you can see from the numbers and from previous years, it’s very weather sensitive, it’s very economy sensitive. We've got very good management and we will continue to grow propane, but as you know you don't grow it in big chunks.

At least that's the way we choose not to grow it. It’s typically small acquisitions and they don't amount to a lot of money compared to our other investments, but the business we will continue to grow and we believe that our propane business has grown as well as any other business in the country.

My questions are going to tend to be sort of high level. The first is congratulations on all these projects, but do you need to add some folks to be able to manage all these projects?

Absolutely, we've got Mackie to the point of breaking and which is good, you know if you are me, that's what you want to do. But absolutely we’ve been here and we need more expertise and we are in the job market now conducting interviews and we are going to beef up our team, yes we are.

So related to that Kelcy, what does the integration mean in terms of I guess Martin in your opening remarks you said that you are well on your way to integrating the Louis Dreyfus asset. What does that mean exactly?

Yes, for example, there are certain things that doesn’t matter if you are moving a barrel or if you are moving a cubic foot of gas, that can actually be integrated in certain amount of engineering, in certain amount of accounting, even measurement to a large degree, [runway] maintenance. Many, many things that can be integrated and effectively, cost effectively and intelligently and that’s what we are referring to.

Martin, would you like to add anything?

Yes and Kelcy has hit the nail on the head. It has a lot more to do with just getting folks on board, getting both teams to work together.

As you know, Regency's assets tie in on the originations on the West Texas pipeline and in the Permian. We tie into (inaudible) and of course what we are doing in Mont Belvieu.

That’s the integration of being commercially minded from an ETP perspective and Regency perspective as well. But then also, I think there were some questions.

We announced a project about who is coming from the employment perspective. That’s all behind us.

We've got the team in place across all entities and ready to show some growth.

And when you think about all these projects, it seems like a lot of the capital is going to be spent next year. Do you have any sense of how big the number could be for 2012 in terms of growth CapEx?

Well, I think when you add up all the things that we've announced over the last few months, let’s say, I think as I mentioned in my remarks, on Lone Star, we see that being north of $1 billion, close to $1.5 billion. When you look at what we are doing on the ETP side, you are also talking probably north of 750, so we’re approaching probably $2 billion between 12 and may be some into 13 in terms of lot of risks we are pursuing today.

And of course if we’re successful with the Cushing project.

Right, and then if we are successful with the cushing project, then that’s added to it.

Okay and then just the last two. When you think the returns historically, you’ve really knocked the cover off ball on returns, how would you frame the returns on these projects going forward?

No difference.

You want to put a number on that?

Well, we’ve always shot for something getting off the ground in the six, seven multiple range for these type of assets, for these type of projects and then these are also going on a commitment level that we’re comfortable with and as we have historically proven and executed on, we drive that multiple down. So that says the same from a pricing perspective.

And the last question. When you look at the Lone Star assets and the whole array of assets that you have within Energy Transfer, does it make sense to perhaps to prune some assets, any disposition that you might want to think about?

A few years ago, you sold some assets would you think about that again here?

Yes, this is Kelcy. As you know, it’s very difficult for an NLP to justify that or rationalize just way through it.

However, we continue to look at that and we will, if there’s obvious tax cuts points us to that, that we’ve got to consider per unit holders, but yes, sure. We will continue to look that sure.

Just on the fractionation facility that you just announced this morning and I just wanted your views on all these projects. So, I am just trying to understand a little better what kind of, how this works.

Is this going to be fractionation on fee basis or are you going to be able to capture margins for your own account. I am not quite clear, how the arrangement is here?

As we been mentioned earlier the way we structure these agreements, if the put a frac its 100% fee based, demand charge, fracking [low grade] into different components. Yeah, in other words John.

We are not going to be buying the [low grade] and then reselling the fractionated product. That's what you are asking.

We are not going to get them, the merchant business of that.

Okay, great. Just switching over to Energy Transport Equity, can you just remind us the, what the interest rate on that debt.

You did that refinancing lot long ago.

It was there were 7% -- 7.25% somewhere in that. Now that was a 1.85 billion senior note offering.

Just have one question from me on natural gas storage. Can you talk about your thoughts process and keeping that gas underground rather than withdrawing and what your view is and what storage in the winter, winner spreads will do for the coming year.

Since right now they don’t look much better than that what you could gotten today.

Yes I think Michael on there we hedged, and then you look at what it would cost you to withdraw at a cost. What would you realize if would have withdrawn and based on the our top months on the curvet and the market says or at least show that it makes more sense to hold on to that and get an extra nickel, a quarter, a dime whatever that maybe.

That’s what we look at and because of what we saw from a commodity price perspective in the first quarter it was more advantageous to hold on to that inventory, keep it on the ground and then just profile it for a withdrawal in late ‘11 or early ‘12. Having said that we continue to look at it, the extent that we see weather patterns unfold, commodity prices change as we head into this summer with heat coming in, you make an opportunity to withdraw during the summer and we take advantage of that as it shows up.

So a lot of flexibility in our storage facilities and we try and optimize that and again try and profile some that makes sense today but the market will change and so will we. And I think going forward our goal is to have much more that capacity under a fee based contract.

Having said that with where gas prices are in our business and its the tough business today. Its pretty flat curve out there which means flat spread or spread aren’t as good as what they used to be but it will come back and we just don’t want to give that capacity away.

We've got returns to make and right now we’ll do it on a short-term basis including get contracts that make sense for us.

Let me add one thing to that to. These volumes that we are talking about and others are talking about there's a significant amount of residue volume that will show up in and around the [ship] channel.

We do believe that will impact spreads and storeds will become more and more valuable in the future as these volumes show up.

Okay. That’s helpful.

So just one more point on this topic. So just to understand how it works; are you effectively rolling your hedges forward to the next winter now or are you just letting it expire and then you see kind of how it develops?

No you roll them, we don't think any [predictive] positions on that natural gas in the facility. So that will expire, the ones that we put in let's say for March of this year but as they expire and we don't withdraw then we put on let's say December through March hedges thereby locking in a margin.

So we don't take [predictive] positions with respect to that gas.

Sorry guys. I jumped off just temporarily there.

My question and someone also might have already asked it but Kelcy, just wanted you to kind of talk just generally speaking. OKS has announced, obviously 75,000 a day of frac.

You guys on 100 and EPD just finished one and is talking about another but. Just the overall supply demand dynamics and you know, is this kind of put us into another capacity situation or is there just adequate demand that you guys see it over the next couple of years?

Thanks.

Yeah, you bet, Ross, it's a very good question and I really appreciate it, and time we will overbuild and then we will be challenged for capacity, and we will overbuild again. That’s what our industry does and we are very, very good at it.

We can't seem to learn our way through the process. We've done that in the natural gas pipeline business and you can see several of our peers are having discussions of converting natural gas line into crude or liquid service.

And hence it becomes the overbuild capacity. I believe that we've got ways to go on fractionation capacity before we get overbuild.

Yes, I do. I believe we've got a long way to go.

But it will ultimately happen. To go back to Mackie's comments, that is why we are structuring our contracts in a fee-based manner and we are structuring them in a long-term tenure as well.

Great. Well, thanks everyone.

As you know, we have exciting times over here. We look forward to a lot more growth that comes from the partnership.

Thanks for you time this morning.