Welcome to the Energy Transfer’s second quarter earnings conference call. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session towards the end of today’s conference. (Operator instructions) I would now like to turn the presentation over to your host for today’s call, Martin Salinas, Energy Transfer’s Chief Financial Officer. Please proceed, sir.

Thank you, operator, and good morning and welcome to our second quarter earnings call for 2010. We issued our results this morning before the market opened, and I’ve decided to talk about them along with some positive trends that we are seeing, primarily in our transportation volumes and basis differentials. We'll also give you an update on our FEP and Tiger projects; they are getting closer and closer to completion. I’ll also make a few comments about EPE and how its new ownership of Regency has coming along. As in the past, I'll make forward-looking statements within the meaning of Section 21-E of the Securities and Exchange Act of 1934, based on our belief as well as certain assumptions and information available to us during this call. Kelcy, Mackie, John McReynolds and other members of our senior management team are here with me to answer your questions. Before I go through our second quarter results, I would like to highlight a few things that have positively impacted ETP. In addition to seeing an uptick in our quarterly EBITDA of roughly 25% from this time last year, we are seeing some nice volume increases across our system compared to the latter part of 2009 and early 2010. Our Barnett shale volumes alone have increased 0.5 Bcf a day and we expect an additional 200 million cubic feet a day to 300 million cubic feet a day by the end of this year. All in all, our transportation volumes are up over 1 Bcf since the fourth quarter of 2009. Natural gas prices have also increased from this time last year and we are recognizing better margins as a result of the increase. As we stated in our first quarter call, we have had a significant portion of our commodity risk exposure in 2010 and 2011 at effective levels and certainly much higher than what we’ve realized in 2009. In addition to the increased volumes and natural gas prices, we are now seeing basis differentials significantly wider compared to the last fall and earlier this year. During the quarter alone, we saw differentials go from an average of $0.08 in April to $0.14 in June, meaning we expect to get a full quarter’s worth in our third and fourth quarters. From a capital project perspective, FEP and Tiger have entered the construction phase and we are well on our way to bringing these two pipelines in service ahead of our original schedule and significantly below our initial cost estimate. FEP is slated for a fourth quarter 2010 in-service date and Tiger’s original capacity of 2 Bcf is on target for Q1 of 2011 with a planned expansion of 400 million cubic feet a day to occur in the latter half of 2011. I'd also like to remind everyone that these projects are supported by minimum of 10-year 100% demand fee contracts. Also each one of the construction related agreements have been executed on fixed cost basis. In addition to FEP and Tiger, I would like to bring up to speed on a number of other growth initiatives that we are pursuing. In the Haynesville, North Louisiana area, we are currently gathering and transporting over 200 million cubic feet a day and expect to exceed 300 million cubic feet a day by the end of this year. These assets will be bringing gas to the Tiger pipeline when it comes online. In addition in East Texas, as we announced, a 52-mile [ph] project predominantly consisting of a 24-inch and 20-inch pipe that is expected to be completed by the fourth quarter of this year, we expect volumes to exceed 1 million cubic feet a day on this pipeline by the end of the first quarter of 2011. In Eagle Ford Shale, we are pleased to announce a 50-mile pipeline of predominantly 24-inch in South Texas. The system and gather rich gas for initial delivery into a processing plant and capacity will be in excess of 350 million cubic feet a day and we anticipate volumes to grow rapidly throughout 2011. Both the East Texas pipeline and our system in the Eagle Ford will tie into our existing HPL System. In the Marcellus shale, we expect to be flowing gas by the end of the third quarter with initial volumes of 40 million cubic feet a day and growing to 100 million cubic feet a day by the end of the first quarter of 2011. And as we announced in May, as part of the Regency transaction, we contributed a substantial ownership interest in MEP to ETE in exchange for 12.3 million ETP units that ETE owns. This provided us with a tax efficient method of transporting MEP and allows for future growth projects to be more accretive due to the reduced number of ETP units. It goes without saying that ETP’s management team is very excited not only about the status of existing projects but the incremental distributable cash flow coming from them, but also about the opportunities for strategic growth primarily in the prolific shale plays where our assets are located. Looking to our results; second quarter’s adjusted EBITDA was $335.6 million, an increase of 25% over the second quarter of 2009, and distributable cash flow was $200 million compared to $134.6 million for the quarter ended June 30 of 2009. Note that beginning this quarter, we have revised our definition of adjusted EBITDA to include an adjustment for unrealized gains and losses on commodity risk management activities. Adjusted for these activities have been included in our reconciliation of distributable cash flow and with this change are now included in the reconciliation of adjusted EBITDA. The adjusted EBITDA for prior periods have been revised for this change as well to allow for comparability between the periods. With respect to distributions, we will pay our quarterly distributions of $$0.89375 per common unit; that’s $3.575 on an annual basis to our unitholders on August 16. And we continue to see positive momentum to return to distribution rate growth in the very near future. Turning our attention to our operating results by segment, and I’ll begin with our intrastate transportation and storage operations. Operating income for the quarter was $127.8 million compared to $156.9 million in 2009. Our results for the quarter were impacted by lower transported volumes than we saw a year ago combined with lower basis differentials across Texas. This is resulted in $24 million less margins from transportation fees. For comparisons, basis differences between the Waha and Houston Ship Channel markets averaged $0.45 per MMBtu in the second quarter of 2009, but only averaged $0.12 in the second quarter of this year. If you recall, we started to see volumes declining starting in the middle of last summer as natural gas prices were falling and basis differentials tightening. The good news is that we're seeing better differentials, particularly towards the end of the quarter and into July and August and expect this trend to continue. And as I mentioned earlier, we are seeing volumes picking up too. On a year-to-date basis, transportation fees were down $58.6 million compared to the prior year which is also due to lower volumes and basis differentials that averaged $0.54 per MMBtu the prior year compared to only $0.08 so far in 2010. Our storage margin also decreased $14.6 million quarter over quarter, primarily due to a less of a change in the price difference between the spot price and the forward prices. As a reminder, we apply fair value hedge accounting for the natural gas we have in storage and adjust the carrying amount of the physical inventory to the spot price at the end of each period. On a year-to-date basis, storage margins decreased $23 million, despite larger withdrawals in the current year, primarily due to a less of a change in price differences between the spot and forward prices. Most of the margin that we realized for natural gas withdrawn during the first quarter of this year have been previously recognized through fair value adjustments in prior periods. As a note, we have shown the impact of these non-cash items in our adjusted EBITDA and DCF tables in our earnings release filed this morning. With respect to our Bammel storage facility, we have increased the amount of storage capacity contracted under fixed fees to approximately 25 Bcf from 22 Bcf this time last year. Combined with our Bethel and Bryson caverns, that puts us at about 50% of our storage capacities locked up under fee-based arrangement. After withdrawing substantially all the natural gas being managed for our own account in the first quarter, we have approximately 19 Bcf that we intend to withdraw in the upcoming winter months. Offsetting these margin decreases in our intrastate segment were reduced operating expenses and favorable impacts from pipeline system optimization. As we continue to see commodity price volatility, we remain proactive on the hedging front. We’ve hedged substantially all of our estimated volumes in 2010 at an average Nymex price of around $5.48 an MMBtu, that's an increase of $1.94 from our 2009 average price, and we've hedged a substantial percentage of our 2011 exposure. Currently we've hedged approximately 85% of our anticipated volumes in 2011, primarily with collars to have a floor of $5.50 and a ceiling of $7.50 per MMBtu, and about 15% is in Nymex contract at an average price of $5.46; and we have our eyes on 2012 already. Moving to our interstate operations, which currently represent our Transwestern activity; operating income was $32.2 million for the quarter, which is fairly flat to last year; and $53.8 million for the six months, a 6% increase from last year. The year-to-date increase is primarily due to the completion of the Phoenix project in February of 2009. For the time that we own MEP during the quarter, we recognized equity and earnings of $3.4 million and $8.9 million for the six months ended June 30. As mentioned, on May 26, we transferred substantially all of our interest in MEP to ETE. As we look forward, our interstate operations will experience significant growth as we bring FEP and Tiger online and start to see those cash flows coming in. Now touching on our midstream results, which saw a pretty solid quarter; operating income increased $19.6 million due to the increased gathering and processing volumes and the continuation of a strong NGL environment. In addition, we recognized $5.8 million in fee-based margin from our recent acquisition and other growth capital expenditures in Louisiana. On a year-to-date basis, the $44.1 million increase was primarily due to higher gathering and processing volumes and the improvement in NGL prices from the first six months of 2009. In addition, approximately $12.2 million of the increase was due to fee-based margins from our Louisiana assets. We expect our midstream fee-based margins to increase as we continue to see volume increases in Louisiana and from the growth initiatives I spoke of earlier. Looking at propane, operating income decreased $11 million for the quarter and $48 million for the six months ended June as compared to the same period last year, and this is primarily due to the impact of mark-to-market accounting from our financial instruments in 2009 and slight decreases in volumes. Quick comment on G&A before moving on; we continue to keep a close eye on expenses and spend where necessary. This has resulted in lower G&A expenses for the quarter with expenses down quarter over quarter by $9.5 million and $16.5 million for the six months. From a growth CapEx perspective, we spent approximately $480 million in the second quarter. Of that, approximately $90 million related to our intrastate transportation and midstream segment, $383 million was spent in Q2 on Tiger, and the remainder was spent in our propane segment. As it relates to maintenance CapEx, we spent $24 million in Q2 which is spread pretty evenly across our segment. For the remainder of 2010, we estimate our capital expenditures to be between $200 million to $220 million for our midstream and intrastate segments, $550 million to $610 million in our interstate segment, and approximately $15 million to $25 million in propane. Maintenance CapEx is expected to be around $40 million to $55 million for the remainder of the year. Total growth CapEx for the full year of 2010 is expected to be between $1.37 billion and $1.46 billion and maintenance CapEx is estimated to be between $85 million and $100 million. With respect to FEP, we do not anticipate any capital contribution in 2010 as expenditures for FEP will be funded through a separate credit facility. As it relates to FEP from a spending perspective, we spent approximately $273 million during the quarter that have spent approximately $690 million since inception. Now these amounts are on an 88 [ph] basis. We do want to comment a little bit on liquidity before I move on to ETE. We continue to maintain our strong liquidity position with almost $2 billion in the available capacity under our revolver. We also raised an additional $150 million in net proceeds under our equity distribution program during the first six months of the year and we will continue to monitor capital markets to ensure we provide ourselves not only with the financial flexibility but to continue to maintain our commitment to keeping our investment grade metrics. That wraps up ETP’s discussion. I'd now like to discuss ETE’s results starting with the Regency transaction. As I mentioned earlier, ETE consummated a purchase of Regency’s GP interest, including 100% of the incentive distribution rights and exchange with interest in MEP that it obtain from ETP for approximately 26.3 million units of Regency. In addition to owning and controlling the GP above ETP and Regency, ETE also owns a 100% of the IDRs in both the MLPs and as the single largest unitholder of each partnership. We couldn't be more excited about the growth potential for ETP and Regency and what this means for ETP. In the last few months, working with the Regency team has confirmed our confidence in this transaction. From a cash flow perspective, ETE expects to receive approximately $95 million in cash distribution from its GP and IDR ownerships in ETP and approximately $45 million from the roughly 50 million ETP units it owns. These amounts do reflect the redemption of 12.3 million ETP units as part of the Regency transaction. And as it relates to ETE’s ownership in Regency, cash distribution from the GP and IDR interest expect to total $2 million and ETE will also receive $11.7 million from its LP unit ownership in Regency. In addition, there was a one-time pro rata settlement payment of $3 million to ETE during the quarter and approximately $13 million in transaction fees that were incurred as part of this Regency transaction. This explains large increase in G&A that ETE recognized during the quarter, and we do expect SG&A going forward to be more in line with what it had been in previous quarters. Regarding the distribution to ETE's unitholders, we announced a quarterly distribution rate of $0.54 per unit, that’s $2.16 per unit on an annualized basis. Excluding the one-time transaction fees, ETE maintained a slightly higher than one-time distribution coverage ratio to continue to allow the financial flexibility to refinance our existing debt, and the high yield markets have improved since we announced the Regency transaction back in May. In summary, we have a lot of great things happening here at Energy Transfer and starting to look forward to the future. With that, operator, let's going to Q&A. Thank you.

(Operator instructions) Your first question comes from the line of Yves Siegel with Credit Suisse. Please proceed.

Good morning guys. Just a follow-up real quick, Martin you mentioned the Marcellus. Could you just remind us how you're looking at the Marcellus and perhaps where the 40 million cubic feet a day of gas was coming from?

Yves, I’ll let – Mackie is here with me. I’ll let him comment on that one.

Yes. Everybody probably knows, we got started about 1.5 years ago up there and finally getting and some momentum. Our first project is in West Virginia. We haven't fully disclosed that because of the confidentiality agreements with the producer, but we are optimistic about expanding that system and really beginning our growth in the Marcellus.

So Mackie, is that primarily just dry gas that you guys are looking at?

Yes. Well, no; not that we look at that deal as dry gas –

I didn't mean to ask you a leading question there.

Well, also, of course in the Marcellus, we are focusing on gathering gas in Pennsylvania and also moving on some water projects in combination with that. And we are very optimistic that we will be announcing something hopefully in Pennsylvania.

And then just the last question, could you comment on what do you think is happening, the factors behind the widening on the basis differentials? Is that just coming back to normalcy or is there something else that might be going on?

I think we are seeing a combination of things. Weather is certainly the main driver or a driver because – so wild out west and so much hotter in the east. Also there is a lot of gas kind of backed up even on the (inaudible) which pushes gas down into the midcontinent, including Waha. So there is a combination of factors, but certainly we are seeing a weakening of the basis and we don't see any indication of it tightening up any time soon.

Thanks, guys.

Yves.

Your next question comes from the line of Darren Horowitz with Raymond James. Please proceed.

Yes, good morning guys.

Hi, Darren.

Martin, first question; I was hoping to get a little bit more color on the volume ramp you detailed out of the Haynesville. In particular, we're hearing about a lot of wells that have been drilled but not completed in that area due to lack of stimulation and frac services. I'm just curious for some more color when you talk to producers. Are they discussing this? And ultimately what could completion deferrals mean to your throughput there?

Yes, I’ll let Mackie comment on that.

Yes, fortunately most of our business, both the upstream and our Tiger Pipeline project are fee-based with the demand charges. We are not as impacted by that. Certainly that has been something more concerning to producers than drilling rigs. But as far as we know and what we're seeing in our systems is pretty consistent volume growth, and we believe the volumes will be fully available when Tiger comes online next year.

And Mackie follow-up from me on the heels of Yves' question, when you look at this expansion basis, can you quantify what it could mean for us either volumetrically or in terms of gross margin relative to how much you guys are hedged? Is it going to have that much of a material impact on your cash flow?

Yes, Darren. As we looked at (inaudible) from a commodity price exposure, we've done a good job of getting the retained fuel components off the table with what I mentioned in terms of the volumes that we’ve hedged in 2010, 2011 and I mentioned was down focusing on 2012. From a basis differential perspective, we have – I think as we have stated in the past, somewhere in the 75% to 80% of our interstate volume are hedged under some type of fixed fee – demand-fee type contracts. The remaining 20% to 25% as we’ve kept opened for business, so to speak, on our burn, much shorter term capacity. And that's been a huge advantage for us and a big opportunity for us as we saw basis differentials widening like we saw prior to ‘08 and into ’09, certainly more upside to down side in terms of the basis differentials today. We’ve not hedged a significant piece of that open capacity as it gives us that opportunity to capture these amounts – these widening spreads. As to the margin impact, it’s not a big piece of our business today. I think it impacts more just volume throughput. We’ve not quantified what that is although we’ve have stated that our breakeven tad number is about $0.08.

Okay. I appreciate the color guys. Thanks.

Thank you.

And your next question comes from the line of Ted Durbin with Goldman Sachs. Please proceed.

Yes, thanks. Just wanted to check in again on the Tiger project. I think previously you said you're coming in low budget. Are you still looking to come in – is there any more flexibility there? You might come in even lower, on budget and same thing on FEP, kind of where are the costs and the timing coming in?

Yes, Ted. This is Martin. On Tiger, as we’ve talked about in our first quarter, we revised our budget – our estimate numbers on Tiger downwards, which we feel very confident about. We’ve entered into fixed cost contracts with our customers and also with the construction companies. The project is going very well, obviously from a commercial perspective and we’ve now entered into the construction phase. The numbers are conservative in our view in terms of what we’ve estimated from a cost perspective. There is opportunity to see a number below what we have today. But we’re just at the construction phase and given our experience in building these pipelines, we want to err on the conservative side today and come back to you in a couple quarters telling you we beat that number. So there’s surely some upside to getting inside of what we have out there today. On FEP, same scenario there. We are well into the construction phase of that project. We did revise our estimates again in the first quarter and same scenario as with Tiger, less a little bit of a cushion for us as we go through construction. Again, it allows for us to be at that number or below that, so certainly some upside there as well.

Okay, great. Thanks very much. And then if I could just ask sort of bigger picture, if you're looking at all the producers and the way all of the drilling is shifting more to the wetter plays, is there anything you can do to really take advantage of that shift in the drilling economics?

Sure. We are – you are talking about drilling the richer gas, you mean?

Yes.

Yes. We are, we haven’t really made announcements yet. You’ve heard of today publicly that we are expanding our system in South Texas for the first time in a while to gather rich Eagle Ford gas. We are also seeing some momentum even in the Barnett shale where the producers – certainly in some areas it is down, but it has picked up fairly dramatically in the rich portions of that play. And we continue to look for other opportunities where there is rich gas gathering, including the Granite Wash.

Okay. That’s if from me. Thanks a lot.

Thanks, Ted.

Your next question comes from the line of Michael Blum with Wells Fargo. You may proceed.

Thanks. Good morning everyone.

Good morning, Michael.

Hi, Mackie, maybe just while you're talking about South Texas, to the extent that you're willing to is it possible to provide – and I apologize if I missed it, but what type of capital do think you're going to deploy there, kind of what the timing is and what sort of returns we should think about?

Yes, Michael, this is Martin. We’ve not provided detailed information on what we are doing in South Texas. Some of that is driven by some confidentiality clauses that we have with producers we are working with. Today, however, I will say that embedded in the revised cost estimates are our numbers to include – our cost to include both the East Texas pipeline that we announced during the quarter as well this pipeline in the shale. So I know you can do the math and get pretty close to what that’s going to be. From a multiple perspective in line with what you’ve seen from the month of delivery kind of in the five to seven times multiple range for those with an upside potential and we look to build off of that extensively.

Okay, great. My second question was, you are now at about 50% on third-party fee-based contracted natural gas storage. What is the thought in terms of how far would you like to push that if you can? And if you are looking to expand the third-party lease piece of that business, what does that environment look like? What are rates looking like?

Absolutely. We’ve stayed on the same track we’ve also had with storage and that’s hedging as much of that as possible meaning selling to third parties. The margins came into areas where we weren’t comfortable with expanding but we are always in negotiations and we are certainly are very excited about some opportunities that LNG may impact storage need, especially in South Texas. So we will continue to not only market that storage or look to market that storage towards a long-term agreements, but also marry that up with up and downstream revenue on our existing system. Margins are pretty tight right now, that’s why we are not interested in selling it long-term, but we are very optimistic about those widening in the future.

Thank you very much.

Thanks, Michael.

Your next question comes from the line of John Edwards with Morgan Keegan. Please proceed.

Yes, good morning everybody.

Hi, John.

Hi. Can you just remind us, what are the announced budget numbers for Tiger and FEP?

For FEP, I believe announced have been $1.225 billion, it’s on an 88 basis John. Tiger, $1.1 billion and that’s for the initial 2 Bcf a day and another 190 million to 200 million for the expansion that will come on latter half of 2011.

And you're expecting to come in below those announced budgeted numbers?

You're not in our room but Kelcy is nodding his head profusely with a yes.

Okay, all right. And then you are mentioning your basis is widening here. Any thoughts you could provide us as far as what your outlook is for basis for the rest of this year or perhaps into next year?

Sure. Because of a number of factors drilling is picking up all over Texas and some other things are going on. We, as I said earlier, are very optimistic that basis will continue to widen, especially as you get into that shorter month it typically does. So we are seeing a much more likely trend of widening than the narrowing we saw for the last year and a half.

Okay. Any kind of magnitude you can assign to that?

No. It’s hard. We feel like it’s going to continue to be weaker or widened compared to where it is today.

Okay. And then I don't know if you can talk about this, I just – if you say you can't talk about it, just ballpark what kind of – can you talk about what kind of capital you're putting to work in the Marcellus shale area?

The initial project is $35 million. However, we do have some water projects we're working on, probably in the neighborhood of $50 million if we are able to consummate those, and as I mentioned we are in negotiations with a number of other parties that we are going to announce later if we are successful.

Okay, all right. You were talking about the hedging number. Are you basically fully hedged now for this year and next for your gas processing?

Well, it’s not much for the processing, it’s more for the retained fuel, and in some of the well head production it comes into our midstream and then HPL lines. From a processing perspective, we’ve not hedged any of that.

All right. That is all I have. Thank you very much.

Thanks, John.

Your next question comes from the line of Ross Payne with Wells Fargo Securities. You may proceed.

Thank you. You guys have done a really good job cutting down on your SG&A expenses year-to-date and for the quarter. I just wanted you to kind of opine on how you are achieving those cost reductions. Thanks.

Yes, Ross. It’s a number of things; focusing on the low hanging fruit in terms of daily cost, looking at as we continue to add to the systems on a miles perspective, not doing so on a headcount perspective. We looked at some budgets. We looked at where we can reduce costs across the board from a headcount perspective, pushback on a lot of our vendors and services area. So, done a lot of that; not to mention the fact that the FERC issue was a big cost drain on the partnership and on our unitholders and fortunately we are behind that as well. So that also had an impact. So that is really – no science of it other than just keeping a close eye on our checkbook.

Okay. Thanks very much.

Your next question comes from the line of Kent Green with Boston American Asset Management. You may proceed. Mr. Green, your line is open. Your phone maybe muted. Your next question comes from the line of Gabe Moreen with Bank of America/Merrill Lynch. Please proceed.

Hi, good morning everyone.

Hi, Gabe.

A couple – three-part question if I could on South Texas. I know you are reluctant probably to divulge too many details, but the 5 to 7 times return that you're targeting there, does that include a significant component in handling the gas downstream on HPL? Number two, I don't know if you mentioned this as dry or wet gas that you are going to be handling, but if it is wet gas are you guys providing a processing component anywhere? And maybe I'll save the third part for after the first few.

Yes, it is rich gas we will be gathering in that project. And we do have a home for that gas up to a certain extent at some processing facilities and we're looking at a multitude of options as we expand that system and expand our reach into the Eagle Ford.

And then the returns, does that contemplate making some margin on HPL downstream as well?

Yes. Everything we get back in that system as well as our East Texas system that Martin spoke about earlier, all these hopefully tie into our either intrastate or interstate system. So, yes, you can count on additional revenue downstream.

Okay and then bigger picture, your ability to I guess win that project relative to some other MLPs out there competing for packages of gas, I guess can you talk about maybe what positions you best there given some of the other legacy positions there and whether you feel this project potentially could be a beachhead for additional Eagle Ford opportunities?

Yes. No doubt it does. We're not a big processor as of today. There is a great need of processing down there. We can piggyback some processing arrangements we have today while we're building cryos when that decision makes sense. Also, there's not a whole lot of lean capacity out of Eagle Ford. So whether it’s tailgate gas from the plants treating or processing this gas or lean Eagle Ford becomes in the system, we do feel very confident about the future of filling up and expanding our South Texas systems.

Okay. Thanks very much.

Thank you.

Your next question comes from the line of Helen Ryoo with Barclays Capital. Please proceed.

Thank you. Good morning.

Good morning, Helen.

Good morning. I had a question on your East Texas Pipeline, the 63-mile line. Is that a mainly transportation line without gathering? And you talked about I think contracts have 10-year agreements. Is that – any components of that have demand charges?

Yes, either demand charges or true-ups at the end of the year. But that is a little bit of 16-inch, but predominantly 24-inch and 20-inch pipelines that also will connect to our HPL system. It’s primarily transportation – fee-based transportation.

Okay. Does it connect with Regency's East Texas system by any chance?

No, it does not.

Okay. And then another question was, maybe I haven't – I didn't hear this correctly, but did you say you added to your basis hedge taking advantage of – I mean, you have seen a wider basis. Was this an opportunity to add to your basis hedges?

Yes, Helen. This is Martin. I said that we have not done much in the way of basis. We have checked the box on the retaining fuel. And part of the rationale on the basis is that given it was so low there was more upside potential than basis going to zero, which we had experienced in late 2008 – I am sorry, late 2009, early 2010. We are evaluating that today given where basis differentials have widened even relative to where we were at the end of June 30 to where we are today. So that is something that we are evaluating. And line of what Mackie mentioned here in terms of our thoughts, you might see some of that here over the next six months. But that's something we are looking at today.

Okay. Thank you very much.

You’re welcome.

Your next question comes from the line of Barrett Blaschke with RBC Capital Markets. Please proceed.

Hi, guys. Just a quick question. Any thoughts on IDR splits, restructuring the GP at this point?

Barrett, this is Kelcy. No, obviously we're studying what our government is doing and potential tax consequences that might suggest we would look at that, but at this time we are not looking at that and really in any depth.

Okay. Thank you.

Your next question comes from the line of Jeremy Tonet with UBS Warburg. Please proceed.

Hi, good morning.

Good morning.

I think most of my questions have been answered, but I just want to touch on the midstream natural gas volumes. It seems there's a bit of a decline from a year ago and I just wanted to know if you could comment on that a bit.

Yes, Jeremy. This is Martin. Some of those volumes come from – we have a small marketing arm within midstream that takes up space and capacity in our pipeline. A lot of that is going to be driven by just what the market is doing. Primarily from a basis perspective if we use that marketing to fill up any excess pipe or any excess capacity in our pipe. So given the basis trend that we saw late in ’09 and early 2010, there is not much of an incentive to move gas across the system given the lower basis differential. So that’s what you are seeing from a natural gas sold perspective on our midstream, but I think as you see from a liquid perspective from third-party producers where rich gas is coming into the system are getting processed, we are seeing the positive impact on our business from that.

Okay, because it seemed like the interstate volumes held in a lot better than midstream, so I didn't know if there was any different dynamics happening there.

No. That is pretty much, again, on the midstream side from marketing perspective, you are seeing that on the intrastate. Given the diversity of our customer base there, it is not surprising that it withstood a little bit better.

Okay, great. Thanks.

Okay.

And with no further questions, I would now like to turn the call over to Mr. Martin Salinas for closing remarks.

Great. We appreciate everybody's time this morning. Everybody have a great week. Thank you.

Thank you for joining today’s conference. That concludes the presentation. You may now disconnect and have a great day.