Good day, ladies and gentlemen, and welcome to the Energy Transfer Partners conference call. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. I will now turn the presentation over to your host for today’s call to Martin Salinas, Chief Financial Officer. You may proceed.

Thank you and good morning everyone. Welcome to our third quarter earnings call for 2010. Similar to our previous call, I will walk through a few numbers with you related to our third quarter results, which were in the release we issued this morning, in addition to providing an update on some of the projects we recently announced, along with a few other items impacting our partnership. We’ll then go in to Q&A. I’ll be making forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on our beliefs, as well as certain assumptions and information available to us during this call. As always, Kelcy, Mackie, John McReynolds and other members of our senior management team are available to answer your questions. As I said earlier, I’ll cover some of the drivers related to our results for the quarter, but before I do, let’s talk about the significant growth projects being completed within the next few months. First and foremost, we’ve been talking the talk and now it’s time to walk the walk. Both FEP and Tiger are set to come online in less than a month from now, December 1 to be precise, and we couldn’t be more excited inside of our accomplishments. As we stated in yesterday’s release, not only are we way ahead of schedule, but we also expect our total cost for both projects to be significantly less than our original cost estimates, and even lower than our most recently provided estimates, thereby making these two projects even more accretive than what we had originally thought. These two projects are going to provide significant stable cash flow from demand fee contract and they are also going to have a deleveraging impact on our credit metrics going forward, something that, as you know, we continue to be very committed to. In addition to bringing on our interstate pipelines, we also recently announced two separate projects that we are embarking on in the Eagle Ford Shale. The Dos Hermanas project, one that we mentioned in the second quarter call back in May, is approximately 50 miles of 24-inch pipe, which will deliver gas to our HPL-rich system. The capacity will be approximately 400 million cubic feet a day when we bring it online in December of this year and we anticipate volumes to grow rapidly throughout 2011. The other pipeline project we announced was the Chisholm Pipeline, which is approximately 83 miles of 20-inch pipeline, which will deliver gas to our LaGrange processing facility in Southeast Texas. After processing the residual volumes will then be transported into our Oasis Pipeline. This pipeline will have an initial capacity of 100 million cubic feet a day and is expected to be in service by the second quarter of 2011. Future expansion projects could bring the total capacity of this pipeline to 300 million cubic feet a day. It goes without saying that we are not done in the Eagle Ford Shale as we continue to meet with our existing producers and also potential new customers to provide additional solutions out of the area. There is no question that we intend to be a leading provider of Midstream services in the Eagle Ford. Moving to some of the other areas where we are seeing more growth as well. Starting with our East Texas pipeline, where it is still expected to be completed by the end of the year and we anticipate volumes to exceed 100 million cubic feet a day by the end of 2010 or early 2011, with volumes expanding through 2011. In North Louisiana, the Haynesville Shale, we continue to see volume growth in this area and still expect to exceed 350 million cubic feet a day by the end of the year. As we look beyond 2010, you could see our volumes in North Louisiana average between 450 million and 500 million cubic feet a day in 2011, as producers continue their drilling programs. In the North East, we started flowing initial volumes on our pipeline in the Marcellus this quarter and still believe that they will grow to nearly 100 million cubic feet a day by the end of the first quarter of 2011 and 250 million cubic feet a day by the end of 2011 year. Let’s now talk about our results. Our third quarter adjusted EBITDA was $280.5 million, a slight decrease from the third quarter of 2009 and distributable cash flow was a $160.5 million for the quarter, an almost 10% increase compared to the quarter ended September 30, 2009. With respect to our distributions to our unitholders, we will pay our quarterly distribution of $0.8938 per common unit, that’s $3.575 on an annual basis to our unitholders of record on November 15. As we bring online FEP, Tiger and some of the other pipeline projects I just mentioned and start to see a cash flow from them, we will be looking to increase our distribution rate commensurate with our policy to manage our distribution coverage ratio at around 1.05 times or so. With that let’s look at what impacted our third quarter results beginning with our intrastate transportation and storage operations. These are, our Interstate transportation volumes continuing to increase, growing 19% from 11.1 Bcf a day in the third quarter of 2009, just a little over 13 Bcf a day in the third quarter of 2010. Our intrastate operating income for the quarter was $133.8 million compared to almost $110 million in the third quarter of 2009. As a result of the increased transportation volumes, our fees increased $10 million, primarily driven by our customers’ need for transportation capacity combined with the more favorable basis differentials across sectors. Despite the improvement in basis differentials though, we were negatively impacted this quarter by our Oasis pipeline been down in late July and August for repairs. We also had a favorable retained fuel variance of almost $7 million, driven primarily by higher realized natural gas prices this quarter. I would remind everyone that we have significantly hedged our estimated retained fuel through the remainder of 2010 and in 2011. Our intrastate results were also favorably impacted by our storage activity albeit from a mark-to-market perspective. For both the three months and nine months ended September 30, 2010, the spread between the spot price and the forward price narrowed relative to the prior year resulted in a favorable impact to our storage margin under hedge accounting compared to the same period in the prior year. As it relates to Bammel storage facility, we have approximately 22 Bcf contracted under fee based contracts, which puts us at about 50% of our storage capacity locked up under fee based arrangements. As of September 30, we had approximately 23 Bcf in the ground that we intend to withdraw on the upcoming winter months. Let’s now discuss a few points related to our Interstate operations. Operating income for this segment was $34.6 million for the quarter, which is a decrease of $7 million in the third quarter of last year and operating income was $98.3 million in the nine months of 2010, a slight decrease from the same period last year. For the third quarter, revenues in op volumes were up due to favorable market conditions, but were offset by increased operating expenses, primarily higher ad valorem taxes related to the Phoenix pipeline that as you know was completed last year. However, with the near completion of FEP and Tiger, we expect to see significant increase in our Interstate segment’s financial results in the quarters to come. Turning our attention to our Midstream operations where we continue to see very strong results with increases in volumes gathered, treated and processed primarily through our Godley plant. Our operating income increased $9.4 million in this segment due to increased gathering and processing volumes and the continuation of a strong NGL environment. In addition and similar to what we experienced in the second quarter of this year, we recognized increased fee based margins from the acquisition in Louisiana early in the year as well as growth capital we’ve invested in the area. On a year-to-date basis, the $58.4 million increase is primarily driven by the higher gathering and processing volumes and the improvement in NGL prices. We also see strong growth in this segment due to the recent growth projects announced as well as the continued strong NGL environment that we believe will promote further opportunities. Offsetting the increase is other Midstream margin decreasing by $14.9 million for the quarter compared to a year ago principally due to less favorable market conditions. Looking at our Propane segment, where and as a reminder, the second and third quarters are typically our weaker quarters due to the seasonality of the business, operating results improved $3.5 million for the quarter despite the decrease in gallons sold. Our Propane team continues to manage these operations very well despite the challenges caused by the economic growth recession and the customer conservation. Before we move on to some of the balance sheet and CapEx numbers, quick comment on our SG&A expenses where we did see an increase quarter-over-quarter. This increase was principally driven by reduction in bonus approvals that we made last year. From a growth CapEx perspective, we invested a little over $400 million this quarter. We spent about $300 million on Tiger and approximately $95 million go into our Intrastate Transportation and Midstream segments with the remainder of stats in our Propane segment. Our maintenance CapEx for the quarter was roughly $26 million. As we look at our fourth quarter of 2010, we estimate our capital expenditures to be between $75 million and $125 million for our Midstream and Intrastate segments, $200 million to $270 million in our Interstate segment and about $10 million to $20 million in our Propane operations. We also expect our maintenance with CapEx to be between $25 million and $40 million for the fourth quarter of this year. What we have announced growth CapEx for 2011 is estimated to be between $100 million and $200 million for our Midstream and Intrastate segments, about $180 million to $225 million in our Interstate segment and approximately $25 million to $35 million in our Propane operation. As it relates to our maintenance capital expenditures for the year of 2011, we expect that to be between $120 million and $140 million and given the new FEP cost estimates, we really don’t anticipate any capital contributions to FEP in 2010 as these expenditures will be funded through its separate credit facility. Now, touching on our liquidity position and then we will go into ETE. During the quarter, we executed at roughly $490 million overnight equity offerings in August of this year with the proceeds being used to fund our growth CapEx but also managing our leverage ratio. We continue to maintain our strong liquidity position with almost $2 billion of available capacity under our revolver as of September 30. It allows us to fund our growth CapEx through 2010 and well into 2011. As a reminder to everyone, this facility has not only the lowest cost of capital, but also doesn’t expire until mid-2012. We are also very pleased to announce during the quarter that S&P changed their rating outlook on ETP back to stable. As you know, we will continue to manage our operations and endeavors to ensure that we maintain our investment grade, credit ratings. Before going to Q&A, I do want to make a few comments about ETE. After several months of closely monitoring the high yield markets, we successfully executed ETE’s refinancing of a Term-B facility in September 2010, with the completion of an offering of 1.85 billion of 10 years senior notes and got the rate we were holding out for that being the 7.5%. In addition to paying off the Term-B loan and extending our maturity profile from 2012 to 2020, we also used the proceeds to repay borrowings under the old credit facility and approximately a $169 million in breakage cost associated with the interest rate swaps. Concurrent with the refinancing, we also entered into a new $2 million revolving credit facility that expires in 2015, and currently have the entire facility available for borrowing. As it relates to distributable cash flow, ETE had approximately $125.2 million for the third quarter and it excludes the swap breakage cost and takes into account the additional cash inflow from ETP and Regency’s equity offerings that were both done in August. Regarding distributions to ETE’s unitholders, we announced a quarterly distribution rate of $0.54 per unit, $2.16 per unit on an annualized basis. Excluding the termination of the interest rate swap agreement, ETE maintained a 1.04 coverage ratio for the quarter ended September 30, 2010. Now that we have the refinancing behind us, we do intend to get back to the 1 times coverage ratio going forward. In closing, we are very focused on growing our operations and delivering on our commitment to increasing unitholder value. The completion of FEP and Tiger, coupled with new extensions being built on our existing pipeline, will transform ETP into a much stronger partnership than what it is already today and one that will continue to provide unequivable energy services to our customers in many of the existing and newly discovered producing areas in the United States. With that operator, let’s open the lines for questions.

(Operator instructions) And your first question comes from the line of Darren Horowitz with Raymond James. Please proceed.

Hey, good morning, guys and congratulations and SEP and Tiger arriving ahead of schedule and under budget. Martin, first question on the Eagle Ford, as you think about the Chisholm Pipeline announcement and the expected volume ramp across that line, how much excess capacity do you have at the.. LaGrange plant and how do you think about not only expanding capacity there but also the potential to expand capacity on the Oasis system?

I’ve got Mackie here with me. I think he’d probably be a better person to answer that.

Today, we have approximately 100,000 of capacity available. We are moving forward on a bunch of different options to expanding that sooner than later. As far as the Oasis we have enough capacity right now to handle that 100,000 a day, but we are continuing to do studies on possibly adding additional compression to increase that capacity.

Mackie, shifting gears over to Marcellus, how do you think about leveraging Bobcat and Jarvis [ph] lines in that area in order to establish a more diversified footprint, maybe become over time more vertically integrated?

That’s exactly what’s happened. As we completed those, other producers that have acreage around those systems have come to us and we believe with additional volumes and what we’ve already accumulated there, that it will help us expand to the North, probably all the across into Pennsylvania and provide a fairly significant header system to northern part of West Virginia.

Last question from me as it relates to Midstream, La Grange and Godley, as you guys look at your contract arrangements there, just on a rough percentage basis, where do you expect to be as it relates to composition fee based and then into 2011, how do you look at fee based versus the potential for any POL or POP?

At Godley, the vast majority, we have very little keep-whole probably about 10%. As you know, producers have taken a very strong position with processors on depending as much as upside is possible in liquids. From my standpoint we missed the upside, but we don’t have to worry about where liquid process will go in the future, but we pretty much will negotiate terms that the producers are looking for. It means POL or POP or keep-whole whatever they are asking for we’ll negotiate accordingly. LaGrange we have a mix, where we have certain percent as keep-whole, certain percent of POP and I believe that approximately 40% POP and we don’t anticipate that changing other than volumes coming in from Chisholm to LaGrange will be more fee-based.

Darren, just to remind you we do have bypassing capabilities so unlike some of our competitors, we can bypass the plants and still blend it downstream, which gives us that floor to do well.

All right. Okay. Thanks for the color, guys. I appreciate it.

Thanks, Darren.

And your next question comes from the line of Steve Maresca with Morgan Stanley. Please proceed.

Hey, good morning, everybody.

Hey, Steve.

Couple of questions. First on the Midstream segment. You mentioned the gross margin decline, I guess, $14.9 million due to less favorable market conditions. Can you just give any more color or detail on what that means and what were those less favorable conditions that drove that?

That’s really going to spreads and the opportunities to move gas across our system. We have got a small marketing arm embedded within the Midstream business. They take advantage of opportunities as the market presents themselves. Looking at last year, when we started with a strong natural gas and base differential environment, in the third quarter of 2009, obviously, that came to a screaming halt at the end of the third quarter and early part of the fourth quarter. This quarter, while we did see a little better improvement in basis differentials, not what it was at the beginning of last year’s third quarter, not to mention the fact that gas prices have continued to hover in the 3 to 3.5 range for much of the third quarter of this year and we didn’t see that drop in gas prices for the end of the third quarter of ‘09.

Switching gears on the pipe CapEx side, you obviously had a lot of success with Fayetteville and Tiger. What caused a lot of that reduction in cost? What does this mean going forward for some of your other projects? Is it something that whatever you did here apply to future projects?

Really a number of things; one, we approach this very cautiously because of what had occurred in the industry through many of the players over the previous two or three years. We approach this very aggressively though from the standpoint of instead of asking for an EIS, we went to FERC and asked for an EA, because not only that save time but also save millions of dollars. We also had the opportunity to negotiate very favorable construction contracts that turned out to be more favorable than we thought when we signed them as far as capping any type of risks related to what others had experienced in previous years. And then more than anything, we put an incredibly efficient and professional team together that has done a tremendous job in meeting the expectations that we set for them and really exceeded expectations that we set for them because of the way they conduct themselves and because of their communication with all the regulatory bodies being the Corp. engineers, FERC, etc.,

Steve, Mike is being humble. We are the best to put pipe in the ground and that’s actually we’re going to put that to the test on these other pipeline projects. Again, just given our experience, our know-how and our relationships with the construction companies on getting these pipelines in the ground and certainly from the producers’ perspective, giving them the confidence that when we tell them we will meet this timeline, by God, it’s going to be met.

Final question on ETE, you mentioned the $1.04 pro forma coverage. I wanted to get back to one, it is fair to say with the bond deal behind you and that swap cost behind you next quarter is something where you would be looking to increase again at ETE?

Well, we’re going to take into account full quarter’s interest cost on that new bond of $1.8 billion, it is at slightly higher rate but as we mentioned, we took that to take the majority overhang off the table. We also had the full impact this quarter, third quarter, the preferred units that were issued to GE as part of the Regency transaction. So, we are going to go back to the one times, and if that the cash flow is coming in, into ETE given some of the things that are happening below at both ETP and Regency, then certainly that’s we’ll do.

Okay. Thanks a lot, guys. See you next week.

Thanks, Steve.

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

Hey, guys. Just on the Midstream side of the business, how do you see volumes looking in 2011 for your Midstream business? Is there any risk there and just kind of what’s your general outlook?

The trend that we’re seeing in several areas, primarily Northern Louisiana, in the Haynesville, East Texas and the Haynesville and Bossier and of course the Eagle Ford, we project, that volumes will grow fairly dramatically. For example, we’ve flown about 30,000 a day beginning of this year at the Haynesville and we’re today not capital flow through Tiger, today we’ve flown about 350,000 a day. We see that same type of growth in East Texas. We’re approaching 70 million to 80 million a day, should be in excess of 100 million by the end of the year. We expect that to continually grow throughout 2011. In the Eagle Ford, we’ve made several announcements, as you can imagine, all the MLPs are scrambling now, we anticipate making others and we do see those volumes growing fairly dramatically throughout 2011.

And then on the Interstate side, are there any other projects you’re considering here? Obviously Tiger and FEP when you can bring them under budgets and ahead of schedule are a good thing, any other places that you’re looking, or maybe look at getting into the interstate market?

Sure. We always have our (inaudible). We are in constant communication with the East Coast, with Florida, we are looking for opportunities to expand from Eastern Louisiana, Western Mississippi. That we think there are numerous opportunities in the future through the Marcellus. It’s a little difficult. We don’t have really a foundation there now, so we are little behind some of the bigger interstates that can do more in the interim on looping and adding compression, but we do anticipate hopefully beginning a project there some time in the future. And then we continue to look for opportunities as the demand growth increases out West, of looping and adding compression to our Transwestern system.

Okay, thank you.

Thanks, Barrett.

Your next question comes from the line of Yves Siegel with Credit Suisse. Please proceed.

Yes, good morning, everybody.

Good morning, Yves.

I have to tell you when Mackie talked, my eyes opened when he talked about Florida and going west and stuff like that. Just housekeeping number one, can you quantify how much Oasis might have cost you during the quarter?

Yves, on the operating expense, we had somewhere around $4 million to $4.5 million of additional operating expenses to cover the cost of the repairs associated with that. We had a number of producers, shippers, had to refund some money, it’s probably $2 million or $3 million. Least to say, the opportunity cost associated with not being able to take advantage of the basis differentials across the country. I mean across Texas, here in Texas we think we are our own country. We did move gas around the horns so to speak, given the ability to go up the NTP line and then back down from the east pipe. That’s an inefficient way of moving gas, which meant we had a little bit more compression. So this price tag that easily exceeds $10 million. We know they are hard dollars, which is what I just mentioned, but the opportunity cost is probably the one that’s a little bit harder to quantify, but could see that being in excess of $10 million this quarter.

When you look at the Intrastate and Storage segment the Intra segment revenues really moved higher quarter-over-quarter. Could you just explain that phenomenon?

Part of that is some of the marketing team does take some of the space both in the Bammel storage facility, as well as capacity on the pipe given some of the drop in volumes that we have seen over the last call it 12 to 18 months. They have taken little more than that. Again just to be able to fill the pipe as efficiently as possible. So you do see some of the intercompany segment across. Obviously, it’s left pocket, right pocket. That’s most of what happened here. I’d have to go into a little bit more detail. I can get with you offline on some of the other, but off the top of my head that’s mainly the driver there.

Lastly when you talk about growth CapEx for2011, could you give a little bit more detail around the numbers that you have there as you go through the segments. I think if you add it up around to that range is 450 and it sounds like perhaps that number could be lot larger depending on what you’re maybe thinking about? Also maybe could you also talk about the type of returns that you are attaching to the growth CapEx moving forward?

Sure, we mentioned that in the Intrastate business, Midstream, we said about $100 million to $200 million. That’s really going to be for the Chisholm pipeline that I talked about, and we’ve got some additional opportunities in Louisiana and North Texas. So, you know call it little over half of that being the Chisholm pipeline and the other half of that opportunities in Louisiana, North Texas, East Texas and that’s what we have today. Obviously, given that we’re in November 2010, that $200 million, if we are successful, we’ll exceed that. On the Interstate side, I think the upper range, as I mentioned was about $2.25 million. Most of that, as you know, is going to be the Tiger expansion, to get Tiger from 2 Bcf to 2.4 Bcf. We’ve estimated that budget cost to be about a $180 million to $200 million, and if we are successful, as we were on the original pipeline, we would be at the lower end of that range. And then there’s some timing on Tiger between 2010 and 2011. So, that once again little bit more left pocket, right pocket. It’s all part of the $1 million cost estimate on the original Tiger Pipeline; but again that could be some timing; just as we look to finalize, invoices coming in on that pipeline. From an EBITDA multiple perspective, given that these are Intrastate, Midstream type of projects, we’re looking at much better returns than you would on a typical Interstate or even long haul transportation pipeline. So, we’ve targeted kind of in the 5 to 7 multiple range and again with pretty conservative process in that, so we can beat or achieve those process, and it will be at the lower end of that EBITDA range. Now Interstate, when you just apply what we put out in the marketplace with respect to Tiger, I mean that’s a five in front of it, and when we layer in the expansion, that will continue to be kind of five, five and a half type multiple project. So, very strong in terms of not only what Tiger does for us operationally, but financially as well.

Now, would you like to handicap how large that spending could be in 2011 if some of the stuff that you guys are working on actually comes to fruition?

I’ll let Mackie answer that one.

It goes about saying there is a tremendous amount of midstream assets that are necessary just in the Eagle Ford alone. As Martin mentioned earlier, we intend to be a big player in the Eagle Ford. There are numerous opportunities to add upstream, downstream facilities as well as many of those into our existing assets, which are very synergistic with the play. So, it’s hard to kind of quantify what that number will be, but the positives are we’re moving forward and we’re going encompass some big things in there. The second thing is we’re not going to be intrastate pipeline in the Eagle Ford. There is going to be intrastate pipelines that will bring EBITDA much quicker. Those are models that we brought on around four months from announcement. And then the chisel we anticipate in the next seven or eight months. So much quicker EBITDA, much quicker volume growth in some of these areas. But I don’t really have a number. We’re going to be very aggressive.

My very last question is, philosophically are you willing to start maybe construction before you have firm commitments or do you need long-term firm commitments before you start spending big dollar amounts?

I think the way we address that, if we make an announcement, you can bet in some manner we’ve got contracts to back it up. We have not been a partnership that’s been willing in the past, but we’ll also see in the future going out spending hundreds of millions of dollars back in it, but we do anticipate hopefully making some announcements that will be back in some manner, some percentage of fee based.

Yves, not to say we routinely announce a project that if you just look at what might be committed to the project at that time of the rev return would not be spectacular, they would not be that great. But we know that we can fill the line on and increase the capacity. So that’s kind of a common practice of ours that has worked for us.

Great. All right. Thank you.

Thanks, Yves.

Your next question comes from the line of Ross Payne with Wells Fargo. Please proceed.

How are you doing, guys? First question is on the Interstate side. What is the average contracts life for you guys?

It varies by pipeline systems. TW, I’d say it’s in a three year to four year range, although that one given the history we’ve had a very good success rate in the turnover there from a customer perspective. On FEP, those were all a minimum 10 year with the ability to extend the contract term as all the shippers on Tiger, it ranges from 10 to 15 years, Chesapeake has 1 Bcf, 15-year commitment. I believe the others are all panned with ability to extend. So very long tenure on both FEP and Tiger.

Okay. And on your shorter contracts that are coming up, any anticipation on how re-contracting rates will be relative to where they were three or four years ago when you put them on? Second of all, any comments on how storage rates are going these days?

We have been pretty encouraged on some of the deals that we have been rolling and, for example, in Transwestern when companies are looking for rolling the deal three to five years they are willing to pay significantly higher prices than what the immediate spreads are, prop months spreads are. So we have been pleased with how we have been successful in contracting those. Storage has been very volatile. We haven’t seen the spread between summer and winter. Some of them we’ve seen in the past, and so we continue the partnership as the goal securing more and more of that and selling more and more of that to third-party under fee based contracts and that’s the goal that we will continue to try to achieve.

On the contracts that are rolling, it’s obviously coming in well above where basis is currently. How does it look relative to where those contracts were signed a number of years ago when commodity prices or basis might have been higher?

The contract that was mentioned were some of the ones we have on Transwestern and several that we have rolled certainly were slightly lower pennies. There is nothing that is imminent on being rolling them most of our other assets, most of them had at least on the intrastate side six to seven years left if not more and of course on the interstate side these projects are just kicking off beginning to (inaudible) more.

Martin one question for you and I will jump off, what’s Tiger and FEP get fully up and running, what’s your anticipation for leverage metrics as you kind of end the year in 2011 from a run rate standpoint?

With FEP and Tiger coming online and the cash flow going out the door stopped and now we get to see the cash flow coming in, start turning back down to about a 4 times leverage metric, which we feel is an appropriate level for us for now in support of the investment grade rating that we have, but the (inaudible) improved volume, given the mix of cash flows that both FEP and Tiger bring to the table. So, as I mentioned earlier, if these pipelines coming in service are deleveraging to the partnership and one that that we knew would happen, it would just get to the finish line. So, very excited about the fact that we now have these pipelines in service and we’re talking about 2 Bcf pipelines coming in. It is a lot of dollars going out of the door, but conversely or inversely there are dollars coming in the door now and that has given a good deleveraging impact at ETP.

Great. Thanks, guys. That’s it from me.

Thanks, Ross.

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

Hey, guys.

Hey, Ted.

Just wanted to ask a little bit, maybe just about your outlook for commodity prices, gas versus liquids and then how it makes you think about how you allocate capital to the Midstream or other places, dry areas like the Haynesville versus more liquids-rich like the Eagle Ford?

We continue to be probably as a whole, (inaudible) our partnerships, fairly bearish over the next 12 to 18 months on natural gas prices. We tend to be more bullish on oil, just because of what’s going on more globally, but we don’t know, we had conversations even as early as today as to if gas prices remains remain at these levels, what happens with less volumes coming on from the line, but lot more rich volumes flow in, and bring a lot more liquids into it, how does that impact everything? It’s a great question, something we look at closely and it’s also a reason that we structured our deals to where they are more fee-based, we are not as exposed to frac spreads and/or to natural gas prices.

Maybe I missed it, but how much hedging do you actually have in place for 2011 on your retained fuel and your basis?

Approximately 75%. We say approximately as bring more volumes on, of course, we are consuming more fuel, but that’s a pretty good estimate.

That is hedged with collars that I think range of 5 to call it 7, 7.50. So certainly higher than you’re seeing across today.

On an absolute basis, on your retained fuel of 7 to 7.50?

We have a floor of I think 5 to 5.50 with high or ceiling of 7 to 7.50.

In terms of just Tiger and FEP coming online, should we be modeling a ramp up here or these are kind of come on right away, the second they come on, is there any sort of timing issue with your contracts or what not, or should we just model them as coming on full-on on December, whenever they start up?

Yes, depending on the producer, they do tier into their volumes throughout the year. Some of them come on flat line for the whole tenure, some of this first year, they do tier into those and we will be at full force by the end of the year?

Yes, so really 2012 we’ll see the full impact of those demand fees or the contract fee producers have signed up for, starting in 2012 including the expansion on Tiger. So, strong injection of cash flow in 2011 and even stronger in 2012.

Okay. That’s it from me. Thanks.

Thanks, Ted.

And your final question comes from the line of John Edwards with Morgan Keegan. Please proceed.

Yes, just to follow-up or confirm, so in terms of the ramp up then, you’re basically going to be full sales here by the end of December, both Tiger and Fayetteville, did I hear that right?

End of December 2011.

Okay. So where do you think you’ll be by the end of the first quarter of ‘11 on those?

We hope for slightly more than 2 Bcf a day from a demand charge, we don’t have that exactly, I don’t have that off the top of my head, my guess is, Tiger, it’s around 70% to 75% demand in the first quarter.

Great. And then on Fayetteville?

Fayetteville, it’s slightly lower in the first quarter and then it steps up fairly rapidly in the second and third quarter. I believe by the third quarter it’s fully at today, 1.85 Bcf and we are diligently trying to sell the remaining 100 BCF a day and believe we’ll have that hopefully soon.

Some time ago, doing a joint venture, I guess in the water area with Heckmann, any updates you can provide us on that effort?

Nothing specifically. We are optimistic on some things that we are working on in several areas, whether there is a need for both treating or water disposal and also for fresh water supply, and we do believe that will be a part of our growth in the Northeast and to a certain degree in the South.

And then is that qualified for MLP treatment that effort, that will qualify because you will be assisting I guess energy producers, correct?

Yes, we were driven and got an IRS ruling on that and it’s qualifying income.

Okay, great. Congratulations on the pipeline.

Thanks, John.

And you have a question from the line of Bradley Olefin with Eagle Global Advisors. Please proceed.

Hi, good morning, guys.

Hey, Brad.

Just looking at the Intrastate segment, I guess I was a little bit confused that it looked like the volumes were up really nicely on your system and even with the Oasis pipeline being out and most notably the sales volumes, look like they increased very strongly, could you maybe speak to why that’s the case even with a pipeline outage?

Yes. Part of that as I mentioned, we were still able to move gas around the intrastate system. We just weren’t able to capture a good as margin as what we would have liked given our Oasis being down. We also withdrew, I think around 7 Bcf of gas out of storage which also storage is tied into our intrastate transportation system. So, you see those lines going through that impact, both the transportation as well as our natural gas sales volumes. And then with basis being a little bit stronger than what we had seen previously and we were able to move a little bit more gas that we’re marketing arm, the volumes were good, and they were strong and certainly increasing sequentially, we just didn’t get that extra pop given Oasis being down and having to move gas a little bit more and efficiently to meet our customer commitments.

It also looks like there was a large unrealized gain, derivative gain in the Intrastate segment and given the fact that spreads were improving during the quarter, I figured that the position on your hedges would be generating losses. Are those unrealized gains just all associated with sales out of storage?

That mainly, yes. I think the calendar spread widened out a little bit in the second quarter of this year and then started to contract or tighten in the third quarter, which was all fit in, in that unrealized gains. A lot of that is timing. As I said, we did move out of storage a little bit but still have about 23 Bcf that we’ve hedged to come out in the winter, I think the winter months here appears dim.

So the unrealized gain is mostly associated with the 23 Bcf still fitting in storage?

You’re right.

Just one last question. Did you guys take advantage of the spreads or the widening spreads throughout the second and the third quarter to add to your hedge position in a significant way?

Our top line group, they go out of their way when there’s opportunities to hedge at levels that makes things for our company they do and so, yes, when the spread widens, we do for hedges and/or we sell to shippers that purchase that capacity.

All right. Great. That’s all from me. Thanks a lot, guys.

Thanks, Brad.

At this time, you have no more questions. I would like to turn the conference over to Mr. Martin Salinas for closing remarks. Please proceed.

Thanks, everyone for your time this morning. Everyone have a great day and a great rest of the week. Thank you.

Ladies and gentlemen, this concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.