Ladies and gentlemen, thank you very much for standing by. And welcome to the Energy Transfer earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given to you at that time. (Operator Instructions) And also as a reminder, today’s conference is being recorded. I would now like to turn the conference over to your host, Mr. Martin Salinas. Please go ahead.

Thank you, Flor Jean. Good morning, everyone. Thank you for joining Energy Transfer’s fourth quarter and year-to-date earnings call. Reminder, that we will be filing our 10-K for ETP and ETE for the year ended December 31st, 2008 with the SEC on or before March 2nd, 2009. You can obtain a copy of that on our Web site when it is filed. During the call, we will 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 assumptions and information available to us. Although we believe these statements to be reasonable, we can’t give assurance that such expectations will be proven correct. As we’ve done in the past, we will make a few brief comments about the results for the quarter and year-end December 31st, 2008 before answering your questions. Just as a reminder and if you’ve noticed in the press release, we changed our fiscal year from August 31st to December 31st back in May 2007. For the purpose of this call, we are comparing our fourth quarter results from the results for the period ended November 30th, 2007 and the 2008 results for the 12-month period ended November 30th. I’ll also comment on our CapEx for 2008 and our expected CapEx for 2009 during our recent (inaudible) announcement, for which (inaudible) and Energy Transfer is very excited. I’d also tie that end to our liquidity through 2009. As always, Kelcy, Mackie, and other senior management are available to answer your questions. We also have John McReynolds here, ETE’s President and CFO, to address any ETE related questions. Before commenting on our financial results, I would like to bring your attention to a few things we did during and shortly after the fourth quarter as it was a pretty busy one for us. First and foremost, we exceeded our EBITDA expectations despite a very challenging environment. This demonstrates our asset in management team’s superior performance. And I’ll speak to that more in a minute. We also successfully raised $800 million in proceeds, (inaudible) amounts and equity offerings, of which these proceeds were used to reduce borrowings under our existing credit facilities. These offerings were executed despite the challenging market headwinds we’ve been experiencing for the last few months, but we couldn’t be more pleased with the results of those transactions. We’ve also added the capacity for expensive natural gas pipeline system with the completion of several projects, including a Southern Shale, which is a 30-mile, 36-inch 700-a-day pipeline connected to our Maypearl compression station that then delivers gas into our extensive networks. We also completed the Cleburne to Tolar, which is a 36-inch mile – I’m sorry, 36-inch, 400-a-day, 21-mile pipeline connected to the western region of the Barnett Shale. We also completed Katy expansion, our 36 inch pipeline, 56 miles, 400 days capacity providing outlets out of the Bossier and Barnett Shales into the Katy hub. And we also look to bring the Phoenix lateral online before the end of the month. As a reminder, this is a 500 mile extension of the mainline pipe from our Transwestern system and consisting of 36 and 32-inch diameter pipe serving the Phoenix area. Beginning with our original 42 inch Cleburne to Carthage pipeline, we’ve added over seven BCF of incremental capacity with the majority subscribed in a long term commitment from ten pipeline projects completed during the last two years. It’s a pretty impressive speed. We also, during the fourth quarter – actually shortly after the fourth quarter, announced the Tiger pipeline, which is the 42 inch long haul transfer station pipeline connecting from our dual 42 inch pipeline at Carthage, and extending through the heart of Haynesville shale. The pipeline will not only serve as an expected capacity requirements producers from Haynesville, but will also derive the much needed takeaway capacity out of East Texas. We believe this project will demonstrate ETE’s ability to make the market accretive deals despite the challenging landscape and our cost of capital we keep today. Moving on to the fourth quarter and year-end results, our consolidated EBITDA for the fourth quarter was $338 million, a 20% increase over the three-month period ended November 30th, 2007. For the year, EBITDA was $1.4 billion, a 22% increase over a 12-month period ended November 30th, 2007, and probably ahead over our updated guidance of $1.35 billion. We want to point out that our initial guidance that dates back in the beginning of 2008 was $1.25 billion, with a net increase over guidance that much larger. Stepping through our segment results – and we’re pretty proud of our company and our people and what they’ve accomplished, just a great job. Looking first at our interstate operations, which consists mainly of our Texas assets, but also includes our Canyon and (inaudible) systems. Very impressive results for the quarter and the year, which were mainly driven by our continued efforts to add incremental capacity to our natural gas pipeline systems and our ability to transport gas and natural gas producing basins to major market delivery points along our pipelines. As I mentioned earlier, we brought into service over seven BCF in capacity resulting in higher fee based revenue year-over-year. The increment capacity, coupled with higher natural gas prices, and favorable (inaudible) price differentials were the main drivers for earnings growth in 2008. As you can see in our volumes, we’ve also been able to grow our volume by over 50% quarter-over-quarter and year-over-year for our transportation segments. Looking at the quarter, I do want to play out a couple of non-cash items that were recorded during the period. We did have a $47 million lower cost for margin adjustment related to our natural gas store in our (inaudible) facility. This is probably due to the drop in commodity prices in the recent months. I do want to remind you that we do cash, from a financial perspective, our natural gases, those in storage, and this is a non-cash item. In addition, as a result of annual goodwill impairment asking, we wrote off $11.4 million of goodwill associated with our Canyon assets. This was also a one time non-cash charge. After these items, we had a very good quarter and our results demonstrate our intention of putting together a system mix that delivers strong results despite challenging market conditions. Turning over to our interstate and the key drivers, as you know, (inaudible) and pipelines make the majority of our interstate business. We had strong operating results from there, with an increase of $9.3 million or 39%, which is really due to the completion of San Juan Loop back in July. On a year-to-date basis, Transwestern was up 4%, which demonstrates the predictability of owning an interstate pipeline. We expect our earnings and cash flow from our interstate business to grow as we bring in service, the Phoenix lateral, a year and – 15 to 20 days as well as the MEP, which is due to come in service at mid break 2009]. Turning to propane and our key drivers there, we have very good business on the fourth quarter as well on a year-to-date basis, and we ended the year on a strong note. Our volumes was probably higher than the prior period when we are speaking higher margin on a per gallon basis and expect the trend to continue for the remainder of the heating season. I also want to point out that 2008 includes a non-cash mark-to-market loss of $46 million related to derivatives put in place for winter sales. We anticipate little item mix and significant profit on these sales from propane delivered to our customers for the remaining few months. Turning our attention to the balance sheet and a few comments on growth and maintenance CapEx, closed CapEx for the quarter as follows, interstate we had $209.7 million for the quarter, $1.186 billion on a year-to-date basis; for the quarter our CapEx was mainly for (inaudible) project will come in service in mid 2009; and, the completion of the pipeline that I have mentioned earlier. Interstate CapEx was $87 million for the quarter, $695 million on a year-to-date basis, intrinsically for the Phoenix project. Propane has $6 million for the quarter and $40 million on a year-to-date basis. Maintenance CapEx for the quarter was $65 million and $140 million for the year, slightly higher than our guidance due to the (inaudible) of certain projects that are related to pipeline costs. Looking forward to 2009, our planned CapEx is expected to be between $720 million and $790 million. This is roughly a $150 million increase from our previous guidance provided on our analyst meeting back in November here in Dallas. The increase is mainly attributable to the Tiger project we’ve recently announced. Related to our joint venture with Kinder Morgan, first, the anticipated cash flow for the Fayetteville express pipeline in 2009 are $300 billion to $310 billion to fund amounts an excess of $1.26 billion project financing facilities we have in place there. Secondly, the expected funds between $200 million and $222 million in 2009 for our 50% share of the Fayetteville express pipeline. This could change, however, as both Kinder Morgan and we intend to seek third-party project financing for this project. We do continue to pursue opportunities for growth projects around our assets. And we’ll continue to evaluate each project on a go-forward basis as we monitor the current market conditions. A couple of comments on liquidity, over the last few months we have significantly enhanced our liquidity position despite the holes in the market with two successful offerings to debt and equity, as I mention earlier. This demonstrates our ability to access the market, but also our prudent approach to managing our finances given the rough terrain. As (inaudible) one, we have approximately $0.9 billion drawn on our revolving credit facility. If you (inaudible) off for the January equity offering, we have approximately $1.26 billion in available capacity under that revolver. I’ll remind you, we have several financing options available to us that we’ve discussed in our November analysts’ meeting and continue to explore our options. With our announced capital project and CapEx guidance, we believe our strong liquidity position will allow us not have to access the markets until early to mid 2010. However, we will continue to monitor the landscape and be ready to act when variable conditions present themselves. Looking at our distribution and our distribution coverage ratio, despite the strong operating results from our assets and continued growth and distributable cash flows, we maintained our fourth quarter distribution at 89 and three-sevenths – 89 (inaudible) units or $3.575 on an annual basis. Having said that, our distributions have grown, on average, 10.5% from the prior quarters. We continue to believe that it’s in the partnerships’ and our stakeholders’ best interest to closely manage every dollar in and out of the partnership and be prudent with how we allocate resources. Our coverage ratio as of 0/31/08 stands at probably less than 1.2 times and would grow to almost 1.4 times by the end of 2009 if we meet our EBITDA target and kept distribution consistent with today’s level. However, we don’t take a 1.4 coverage on a long term basis as mortgage given our size and risk profile. We could see that coming down to 1.15 to 1.2 times when market conditions improve. Looking at our proposal and venture with OGE Energy and as we announced back in September, we look at the former joint venture with OGE Energy and their assets in the Oklahoma – in Oklahoma. But as we all know, the credit market deteriorated, posted that announcement. And last Thursday, OGE and we, agreed to terminate the agreement. There are no break-up fees with that as we simply terminated the agreement. We do have a high regard for OGE and its management team, and we’ll continue to explore opportunities with them. Turning our attention to ETE, the expected cash distribution to be restated in the ETE for the fourth quarter totaled $939 million [ph], and ETE is expected to pay out $114 million in distribution through its unit holders based on an announced distribution rate of $0.51 per unit or $2.04 on an annualized basis. This represents a 6.25% increase for the third quarter rate of $0.48 per unit, and was mainly driven by additional cash flow resulting from ETP January equity offering. For those of you who knows ETE’s liquidity position, it has this $500 million revolving credit facility that expires in February 2011 and available liquidity under that revolver at 12/31 was roughly $378 million. In closing, we experienced another great year for Energy Transfer with strong earnings performance and growth in distributable cash flow despite the challenging environment, particularly over the last few months of 2008. We have invested a substantial amount of our resources, operational and financial, over the last couple of years to build a premiere energy partnership that will diversify and engineer to provide distributable cash flow for years to come. Our strong financial position, significant liquidity position, investment grade rating, and appropriately managed distribution coverage have put us in a position to continue executing our goals and objectives and the ability to take advantage of opportunities as they present themselves. Despite all of this, you will continue to see prudent management decisions from us as we operate in an environment that is fragile and ever changing. There continues to be a strong demand for our products and services, and we are confident that we will continue delivering large term value you have come to expect from Energy Transfer. With that, I’ll turn it over to the operator for questions. Thank you.

Thank you, ladies and gentlemen. (Operator Instructions) And our first question comes from Jay Murray [ph] with Bank of America.

Good morning, everyone.

Good morning, Jay.

Martin, do you mind just running through the Bammel and Canyon charges one more time? How much was that Bammel off the market?

The Bammel was $47 million.

Okay. And in terms of delivering that gas, will that primarily take place in the first quarter this year?

That’s right, Jay. As we looked, we saw gas at Bammel, as it stands today, that is our intention.

Okay. Both of those were in the exchange segment, right?

Yes.

Okay. Great. In terms of just larger (inaudible) questions, the decision to raise the distribution at ETE in keep it at the level of ETP, particularly considering, I think you talked about ETE’s liquidity to support ETP in the future. I wonder if you could just speak to that a little bit?

Sure. They are really just like the shareholders to buy both the limited partnership, maintain a distribution, ETE benefits from growth and cash flow as ETP. So as we looked to our distribution to ETE from ETP, it makes sense to demonstrate ETE’s ability to grow with ETP’s position. Does that make sense?

Yes, that makes sense. And switching gears to the Tiger pipe (inaudible), the timing around that open season, I know you got the base load or baseline commitment from Chesapeake [ph] but just the timing on the open season to potentially get some more commitments.

Well, this is Mackie. We intend to start double season either Thursday or Friday of this week.

Okay. Mackie, how long do you think that might run for?

Will run for 30 days.

Thirty days, okay. And then just ’09 guidance, I think it was $0.16, $0.17 to $0.17 EBITDA. Do you still feel comfortable with that level?

Yes, we do.

Okay. Thanks.

Thank you. And our next question comes from Derrick Lahey with RBC Capital Markets.

Good morning. Just a couple of quick housekeeping questions more than anything else, wondering what was the maintenance CapEx expectation for 2009?

Our value is at $130 million.

Okay. It’s still staying there. And then, I apologize I missed the fourth quarter ‘08 number?

Fourth quarter ‘08?

Yes.

Maintenance?

Yes.

Bear with me.

For the full year, either one.

Full year was $140 million.

Okay. And Martin, could you walk through the non-hedge interstate derivative laws? Can we just get a little more detail on that?

You referring to ETP or ETE or both?

ETP.

ETP, we entered into derivatives late November, December. A $500 million commercial [ph] amount with a drop in interest rates from that period at 12/31 recognizing a number of (inaudible) laws. This is a pre (inaudible) hedge through 2009. And so, kind of rules from triangle via cash flow head accounting. So you’re going to see that volatility in our mark-to-market. It is a non-cash up until the time we do have that set issuance.

Okay.

But it is un-hedged and it did impact the cash flow.

That’s what I thought. Okay. Thanks.

Yes.

Thank you. And our next question comes from Ross Payne with Wachovia.

Martin, first question is, obviously you’ve just completed a lot of projects here in the fourth quarter and you’ve got some major ones coming here in 2010. But if you could, could you estimate for us the amount of Cap Ex, the amount of dollars that have been spent that really haven’t been generating significant cash flow here, so we can kind of back into pro forma and EBITDA number. Thanks.

Yes, Ross, we haven’t given specific variance to the projects themselves. What I will tell you is when you go back and look at the calendar and see when this project came on line, the biggest one and probably Bossier came on line back in late first quarter, early second quarter. And then we’ve had a whole host of projects came on line second, third, and fourth quarter. And reminded that we also expect to see, as I mentioned, Phoenix come on line by the end of the month, and MEP service up to Fayetteville by early second quarter and then (inaudible) by the third quarter. I think if you factor in a full year for those projects and the pro rata for MEP and Phoenix, what you’re left with is – really, an independent pipeline is the only projects out there from a CapEx perspective that was not seen in the EBITDA contribution from that. And we’re about halfway on that as I mentioned, Ted comes on line early third quarter.

Also, Martin, I missed the availability at 12/31, I’m sorry.

Yes, Ross, the availability is about $1.26 billion at 12/31 when you factor in the equity offers in January.

Okay, that will be good for 12/31. Okay.

Hey, Ross, just real quick though, going back to your other question, when you need to factor in the contributions on the resort bankers?

Yes.

I’m sure you’re aware of that as a reminder.

Okay, got you. Okay, we’ll have that in. Also, Martin, you were holding on a decent amount of cash, I was just curious about that, at 12/31.

Well, that’s fairly due to timing and how receivables and payables get settled. I don’t recall whether (inaudible) personal loans to answer that. Typically, what you see as income that’s cash there, it’s really a result of timing between collections and payments on our producers’ side.

Okay. One final one and I’ll jump off here. I was wondering if you could just comment on either how things were for processing in the fourth quarter and what you’re seeing here as you go under the first quarter. Thanks.

Yes. No, surprise there that you can see a drop in the commodity prices, although we’re not alone in that. Due to the market systems, a couple of things, one is, with respect to the Dolly [ph] plant, that is becoming a more and more fee-based business. We also saw some fulfillments in the fourth quarter related to the Bellevue being shut down. And then very recently, the Louis Dreyfuss (inaudible) line, which we’ll start seeing more of that process in February [ph] capacity in 2009. (inaudible) system, which the system down the (inaudible) that has been predominantly people. The beauty of those systems is that we can bypass the plant, so we do strip down the low-end, if you will. I’m still seeing wells being completed and lines coming on, so again, a small part of our business factors in some decrease. And my commodity prices for ’09 that I still feel confident our systems will produce.

Our next question comes from Darren Horowitz with Raymond James.

Good morning, guys.

Good morning.

I apologize if you’ve mentioned this, can you give us a little bit more color on a few pieces, specifically the cost construction is $1.2 million to $1.3 million still you target and then secondly, what are you guys seeing in terms of the market for third party financing at this point?

Darren on the cost, the $1.2 million, we still feel very good about that, our management team and we secured the most part of the pie compression. We’re currently in negotiations on labor. We couldn’t be in a better situation (inaudible) and what we’ve seen recently with decreases in field or labor. But we still feel very good about that estimate. We’ve done a lot of things since we’ve announced the projects. And we feel very good about not only the cost but the timing of the project. As it relates to the second part of your question and project finance, still a tough market. Banks have not yet opened the doors in terms of an instrument like that. I remember we’ve got ongoing discussions with the CapEx being more important in the last part of 2009. And we still have some time before we see a lot of that Cap Ex coming to the table in both MEP – sorry, both Kinder and us. So that’s the time, again, as I looked our financing needs. That’s not something that I’ve digged [ph] in. It will be a plus if it happens. Otherwise, we’ll look at the capital market.

Sure. I appreciate it. Then finally, just one big picture question for either Kelcy or Mackie, specifically around the Haynesville, in today’s gas environment, if you were to extrapolate the forward curve, does that change your expectations for production record this year, and lastly, ultimately, how do you gain the takeaway capacity on Barnett? Do you think that the two proposed lines are adequate? (inaudible) Do you hit a correction [ph] point where there’s a bottleneck [ph] to get capacity (inaudible), just some additional color there.

Okay, this is Mackie. (inaudible) the whole producer in paying their own rates. Personally, most of them are sitting their way through Haynesville in that area. As you may or may not know, the hydro project is really geared not just for the Haynesville, in what could be one of the biggest lines in the history of the country loss. So also, it connects, as Martin said, which could provide transportation from West Texas from Barnett Shale, from South Texas from the Bossier. So the project really benefits both Texas producers and the growing Haynesville production, and in conversations that we’ve had with multiple shippers who had the unbelievable amount of interest in the project, we see significant production profile growth in prices, say, kind of in a range of $3 or north of $3. So we’re pretty excited about the play overall energy that make most of the industry.

Thanks, guys. I appreciate it.

Thanks, Darren. Parkie [ph], could you get the next question, please?

Our next question comes from Michael Blum of Wachovia.

Hi. Thanks. A couple of questions, can you give us a little insight into what you’re seeing in terms of volumes in the Barnett Shale right now?

As far as volumes pertaining to Energy Transfer, they continue to grow. Of course, we’re obligated to move a significant amount of production out of that area. And our producers are meeting their volume curves and we’re delivering the gas as required.

So there’s no change with how you saw things are playing out now, if it’s playing out the way you thought it was?

No, well, we currently do see change, in fact, (inaudible) it’s a very positive change in regards to the production co-files from the producers out of Barnett Shale peak within the next two to three years because of what happened in the industry and commodity prices, and the focus on Haynesville. That peak has now leveled out. In fact, we didn’t renegotiate some of our contracts in the longer term, 15 years contracts without a P. So the P benefit that (inaudible) transfer that don’t have to deal with that two, three year P and yet maintain the high level of P based volume commitments to our project. So it’s really a positive for us in what’s happened (inaudible).

Okay. And Houston share praises are kind of depressed right now. What kind of that impact (inaudible) Houston pipeline and just generally on your system?

Yes, Michael, this is Kelcy. I’ll answer that. We move all the volume that we have in our system, whether it goes in the storage or the …

What is the impact of loads on the Houston pipeline and, just generally, on your system?

Yes, Michael. This is Kelcy. I’ll answer that. You know, we move all the volume that we have in our system whether it goes into storage or whether it goes to the burner jet. We don’t shut in gas. We take great pride in that. It takes a – it takes a rare event for us to be required to do that. Even there are periods of hurricanes we make every effort to flow the gas so that producers – that’s our job. So, yes. We work very hard to create a pipeline system where we can have the ability to just tell us where gas is most valuable and the producer can work out an arrangement for us to move the gas to that location. So we – we take great pride in that. We have a system that we can go to Waha, to Katy then Ship Channel to Perryville (inaudible). And we have great hydraulic capability to perform that service. And we’ll continue to increase that capability.

Okay. And the final question just to clarify, so instead of distribution gross [ph], I assumed, Martin what you said is that effectively you won’t be raising the distribution until – and because of that ETP, until market conditions improve? Is that essentially what I heard? Is that correct?

Well, Michael, we really can’t comment. I’m serious when I say this. There’s no foregone conclusion as to what we might do next quarter. I want to make that very clear. However, I do believe strongly when we made the decision two quarters ago to leave our distribution plant [ph], at that time that was – that was the challenge to break the old saying that that was going to be a negative thing. We have not seen that. Since that time people like yourself and others on this call have actually commended us for that for several reasons. One reason is we’re not being rewarded for. The numbers speak for themselves. We’re really doing well here. Yet, in my opinion, we’re trading as if we’re not. So we’re not sure we’ll be rewarded for distribution increases at this time. They will be forthcoming. Without a doubt they’re forthcoming. Martin said earlier that we’re letting our coverage ratio creep up. It’s just so we don’t make anymore for this year. And I’ll think that’s a fair assumption on distribution increases. But if you send that we’ll get to one quart full pretty quickly. And we believe we’re more like a one (inaudible) high coverage ratio partnership. So for any unit holders on this call, that tells you the money’s coming to you. It’s coming out the door. It’s just the energy [ph] didn’t come out the door. We just don’t believe we’re being given credit for it in this market today.

Thank you, Kelcy.

(inaudible). Thank you, Michael.

Thank you. And our next question comes from John Edwards with Morgan Keegan.

Yes. Good morning, everybody.

Hey, John.

Martin, just to clarify the total liquidity you’re looking at right now, I think you said 1.26 was on the credit line. Is that you’re total available liquidity?

Yes. On the PBCF [ph] revolver we have about 1.26 with the pro forma equity in there.

Okay. Great. And then, just to clarify I think somebody else’s question earlier about your 2009 guidance I think. The last one you put out was $1.7 billion to $1.8 billion in EBITDA. You’re still – you’re still working at that range?

Yes.

Okay. And then I noticed you’re not commenting on 2010. If we decided to see any preliminary guidance for 2010?

We’ve not done that, John. Again, I think there’s too much uncertainty in the marketplace today. What I’ll tell you is what I know. We’ve got a full year of MEP coming online 2010. Also, this year you’ve got Phoenix partial. We’ve got (inaudible) partial. You’re going to see growth, John. I just can’t tell you how much that’s going to be today.

Okay. And then as far as – I think there was a (inaudible) that there’s an article about a week ago or so regarding the – where you would price your transportation to. I think it was in the Gas Daily. Then, I was just wondering if you could provide any inside as to how that – obviously it was a positive benefit. If you could, maybe, put some – a little more color on that?

John, this is Kelcy. I assume you’re referring to the fact that a lot of gas is being passed off to the Waha Hub. Is that what you were–?

That’s right. Exactly.

Yes. You know, if you look at the Barnett Shale – Mackie’s probably a better person to address this. For ever, the only way that we could really move volumes of gas out of the Barnett, because of restrictive capacity, has in fact been to move the gas west. So it was very appropriate to price it to the West. Really, up until the Texas Independence Pipeline is completed, we still have that predicament. And then, of course, there’s the Tiger Pipeline as Mackie mentioned. As that is completed, that eases our flexibility to move more gas east. At the present time it’s very difficult for us to accomplish the movement of gas, from the Barnett Shale specifically, without directing that gas to the west. So I didn’t really – I personally don’t read Gas Daily. We’re proud of that. The only thing I could figure out that they’re referring to is a lot of (inaudible) are in fact pricing their gas off of the Waha Hub.

Okay. It just looked that there would be an incremental, positive benefit to that. I was just trying to get a little bit better idea in terms of the approximate upside that (inaudible). If you could comment on it? If you can’t I understand.

Yes. If you look at our system it currently is unique. I guess the closest party to us might be Enterprise. And we have much more capability than they do at the present time. And if you look at our system we don’t care if you want to move it to Waha, Katy, Ship Channel, Carthage. We don’t care. Just tell us and we’ll perform that service for you. So we do enjoy a nice basis differential that exists across the state. But truthfully, we really don’t care if Waha is the highest priced hub or Carthage is the highest priced hub. And if you study our hydraulic capability in our company, that becomes very clear to you. Now that didn’t happen by chance. We’ve worked extremely hard and have invested billions and billions of dollars to create that kind of machine that – presently, if Waha is the cheapest hub, then we’ll try to buy as much gas off of that Waha fast as we can and deliver it to the highest priced hub.

Okay. And that was great. I appreciate the color on that. And then, Martin, you’ve mentioned you didn’t break out the access type of markets at all until sometime in 2010. So will you do it selectively? In terms of when you have to go back to market are you looking at, well, say mid-year type – mid-year 2010 type – type time frame?

Yes. Our (inaudible) into that is the MEP facility. The facility at MEP expires in 2011. The pipeline comes in service in mid-to-late 2009. We’ve got some time. Problem is (inaudible) on when the right time is. So if you factor in a later take out of that facility, then that pushes that – that timing into late 2010. If you push it in early then it accelerates that need to go to market. So that’s really – currently that’s the biggest driver of the timing as related to 2010.

Okay. Great. Thanks. Appreciate that. And nice quarter.

Okay. Thanks, John.

Thank you. And our next question comes from John Tysseland of Citigroup.

Good morning, guys. Just a figure question for Kelcy or Mackie, regarding your expectations for basis differentials going into late summer; early fall. They announced what might be considered an over supply in the natural gas market. And that versus a rolling over of the (inaudible). How you view where we’re going to be in terms of basis differentials later this year?

Hello, John. That is a very difficult question and I’m going to let Mackie answer that.

I’m trying to go back to what Kelcy said. What we initially had done is ask the producers where they want to go and we drove assets to those markets. We will continue to do that. In the meantime, we really don’t care where basis goes. Our system’s set up to benefit regardless of if it’s spread wide, or from west to east, or from north to south, or from east to west. So what we’ll do is continue to (inaudible) our shippers and continue to sell our capacity between the lower Texas points to the highest Texas markets.

And, John, let me add to that. And I think everybody is – on this house is probably seeing what I’m talking about. We all had childish [ph] suspicions that the next project built by Kinder Morgan was going to, in fact, shuffle the deck and change basis dramatically. We have seen that. We all speculated that it would occur. And it, in fact, has occurred. So I think that there’s some fundamental things that have happened of late such as that prices to the west being depressed. If you think about it a lot of gas that was supplying certain parts of the United States market is now got very strong competition from the Rockies. We didn’t have that before. And so, I think, there’s been somewhat of a permanent phenomenon that’s occurring here with basis. And we intend to study it and try to provide much service to our producer-customers as we can to help them receive the highest price they can get.

I guess another way of looking at it would just be – with your conversations with producers, are they still concerned at this point that pipeline capacity is not efficient? We’ve seen that with the Tiger Pipeline announcement that certainly Chesapeake – they value getting their gas out.

Yes. There’s not – I compliment Mackie and his team. It’s pretty unbelievable what they did on the Tiger project. We didn’t have the best foothold of our competition yet. Yet we, in fact, prevailed there. If you look at the Barnett Shale with the Texas Independence Pipeline, we’re okay. If you look at Bossier, we’re okay. If you look at the Permian sure, we’re challenged. We’re challenged, our west to east. And are continuing to explore that. If you look at Haynesville we’re not okay. There’s not enough capacity to move the production that is being discovered and will be discovered in Haynesville. Just not there. We believe, even with our 42-inch that we are building, there’s still need for additional capacity out of Haynesville. Mack, would you agree?

I do.

That’s great color. One last question. Maybe Martin’s (inaudible). Looking at project cost he (inaudible) earlier. But it just seemed that if you look at pipeline cost (inaudible) per mile your costs continue to go up with each incremental announcement to the market. Are you hopeful, given that (inaudible) from the outside looking in, looking at steel costs and everything else slowing down, are you hopeful that these projects might come in a little bit under budget?

Yes. Not only hopeful. We are seeing that. We are seeing a trend at (inaudible). Both the steel cost and also the labor. They are not here to make projects out there on the drawing board over the next two or three years. And we do (inaudible) and have already signed up for (inaudible). Fixed price. Current price where we don’t have the risk of weather, et cetera. So yes, we do anticipate that and we are experiencing that (inaudible).

All right. That is (inaudible). Appreciate it.

Thanks a lot, John.

Thank you. And our next question comes from Steve Maresca with Morgan Stanley.

Good morning, guys.

Okay, Steve.

Can you just talk on Tiger? How you thought about the risk and having Chesapeake being such a big part of it as opposed to, maybe, spreading that out over different producers?

Sure. As everybody knows, to kick off a pipeline project of that size you need foundations. Chesapeake was the one that stepped up. They had the most – better wells, the most anchorage. And what really drove our decision is that he’s built a tremendous (inaudible) through Carthage. We know how much volume we’re obligated in this company along to deliver to Carthage. And we know there’s not near enough equity capacity in the next two to three years to accommodate what we’re obligated to deliver to Carthage alone. So we see the risk as minimal in regards to both what is available at Carthage and (inaudible) and the expanding Haynesville (inaudible) and East Texas and throughout the Louisiana corridor – northern corridor.

(inaudible). Shifting quickly to (inaudible). Just the status on Mark West’s option on that. Where is that? Is that still exercisable?

No. They chose not to exercise it.

Okay. And then, finally, on the (inaudible) release on OGE JV. Are there other things that you’re considering with them now that the JV is not happening? And then, also, is there potential for this to reemerge again if you get better market conditions over the next several quarters?

Yes, Steve. This is Kelcy. Our logic for that partnership was, in fact, that we believed that there is unexplored opportunities that exist from Oklahoma. We believed that the next pipeline was going to depressed prices in Oklahoma. That has proven to be correct. We are extremely impressed with the capability that OGE has built with the Enogex pipeline system that it is an impressive machine. However, it has limits to the market it can access. We’ve spent huge dollars over the last few years increasing our market access. We felt that a partnership with that asset would be win-win for both parties. Unfortunately, as we said, the market deteriorated before OGE lost their financial desire to move forward. And, of course, we did as well. However, to go back to your question, we have developed a very good relationship with those people over the last year. And we think we’re very compatible in the way we think, the way we conduct ourselves and the way we use supply and demand going forward. And I think there’s a very good chance you’ll see us do more things together, whether it be a project basis or something in a larger scale, I don’t know. But I think there’s a pretty good opportunity for us to work together.

Okay. Well. Thanks a lot for the caller [ph] guys and good job on the quarter.

Thank you, Stephen.

Kevin Segal [ph] with the Royal Capital [ph].

Thank you. Good morning, everybody. As it relates to Tiger, are you guys trying to spend money on that project?

Sure, of course, as far as environmental process, as far as the purchasing right of way, as far as locking-in the compression. We haven’t been doing much.

When is the goal, next year, when you start?

Yes, yes. Hey, this is Martin. The three-year [ph] build out, we have about, call it 20% in year one. And then, really, the big bulk towards a lot of part in next year, then early part of 2011.

And here’s a naive question for you. But is that pipe going to be in service soon enough to meet the needs of the producers out there. Or do they still need to have another temporary solution to get gas out.

Most of the bigger players, they’re saying that the most (inaudible) and/or have negotiated back haul agreements of different pipelines. So understanding and also some board haul on any remaining capacity with existing assets. So I think they are all scrambling to place their gaps in the interim period.

Okay. And then two last questions. As it relates to potential acquisitions, consolidation, do you get the sense that sellers have sort of come to realize that maybe they have to realize lower prices in order to get pumping down in this environment?

Yes, this is Kelcy. I certainly believe so. I mean, for the first time in many years, we’ve seen a depreciation of the product that you got no trading bills [ph] varying from, I don’t know, 40% to 50% to 78%, I guess, in the sector. We didn’t have that before. Everybody was considered pretty much the same based on what your last quarter’s distribution was. So yes, we believe that consolidation is inevitable. We are being extremely patient here. That is something that we want to do. We believe we’re an excellent consolidator in the sector. We take our investment grade credit rating very seriously. And we’ll protect – we’ve covered that and we believe that we’re going to be a much larger and stronger partnership when all the dust settles. But you know, I think patience is a very key word right now. I think it’s a little early to be rating to beat [ph] in consolidation waters.

I agree, too. And then the last question, and this is Kelcy’s favorite. As it relates to McGraw- Hill’s, where do you stand on the second leg of the FERC hearing now?

Jerry Langdon is with us on this call. I am going to ask Jerry to speak to that, please.

Kevin, how are you today?

Great, Jerry. I’m fine. Can you by any chance to answer the question?

As you know, we’re waiting for the commission to come back on some of the puzzle that we had before them on the Oasis piece that we filed early part of January. The trading case, we have pushed back 45 from the original (inaudible) equal to the push back to about mid June. And we also push back the (inaudible) conference.

And what’s the rationale for pushing it back?

The rationale was that we needed to review the McGraw-Hill data. And as you know, there were some difficulty in getting that from McGraw-Hill for a gap longer and we petitioned the judge to give us more time to evaluate the data that was there. And he agreed very quickly that (inaudible).

Did the data come?

The data came.

Okay, great. Thank you.

Thank you. And the next question comes from David Luzenske [ph] with James [ph].

Thanks. This is David, a follow up in my blooms [ph] question. Can you please provide a little more detail regarding why you expect to see volumes in the Barnett Shale growing in ’09. As you know, Devin [ph] recently announced their plan to only drill, I think it’s between 200 to 250 wells this year down from roughly 650 wells last year. And I think the recount is down from 40 to almost 20 now. So where are the volumes expected to be coming from? And when do you expect volumes to trend or where do you expect volumes to trend in 2010 based on current drilling plans.

David, I’m going to – Kelcy, I’m going to take a stab at just the first part of that (inaudible), and then we’ll let Mackie pin more of the ways. But as of about three weeks ago, four weeks ago, there were 208 wells completed in the Barnett Shale yet to be connected. So if you just look at that, that tells you that we’re adding volumes, if you just look at the wells to be connected. And secondly as you know, that unfortunately for the Barnett Shale, that doesn’t happen very quickly. Every well connection is a challenge, it’s becoming more and more of a challenge. And so it’s kind of slow to get all that done. So I think we’re – a lot of the full, we see kind of this backlog of rapid drilling coming into the market. However, you’re right. We’re seeing dramatic, in (inaudible), dramatic reproduction. We’re seeing that other people’s cases, such as, people like (inaudible) not nearly as traumatic. But we are seeing that they’re actually growing with that (inaudible).

Well, a couple of things, one is we’re (inaudible) pipelines really open up a little bit to take away. So some of the producers that have held off from drilling some of these richer wells have again been drilling some of those. And I think with the reduction in drilling, it just means they’re not downsizing their staying, they’re drilling (inaudible) won’t have to drill to hold their leases. So at least our customers, majority of our customers, that only means (inaudible) transport their gas. They had remained – they have kept their drilling needs at wells to maintain from hyper growth [ph] into the future.

And let me say, I might say that next to my knowledge, we don’t have any debt (inaudible).

Devin’s buys and our customer buys.

So that Devin’s rigged count all that we have. Let’s just say have no impact on us at all.

No, I understand that. But can you all, I guess, provide a little bit more color to what producers are you talking to that intend to potentially keep production where it's at. And then based on the discussion that we’ve already have, is there an expectation that your (inaudible) volumes in the (inaudible) at the end of 2009? And then is there an expectation or what is your expectation for 2010 at this point?

It’s tough to tell. One thing that we have is that the production profile is up (inaudible) we’re in a very high cliff, a very high rate of growth over the next two or three years. We see that as a much smoother hill, if you can picture that. So we don’t see near the growth that we’ve anticipating, but we do see a slight growth from all of our major producers from the Barnett Shale. Secondly, our contract for Phoenix so certainly, we for the sake of business to continue to grow their production to the levels that we’re obligated to transform us, but the impact on us will be minimal because we’re receiving our (inaudible).

And just on the midstream segment, is there an expectation (inaudible) at least in terms of the gas-liquid sold and the natural gas sold in the fourth quarter very perceive of the second and third quarter, certainly dramatically. What kind of decline trend would you expect to carry forward into the first and second quarters?

On that David, a couple of things as I’ve mentioned in the fourth quarter that you saw. You did see some lag on (inaudible) and you also saw, as Mackie just mentioned, a strength on pipeline capacity of our pipeline of resulting plant. Those things have worked themselves out. We thought that we are now online at the beginning of ’09, but we’re seeing a light imitated the rich wells that the producers (inaudible) on. You try to see that come through. Doubling expenses, they continue to hook up a love affair. We’re seeing a continued drilling there.

W. Spence is here. They continue to hook up (inaudible). We’re seeing a continued drilling there. So some drop off, but again, with the business, I don’t see (inaudible) there in 2009.

Okay. Thanks a lot.

Thank you. And our next question comes from Shaman Ducon [ph] with Lotus Partners.

Yes. Hi, good morning. Can you talk about how the percentage of your capacity for your entire system that subscribed out for 2009 and 2010?

The company, as a whole, has an operating capacity subscribed at approximately 5%. Any one of the systems will (inaudible) left. And slight (inaudible) our storage, we have a target of 7% that we might accomplish our (inaudible).

So if there’s a – if there’s a decline in drilling in any of these areas, that effectively protects you from a little revenue coming down the pipes?

Well, the demand charges protect us from the standpoint of amortized amount of pipes at the levels of each (inaudible). As Kelcy mentioned a little bit earlier, we do believe that the basis spread certainly (inaudible) between the (inaudible) and equal continue to expand. So if there was a fall in production, we would still have that capacity with Waha production – production or other areas across state.

Okay. And on these new products right now – new projects that you’re doing, when you sign up a new – when you decide to build a new pipeline, how long are you expecting that pipeline to be full for? I mean are you seeing – are you looking at production profiles right now for the new pipelines that are coming in off of these shale pricing? Are you looking at these pipes being full for 10 years, 15 years, 20 years? How do you guys think about that?

Well, it remains public – in our press release from (inaudible) 15-year deal. If you look at the production curve from the major holders of acreage in that area, a lot of them see their production peaking in 2020, 2021. So you really expect a lot of them will be 20-year pipelines – of flows for significant volumes. Historically, we look at end-year agreements at the minimum. And I think we’re going to see (inaudible) go more – manage for more 15-year pipelines [ph].

And also, let me add to that. If you look at our top line system and study it, with the exception of the Fayetteville shale line, which we have a plan to bring that in. If you look at what our system does, they Haynesville project that we announced we were (inaudible), it’s not Haynesville dependent pipeline. It accesses our overall system at Carthage. And that line, in fact, can move from Invasion [ph] volumes, to South Texas volumes, Bossier volumes, Barnett Shale. So we’ve been very careful to create this hydraulic machine. (inaudible) company has been dependent upon a field for your future. If you’re dependent, you got two things working that you got to consider, your volume and you’ve got to consider your margin. And so, what we have – we have gone to great lengths and spent a great deal of investment to make sure that we have a system that when one field begins to decline, that volume is being back filled through that pipeline through other (inaudible).

So when a field like the Barnett peaks in seven or eight years, does your – can you replace the volume declines on some of your take away capacity out of a field like that?

Absolutely.

And where would that come from? Where would you think that would come from.

Today, presently, that will be from the West. That will be (inaudible) from the Permian, possibly San Juan basin. We have the desire to lay a line into the Rockies, off the trans-western. So the west to east capacity that might be back filled from the Barnett shale could, in fact, from the West, including New Mexico and the Rockies as well.

Okay. The one thing I wanted to ask you, can you quantify the EBITDA in pass of the quarter on the change in commodity prices?

Half of it. Yes. And we …

Yes. How much would the EBITDA been higher if you have the same commodity prices you have last year.

Ride a couple.

Yes. We haven’t run that. We certainly have some commodity impact. But as most prior business (inaudible) we had a (inaudible), what kind of impact that would be? It could be minimal.

Okay. Thank you. I appreciate it.

Thank you, and our next question comes from Ted Green [ph] with Boston America [ph].

There also seems to be a lot of volumes, a lot of question about volumes. Everybody’s concerned about – they’re concern is about pricing. Have we started to initiate pricing, particularly on new projects to allow for a higher return EBIT to your higher cost of capital, particularly for people who view it as a distribution or even a sale of a (inaudible).

Yes, sir, Mr. Green. And let me – by the way, that’s an excellent question because I got to tell you, one of the best days I’ve had around here was when Mack and his team pulled off this Tiger amassed with this Haynesville Shale pipeline. Because up until then, we were seeing our cost of capital increasing dramatically and we were seeing commodity prices falling dramatically and it was uncertain, we couldn’t back to it, our large capital to work for our unit holders and generate the kind of returns necessary to cover those cost capitals and be accretive to our in-holes. We’ve proven that we, in fact, can do that. The Tiger project is very accretive, it’s a really good project. And it’s a large capital expenditure project, so really good question. The market is a little unusual. If you look at the demand of macro gas in this country, it’s really not deteriorating much. It has been, with our policies, it relates to natural gas being more coal-burning fuel, and I agree with that. Therefore, sure, we’re seeing great gas fall, but demand is remaining relatively constant. So we spend a lot of time here talking to our commercial people saying, get yourself in the way, you’re in between the supply and the demand. And if we’re seeing rigs following a particular appeal, that’s okay, as long as the dimensions demand for natural gas must touch our product in some form or fashion. And we created that machine, we’re very proud of that.

Could you give some comments about oil, (inaudible) interstate pipelines?

You know, I’ll tell you what, Mr. Green, I’m not the guy that should think [ph] that but I think Mr. Dan Duncan might be on this line. He has a speaking role. Dan, can you address that? He might not be. I’m not the guy to address oil.

Okay. What about direct quotes (inaudible) rejection rates? It seems to me that everybody’s all up in arms that you’re also into propane business. Was this more of a (inaudible) pattern just in the fourth quarter or will we have a permanently lower margin (inaudible) and how are you (inaudible) restructuring your P base on that regard?

Well, fortunately for us and the imports looking for us, let me address that, the majority of our contracts are in fact, P based. We don’t benefit from the commodity screens that others have benefited from. I’ll tell you airports (inaudible), when a lot of our peers were creating great distributable cash flow through our unit holders, we weren’t benefiting from that. As we stand here today, we’re still doing okay. There was a question earlier; do we suffer as commodity prices come down? Yes. It’s hard to quantify but it’s not substantial. But if you look at historically, tax spread [ph] that exists in this industry, we’re kind of operating where they ought to be. That’s probably make a lot of people angry on this call, but just look at the historical data between crude and natural gas, and this is about predictable as the ES gas [ph]. We weren’t prove [ph] this period of time, we weren’t prove over the last two to three years, in my opinion was an anomaly, it’s not a normal thing that will occur.

Finally, on the acquisition front, you addressed the question of prices are coming down, would you take over projects for other people who could not complete those projects or lend money or whatever, since you have a better liquidity and can access the capital markets?

Yes, sir.

And what kind of returns would you demand of that?

It kind of depends. Unfortunately, a lot of the commitments that have been made on projects, they probably locked in their steel cost, they probably locked in their construction cost. And those costs have fallen dramatically in the last few months, dramatically. In some cases, (inaudible) of steel is 50% of where it was before. Construction costs are following in a similar percentage. So unfortunately, when you look at some of these commitments, we also have to look at those commitments of cost. And in some of these projects, in our opinion, that we have seen that have been brought to us because of our capability, we don’t want them. There’s got to be (inaudible) for us to be interested in those projects.

Thank you.

Thank you. And our next question comes from Noah Lerner with Hartz Capital.

Just a quick follow up on the FERC update, I was wondering if you got a couple giving additional color based on amorts [ph] having settled about six weeks ago or entered (inaudible) into a settlement understanding on their case? Do you think that will have a positive impact as you guys move towards June date?

We think the (inaudible) deal is so different than the status that we’re in right now that we don’t really feel like it adds a great amount of presence. It is a little unusual for perk to reject an uncontested settled amount, but we think our back pattern is very different.

Okay. Thanks.

Thank you. And our next question comes from Ross Payne with Wachovia.

Yes, just a quick follow up. You mentioned that 85% of your revenue are P based. Let me ask you this, are these contracts all take or pay or is there a volume metric component to it? And if so, how is that broken up between take or pay and volume?

As majority of the contracts we have signed up are the main charge based. We do have several agreements that are pay increase dedicated up to certain volume levels where we can require them to turn that to demand if they want to keep it under long term. But to answer your question, Ross, the vast majority are under long term demand charged (inaudible) gas better not contracts.

Great. Okay. Thanks, guys.

Thank you. And our next question comes from Horace Raiken [ph] with Brennet Associates [ph].

It’s Ryan Gartnell [ph], thank you. I’m interested in hearing, if I may, about your views on client concentration and then just credit risk – is it false or the mood of the day around the economy. Could you speak to me whether clients have been raised fancy pay or asked you to renegotiate in these contracts of yours? Thank you.

This is Martin. They are a credit daily. Fortunately for us, as Kelcy and Mackie have indicated, our system is built around many basins, many markets, and so that’s allowed us to also have a customer base that is well diversified between utilities, the large producers, and then allocate about a small percentage of the smaller producers. Particularly, when you look at the technical assets, there are large shippers, the EOGs, (inaudible), XTLs [ph] of the world, a great credit. When we do see any product of sensitivity, we look at guarantees, letters of credit, worse case scenario is a prepayment. Fortunately, knock on wood, we have not seen any significant losses as a result of our customers being in the bulk. And anytime that we have seen that again, we’ve been active and proactive in getting those customers on a prepayment schedule as we’re staying with so many recent bankruptcy. Again, monitoring it very closely. It is a concern, but we also have the right process and controls to mitigate that risk.

And there are no further questions on queue. Please continue.

And with that, thank you everyone. And we look forward to the next time you sit down with us. Thank you.

Thank you, ladies and gentlemen. That does conclude your conference today. Thank very much for your participation and for using the AT&T (inaudible) conference. You may now disconnect.