Please standby. We are about to begin. Good day everyone and welcome to the Southwestern Energy Company Second Quarter Earnings Teleconference. At this time, I would like to turn the conference over to the President, Chairman, and Chief Executive Officer, Mr. Harold Korell. Please go ahead sir.

Good morning and thank you for being with us today. I have Richard Lane, President of our E&P Company here with me and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release, we announced yesterday, regarding our second quarter results, please call 281-618-4784 to have a copy fax to you. Also I would like to point out that many of the comments during the teleconference are forward-looking statements that involve risks and uncertainties effecting outcomes, many of which are beyond our control and are discussed in more detail and the risk factors and the forward-looking statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although, we believe the expectations expressed are based on reasonable assumptions, they're not guarantees of future performance and actual results or developments may differ materially. Well to being with, we have had a very productive first half of the year and we have… we have made a lot of progress on our Fayetteville Shale play. Our production growth of 57% over the second quarter of last year shows the strong impact of our Fayetteville Shale play is having on our results. However, we also having very good results in our base activities in East Texas and the conventional Arkoma Basin, as Richard will discuss more in detail in a moment. We continue to grow our capabilities to carryout the increased activity levels this year, as we have added now about 175 new employees in the first half of the year. For the reminder of 2007, we plan to focus our Fayetteville growing activity in the areas that have been identified as better performing where possible in areas where we have 3-D seismic data. Generally now, we're moving to the slickwater fluids systems for our frac jobs in the Fayetteville, and have begun drilling longer laterals which, coupled with additional completion stages, seem to result in better wells. So, we're continuing to make progress in our Fayetteville project, and we're seeing good results in our other base project activity areas. I would like to now turn the conference over to Richard for a more detailed update on our operations and then to Greg for a discussion of our financial results.

Thanks, Harold. Good morning. Our natural gas and crude oil production totaled 25.8 Bcf for the second quarter of ’07, up from 16.4 Bcf for the second quarter of ’06. The increase was primarily due to growth from our Fayetteville Shale play, which produced 10.7 Bcf in the second quarter of ’07 compared to 8.2 Bcf in the first quarter of 2007, and 1.8 Bcf in the second quarter of 2006. So, our build up continue there. We continue to estimate that our full year production will range between 1007 and 110 Bcfe. In the first half of 2007, we invested approximately $670 million in our exploration and production activity, and participate in drilling 304 wells. Of the 304 wells, 142 are productive, 5 were dry, and 157 were on progress on June 30, for an overall success rate of 97%. Of the $670 million invested, approximately $568 million or 85% was for drilling. We currently have 31 rigs running, 15 deep and 4 shallow rigs in the Fayetteville Shale Play, 7 in East Texas, 4 in conventional Arkoma Basin, and 1 in North Louisiana. In the Fayetteville Shale play, we drilled and completed 52 wells in the second quarter. The wells drilled range in total vertical depth from approximately 2,300 feet to 5,300 feet with horizontal sections that average approximately 2,550 feet. During the second quarter, our time to drill to total depth averaged 18 days from re-entry-to-re-entry compared to a first quarter average time of 20 days. Average completed well costs during the second quarter were $2.9 million per well compared to the $2.6 million average cost we reported for the first quarter. The increased cost is primarily due to drilling and completing wells with longer horizontal laterals. Lateral lengths for the second quarter wells have average 2,500…

Thank you, Richard, and good morning. Our earnings for the second quarter were $47.6 million or $0.28 per share, up 29% from the prior year. Our record financial results were driven primarily by the positive effect on our earnings of our increased production volumes and higher realized natural gas prices. Net cash provided by operating activities before changes in operating assets and liabilities increased to $146.8 million, up 74% from the prior year. We produced a record 25.8 Bcf in the second quarter and realized an average gas price of $6.90 per Mcf, which was up $0.67 from the prior year period. Our commodity hedging product… program also increased our average price by about $0.07 in the quarter. Our current hedge position, which consists of fixed price commodity swaps and collars, provides us with support for a strong level of cash flow. For the remainder of the year, we have approximately 75% of our projected natural gas production hedged. We have 26 Bcf hedged with fixed price swaps at an average price of $7.90 per Mcf and we have 17 Bcf hedged through price collars with an average floor price of $6.85 and an average ceiling price of $10.64. We also have hedged 85 Bcf in 2008 and 48 Bcf in 2009 at even higher prices than those in 2007. Our detailed hedge position is included in our Form 10-Q, which was filed yesterday. Our lease operating expenses per unit of production were $0.73 per Mcf equivalent during the second quarter, up from $0.64 from the same period last year. The increase was primarily due to increases in gathering and other costs related to our operations in the Fayetteville Shale. For the full year, we expect our per unit lease operating cost to range between $0.82 and $0.87 per Mcf.…

Thank you. The question-and-answer session will be conducted electronically. [Operator Instructions]. We go to Scott Hanold with RBC Capital Market.

Good morning.

Good morning, Scott.

The recent results that you have been getting is actually you seem pretty strong. Can you talk about anything that you may have changed… have you change the way you are drilling as well as drilling pattern? Or you have some of those wells has been drilling sort of with the benefited seismic data?

Well, I guess, Scott. I think there some of both there. We were trying to… as we mentioned in our comments, trying to take advantage of the 3-D seismic whatever we can, which I think generally is… right now, we would categorized that mostly out of the steering and geologic control tool. So, we get some benefit from that. And then the longer laterals, we have more completed lateral foot and we are seeing the results at least in the initial potentials there.

I think the other aspect of that to mention is we have some poor results in areas like East Cutthroat new equipment areas often the Southeast part of the play. And those have been watering down the performance that we are seeing quarter-on-quarter, and without that activity coming into this quarter. And most recent drilling wells, we are seeing benefits of having focus some of the drilling activity right from there.

Okay. Specifically that 4.6 million a day well… the Reaper well, especially because you have such relevant short lateral length. What you think happen there? Why were the results so good at that well?

Well, it’s not entirely, obvious Scott, I mean that we had a good completion go off there. And there have been some other good wells in the area. The rock looks good there. And so, it’s not clear why that… is anomalous as high it is. But we have seen that variability in the play, and we could be seeing some more natural fracturing around that well bore, but we are not sure about that.

Okay. And then secondly, you indicated you are going to be focusing on certain areas, including where you have 3-D seismic. Can you talk a little bit about those areas and where you expect to have all the seismic by year-end?

We have… we have 3-D seismic right now over… I think seven of our pilot areas. We continue to acquire data as we speak and we will be acquiring data throughout the year and processing data. So, we are… we are moving as many wells as possible into those areas. I think going forward in ’07, what we have left in front of us, probably we will be somewhere around to 30% to 40% of wells will be under seismic converge.

And if you… just from a record standpoint, for those of you have seen that bubble map that’s in our investor relation scorecard, another map is in the press release yesterday with the pilots, generally the area that we have been shooting 3-D and is the area that from Gravel Hill on the west side going easterly toward the Southwest Greers Lake area. So, certainly the 3-D is in that part of that field. And the reason for shooting the 3-D there, of course, is … we have scattered wells across this whole area. We have much less… many fewer data points in the Eastern part of the play at this point in time. We have more data points in other words, more drilled in that area from Gravel Hill to the Greers Lake… Southwest Greers Lake private areas. So, we focused our 3-D over there. And it make sense to be able to follow the 3-D with drilling behind it. So, we are still… we continue to be drilling wells over in the easterly area because there is a lot acreage still to access. But we have a combination of both going on as Richard said about 30% of the wells going forward will be drilled in areas behind the 3-D. So, it still not a high percentage, but generally over in the Gravel Hill to Southwest Greers Lake area, we have a lot more data there, well control, and now the 3-D beginning to unfold long side of that.

There is another operator out in White County shooting some 3-D as well. Are you going to be able to get your hands in some that too?

We have arrangement with another company to be able to purchase their seismic and conversely they can purchase our seismic.

Okay. Thank you.

We'll go next to Tom Gardner of Simmons and Company Thomas Gardner - Simmons & Company International: Good morning guys.

Hi Tom. Thomas Gardner - Simmons & Company International: Hey, I believe Richard mentioned plans to drill additional wells to the Moorefield and Chattanooga. Could you discuss where you are with respect to commercializing those intervals and if there is any commingling potential with the Fayetteville.

Sure Tom. We've delineated what we've… on our public data what we think is prospective for the Moorefield. If you look at our most public data, you will see an outline… a subset outline of the Fayetteville that kind of describes that as generally in the… on the Eastern side of the play, kind of a update. Remember we had our first well… first horizontal well I believe was the Carter in the East Cutthroat area that we put on production. And we were encouraged there wasn’t a barn burner, obviously commercial, but producing gas and for our first try. The second well is not very good at all, and we're kind of scratching our head trying to understand the data. It’s not very far from the other one. But we have produced a lot of water and a lot more than we should have just from the stimulations so it tells us its probably extraneous water. So, we are not sure where that's coming from. We will be doing some studies to try to figure that out. So, a couple more wells right on the horizon here soon and then from what we learn on those, those wells maybe we spud a couple more later in the year. But it’s… it’s not… I wouldn’t say we have established commerciality. It is what we have call, which is another potential zone and we will be working at trying to understand it through the rest of the year. Commingling is another challenge. If we could do that then it would help the commerciality of the whole picture. But right now, the technology… the down-hole technology is not really quite there. To have both those laterals multi stage fraced and producing up one well bore. So, that's an example of technology yet to really come to fruition that could affect that, and affect the play. Thomas Gardner - Simmons & Company International: I see. One last question, regarding stimulation effectiveness in these longer laterals in Fayetteville. Are you concerned at all about the effectiveness of the stimulation treatments at of the toe of the wells?

At the toe. Well, we… we are concerned with making sure we get the most out of our stimulations and every stage that we pump. We want to be effective, obviously. And I don’t think preferentially at the toe we have much greater concern in any other given stage. But we… our goal is to get the most out of every stage that we pump and then to monitor those and try to understand how we're doing it. And so, we have quite a bit of data that let's us know how each stage is done in various wells. Thomas Gardner - Simmons & Company International: Okay. Thank you.

We will go next to Joe Allman of JP Morgan.

Good morning everybody.

Good morning.

Hey I know it’s really days, but what would be your best guess regarding EURs regarded with the longer horizontals, and is it reasonable to assume that if the initial production is maybe 30% above your type curve that the EURs could potentially be 30% above the 1.5 or the 1.3 whichever type curve you are looking at?

Well, Joe, that’s too broad of a question I think and the reason that I think it’s too broad, is that we have such variable results across the play area. So, specifically longer laterals across the whole play… longer lateral and some parts of this, I don’t think is going to be as effective it is in some others. For example, in the East Cutthroat area that may not be effective enough to get us to the point where we need to be. Now the other part of the question is it… basically if you are seeing IP's are much higher, is it going to translate to EURs. The answer to that is, if the decline curve performs parallel to the other one, the answer is, yes. And what we need to have is we need to have time on those… on the performance of those wells, just as we have said from the beginning of all this we have been a little bit reluctant to get our… to step up very far in terms of saying what ultimate moving numbers higher. We are getting more comfortable now because as Richard mentioned in his comments, our oldest well now is getting pretty flatten out. So, we are getting to the point at least on one to three wells, maybe three wells totaling our package where we can start to see what these terminal decline rates are looking like. We would like to have far more data than that before we tell you some higher number. If that’s what it’s going to be, but higher IP is tend to… in general, if you are going to follow the same type of decline as other wells, then you would have higher EURs. And I think that you can see that if you look at the average daily normalized production graph that we put out for the average of all the wells, and then if you look at… just these cuts for one which is our poorest performing area and then the other line that’s on that graph is Gravel Hill, which is our best performing. Clearly, when you start out higher with those kind of similar declines, you are going to produce more. And I don’t know if it’s 30% more, but we will learn that little bit more over time.

That’s helpful. And then in terms of the pilot areas that will be the more of the focus for the rest of this year, so far, I think you have tested 33 pilot areas. How many pilot areas will be the focus between now and year-end?

I don’t have that exact number, Joe. I think last time I looked, I think we had about… this is not specific to your pilot answer, but we had about 20% of the wells that would still remain those seven that were still out in the less certain areas as I give you some feel for the concentration.

Okay. I get back in the queue.

Okay.

We will go next to Brian Singer of Goldman Sachs.

Thank you. Good morning.

Hi, Brian.

I think following-up on the last question and some of the earlier one. You mentioned some of the pilot areas you will be focusing on, any areas aside East Cutthroat where you purposely have a less of a focus, can you kind of talk about that regionally?

Well, I think in the… if you look at the… we have updated our map… our bubble map if you will. I think that data is out there. Now that we have put out commensurate with our earnings. And there is a lot of uncertainty there. I mean, we have talked about some areas that we have gotten a higher well count in like East Cutthroat and enough wells to kind of say based on those results it doesn't look too. A number of other areas we really just have single well test. So, we are still trying to understand those. And so… the jury is really out on those. And then what we can bring to bear there even on the poorer areas that we have identified so far. There is still more we can do there. But we were talking about really more like, probably 75% of the pilots that we have drilled in, will be more focused on, in the western side.

Okay. And then in terms of your theory from the impact of some of these higher rates, do you see that assuming that these declines are inline with expectations leading to higher EURs. Does that represent increase of recovery rates, or would that just be an acceleration of recoverable resource?

Well, it’s kind of like a… it could be both, I guess, not to avoid the question. But as you just think of pure spacing, if you drill longer laterals, then you have coverage of… if you just take a 640 section kind of our unit premise to drill longer laterals within there then you would… now you would cover the unit if you will with lots wells. And then you might say that that translates into higher recovery per well in that unit if everything else is static. So, it’s really kind of hard to pin that down. There is a lot of variables in that question, Brian. I think the other thing is we are still experimenting with the orientation of our laterals and that has a significant bearing on the number of laterals we can put in the unit. And so, there is a lot of moving parts there. We have been experimenting some with drilling north south laterals instead of on the diagonal and that affect how many you can put in the unit as well.

I think the key part of it, if you are getting higher recoveries per well than you would… you would just generally not be drilling as many wells per section, which is a good thing.

Any update in terms of the service cost environment with increased competition you are seeing there?

Well, this year… I think we kind of we were driving our own ship if we will on the drilling side there with the predominance of our own company own rigs in the play. On the completion side, we kind of held our own I think there, a combination of getting some improve pricing within the play offsetting some of the higher cost things we are doing in the completion. The pure third party side of it… the vendor side of it, we actually have some slight discount over the last year.

Great. Thank you.

We will go next to Jeff Hayden of Pritchard Capital.

Hi, guys. Couple of quick questions. First of all, I am wondering if you could give us some color on those most recent 10 slickwater fracs. Were those all concentrated in kind of one or two pilot areas? Or were those spread out over number of pilot areas you guys are currently working on? And then after that just wondering if you guys comment a little bit on spacing, what you guys are seeing? Is 80 acre spacing going to be the right number, could it potentially goes tighter than that? And then I may have a follow-up.

Well, let me address last question first. The spacing question is still up in the air about this play. We have by no means have drilled down to the point where we are talking about the optimum spacing at this point. And that goes back to the discussion on the question Brian asked to some extent. If we drill longer laterals, then we have less wells per section, which would say if you divide it by 640 that would be less tight spacing. But at the end of the day when you look at this Fayetteville Shale play and I would suggest and here is a pitch that some of you have had meetings with them, I put you on to, but for the rest of the world that’s listening, North Texas Geological Society book that was published that George Mitchell founded to have written called the Barnett Shale, which goes into the years of development that went into the Barnett. I recommend anybody understood unconventional plays ought to buy it and read it. And when I read it, in conclusion, you have to draw about it is that there is a whole lot to learn about these plays. And at the end of the day my reading of that book and others here internally whose comments I have received is, my gosh, we are learning each of the steps that were learnt in the Barnett. And one of those big ones in the Barnett is spacing. Now whatever you conclude at one point in time with the limited amount of data is probably wrong and you keep seeing them go to tighter and tighter spacing. And so on the spacing question these rocks hold tremendous amounts of gas. And the spacing question isn't just a today question and particularly…

I think, Jeff, I think the other part of your question was on the last 10 wells that looked pretty good. Where were they or were they concentrated? I think there is eight different pilots that… those were drilled in. So, they actually represent a pretty broad area, which is encouraging, it’s not just one hot spot. So, eight different pilots making up those wells.

Okay, great. And then one quick follow-on. You talked about basically not even being in development mode yet, the innovation cost. Seems like a lot of the other players. Once people have gone into development mode they do find a ways to optimize things, push costs down. Is that a reasonable expectation for us to make, it’s still really early on and once you really start going full development mode, we should see those total well costs come down.

Yes, once we have settled on the basic design, but as you be sure you keep in mind as we are drilling all the laterals, they are going to cost more. Not just because of the drilling, but in addition because of the additional fracture stimulation. And our real task is to figure out where is the optimum level there.

Okay. Thanks a lot guys.

We will go next to Gil Yang of Citigroup.

Good morning. Just following-on the same line of questioning everybody else seemed to be focusing on. The 10 best wells, are they drilled… you maybe mentioned this… are they drilled with seismic or without seismic? What made that consistency so good, what was different?

Well, they are not all under 3-D seismic, Gil. Probably… maybe half of those… something like that were under 3-D seismic. I think the improvement is just the constant monitoring of what we are doing and the technologies that we are applying and just trying to improve each well as we go forward. We have, of course, we have longer laterals in those wells. And we have less of a mixed bag of the types of fluids. As we reported, we are concentrated on the slickwater fracs. So, I think it’s a refinement of where we are heading and there will be more changes still but…

And Richard, if I might add to that. There are going to multiple factors that there come into play in these plays. Some of which we don’t know in advance. So, I guess, I would say one of the obvious reasons that those 11 or 10 wells were better is they weren’t drilled in poor areas. Now, you guys say to me well how do we define that? And it’s a good question, but maybe it opens up somebody’s eyes to be able to really understand it. So, when we have been drilling in areas where we have no control and if you pull out the map that shows the bubbles again, any bubble that’s blue means there in not very darn much control there because that means that either the first or second well drilled there. And on those blue bubbles as you look around them, they are 10 miles to 20 miles from the nearest blue bubble. And so anytime you are drilling, where you don’t have control, you are not going to know very much about what you are going to find. Now, that may lead to the conclusion, well, some of those areas maybe poor. And some areas in this play I think will be poor… poorer just as they were in Barnett. Some parts of it it’s going to... we are going to turn out some day, I would guess we will be able to say what the core area is and what the non-core area is much like they have described over time in the Barnett. And the likelihood is the core area is going to be very good economics. The non-core is going to take more work to make it actually economic. So, some of it is that just simply that, Gil, is…

Okay. Second question I have got is, have you been able to do sort, of course, more than sort to speak and we are using 3-D shot over wells that have been particularly good. Have you been able to determine what makes those areas… what made those wells not good and thereby going with the solution to that problem?

Well, very clearly we know when we drill two fault zones, we don’t get good wells. And that is… that’s been a factor. Certainly, where we have our oldest data setting, Gravel Hills, wells, we drill two fault systems and much like read the Barnett book… much like in the Barnett when you do that, you either losing the frac energy and that fault zones or there are some meteorological changes along that from waters moving throughout the years or something that causes not that to do as well. And then when we orient wells away from that we have good wells. So, yes, clearly we know that. I don’t think it’s much of a coincidence with like Gravel Hills one of our best areas where we had 3-D in the longest.

Okay, terrific. Thank you very much.

We will go next to Michael Scialla of A. G. Edwards.

Good morning, guys.

Good morning.

I guess at the risk of beating with to death, but I just want to ask one more time about the 10 recent well, that they do continue to perform the way you would expect, can you venture a guess as to the averaging you are on those 10?

I think Harold is going to really claim that well already, Mike. I think the answer is no. I don’t want to hazard a guess. The obvious thing is that we are getting better near-term performance. And you would hope that would translate in the better overall well performance. But it will depend on how they confirm to the declines that we have already seen.

Sure.

If they do that then we ought to get something good from it.

Okay. And then on the spinning plans for the Fayetteville this year, you are saying 950 million, is that going up? You saw that one point where you are looking at like 840 or there is some allocation issue there or am I just misreading that?

No, Mike that is number that Richard talk that included the gathering that we have to. So, there is about 840… you are right of E&P and then the balances is… is about 875 of the E&P and the balance is gathering.

The number hasn’t changed.

Okay. Thank you.

We will go next to Michael Bodino of Coker & Palmer. Michael Bodino - Coker & Palmer: Good morning, guys.

Good morning. Michael Bodino - Coker & Palmer: I had couple of questions here. One is on the conventional sands, you have had some very good wells and the rumor is that how Woods well was conventional sands that produced 6 million a day. How big of a play can these conventional stands to become as part of this whole program?

Well, it’s undetermined that I think the exciting part of that if you look at the map it shows where the conventional zones are that we have conventional wells, we have producing there. They are across at pretty darn broad areas. So, it’s a pretty exciting potential. I mean if you go over to the Fayetteville, we know what that looks like. And as a tremendous resource there that has been harvested through the years. We have less zones to chase than what exist in the Fayetteville area. But nonetheless, we have encountered this… these zones across the really broad area and some of them have been outstanding producers when you would compare them to a typically well that you might drilled on the Fayetteville right now. so, I can’t quantify for you, Mike. But we should like to where we think so far. Michael Bodino - Coker & Palmer: What you all are seeing on the kind of western side of the play in terms of maybe the Hale sand different than what maybe they are seeing on the White County in terms of conventional… on the same conventional zone?

I think it’s the same general stratographic section that people are looking at and having some success with.

The same thing about, Mike, to me is that this really has not been worked. And we are only beginning now to do the work. And of course one of the reasons, there has been a lot of work done. There haven’t been a lot of well penetration. So, now as we are drilling wells through that section, we are encountering these gas shales, and then it’s a matter to starting to put maps together with what data you do have and as that 3-D sweeps across here, that’s going to be huge improvement on our ability to look for these conventional zones, and then the conventional plays become a very real key and important part of the play. I think because they are very expensive to drill first of all. and rates when we are getting $3 million or $4 million a day out of a well, across the 7,000 drilling complete, those are kind of home run economic. So, we have got people now specifically mapping in the conventional which we have not really had after and on. I think until now we have been so focus on answering all the questions that we have and everyone else have about the Fayetteville but on the way down we are going to look and it’s not just a limited because we now have gas coming out of the wells that are spread across… I don’t 50 miles or 60 miles here in the east or west. And so basically, we have unexplored basin and no one really knows we expand a bit in the section that’s just shallow lower than the Fayetteville and then who knows what's deeper. The majors made a play in here, so there are back holding 70s that there are potentially other parts of that section that we haven’t begin to our binoculars on. Michael Bodino - Coker & Palmer: Will this be part of your program in ’08?

That’s part of our ’07 program.

And we have some of those shallower rigs that are capable of drilling some of these too, so we can get on them pretty quickly and have natural completion, so they are not extensive. So, yes and we are very focused on it. Michael Bodino - Coker & Palmer: Thanks very much guys. I will get back in the queue.

We will turn next to Robert Christensen of Buckingham Research.

That’s breath of fresh air, kind of talking about the conventional. On that same subject, you had the Lawrence Well, [Technical Difficulty]

We can't hear you, Bob.

You have the Lawrence Well, and Falkner, and the Tharpe in White County, both with designated hail completions, and on the day that we got from the got from the Arkansas and Gas Commission, we didn’t get an IT. Would you care to venture what those two wells did in their first year?

Let’s see, I am just looking at your data, Bob. I don’t have it in my head but I think I have the data here. And we are testing about 2 million cubic feet per day and we are right on hooked up for that. And what was the other one?

The Lawrence 8-12 that was in Tharpe.

Yes, the Lawrence was about 1 million a day.

Okay, well. And how many more sale attempts did you say you would conventional attempts you would have this year?

I said several; I didn’t say exactly, but we have I think four wells that are not in that producing base. We have talked about waiting on completion or hookup to pipeline. And then we will be… I don’t know exactly how many but what we are trying to gear up to do is to have kind of a small rig program that we can get enough of these locations off that locations map, where we can just stay after it with a rig.

Are these future wells here, say, second half to the hail, are they done on 3-D, or are they just geologic sort of, mapping at this point in time, or is the 3-D already bearing fruit for the convention?

Well, some are within 3-D and some are not, so it’s a combination of working all the data. And I would tell you, when we are offsetting one of these good ones, we have already have, we are trying to get a geologic handle on the shape of the sand bodies and trying to offset them in the most certain place to start with. Others, we have some 3-D and we have got some interesting work going on, looking at the 3-D data to see what kind of second order things we might glean from it that relates to the conventional production.

Finally, you have indicated something below the Mississippian-age Shale, I mean are you… you have seen Arbuckle on that 3-D yet?

Well, we see very deep into this section with the new data that we are acquiring and its good data. We can see… seismically we can see very deep in a section, which would take you down through that. I think interesting section below the Fayetteville but yet above the Arbuckle, some interesting carbonates that exist in our productive… in the basin to the west. And have some very interesting structural styles to them that they give you some hope that you could have carbonate traps of significance but that’s really speculative right now.

One final question if I may. What happens when they put compression on one of your older Fayetteville wells? Say we go out of that well that that was graphed and its 640 days old. What happens when you put some compression and draw down the surface pressure, what kind of response do you think we would see? We will be adding the reserves if we added some field compression?

Well, I mean we have compression in the field now, that’s how we eventually pumped this gas into the transmission lines that are 1000 PSI. So, we have to have compression to pull the gas from our well bores. There are opportunities throughout the field to optimize that compression. As we get further end of the development, we would have some wells that may have a higher well head producing pressure that if we drill it down, would produce currently at higher rates and then you would get the increment of gas that would become, say if you are producing at 150 or 200 pounds well head pressure and you got down to 50, the PVT is going to tell you are going to get more volume ultimately.

So, that changes the EUR?

Yes, you pull incrementally more volume out with lower pressure. It’s just simply the physics of it, but right now I don’t think that has much of an impact on the numbers as we are looking at them today. But ultimately, that’s what happens in every gas field; if you put more compression on it, then ultimately you get a little more gas out over the years.

Thanks. Great progression there as I said.

Thank you.

We will go next to David Heikkinen of Pickering Energy.

Good Morning. Just had a question about for a new player like North Louisiana or Appalachia to be core for Southwestern, how big would it need to be?

You mean in what kind of a resource?

Yes exactly; resource size, what would your skill set desire be if you get into a new area?

Well, I think it depends on the economics, David. And it would depend on how much traction we could get in a new play and how much we control? It’s just kind of hard to quantify. Obviously, as we grow, we are looking for projects that can have an impact and what has to be specific beach area.

I would say, you know its baseball season; and when we go to bat, sometimes singles are okay, and sometimes doubles and sometimes triples and sometimes you steal the base and sometimes you try to hit a home run. And so it could be all sides as it depends on the risk and the situation we are in. The one rig running in North Louisiana, how big of a play is that?

Well, I that’s a cold bed nothing play. I think there is more acreage there; the full extent of the play, I don’t think we fully understand, but it’s in the low 100 Bcf type range, and could grow from there, then on how much acreage we could pull together.

So, an acreage is where there.

Our gross acreage amount.

Growth in that.

I don’t have that in front of me David. We can get that too though.

And then, kind of looking forward where you are now in the Fayetteville with the number of wells awaiting completion and then how that moves forward as you go into a focused development. What do you think the backlog of wells will be in the third quarter and fourth quarters as you move forward?

It’s a challenging part of the project for our operations to manage. And every time we think we know exactly where it’s going to be, it will swing pretty dramatically, and if we get some efficiencies in drilling, all of a sudden we are eating into that inventory. But I think 20 to 25 wells is kind of a reasonable inventory of wells waiting on completion to have. We have seen that if we get a lot less than that, then may be there’s some waste in the logistics that would be more of a factor than the discounting or waiting on the capital. So, I think we are in about 25 right now, which doesn’t feel too bad.

So, no pick up swings or down swings as you put a rig in and run that going forward?

Yes. And we have the completion units there that we have run and which seems to be keeping pace with that. And we have resource that we could add to that if we need to. I think CBM acreage is about 28,000 gross and 20,000 net David.

And then, just your production per area in the second quarter, I have the Fayetteville and East Texas, could you just pick through that?

Yes, the Permian was 1.2 Bs, Gulf Coast 0.3, just about a tenth out of the… our unconventional assets, new stuffs and…

And then conventional Oklahoma?

6 Bcf, it’s about 25% higher than year-over-year same period.

That’s perfect. Thanks guys.

We will go next to Travis Anderson Gilder, Gagnon & Howe. Travis Anderson - Gilder Gagnon & Howe: Got a minor question. I notice that you said that you got about 76,000 acres now held for production, which would imply that you have only brought on about 120 wells and that’s… that correct?

Well, we have some, we are holding 640 acres with a producing well, but we have units where we have more than one producing well in units. Travis Anderson - Gilder Gagnon & Howe: Okay.

It’s not that simple. Travis Anderson - Gilder Gagnon & Howe: I thought you all were really widely scattered.

Yes. Travis Anderson - Gilder Gagnon & Howe: Okay.

And we will go next to Joe Allman of J.P. Morgan.

Hi again everybody. Regarding the conventional well in the Fayetteville Shale area, it seems that the production is holding up fairly well from the initial rates. Is that right? And also please confirm the costs at around $700,000 of drilling complete for the average of those five wells and then do you expect to have like one or two week program going forward in that play?

Well, I think, you are correct. On the flatness of the productive rate has got us paying attention to it for sure. So, we are seeing wells producing in the 2 million, 3 million and 4 million a day and holding up very well. So, your observation is correct. Joe, I think that’s really nice looking production. And the… those well costs I think are in line. What kind of the average or what we would see there. Because like I said earlier they shallow or Harold said earlier, they are shallow and we can get to them pretty quick. And we don’t a lot of completion costs for those. Fairly simple completions to get those kind of rate, so we are not having to pump big stimulation. And then the rig program is, we are just going to have to flush that out here later in the year. Certainly, wouldn’t… don’t know how much, how many rigs we would have on just that program next year, but we are trying to… kind of a goal for me right now is to try to get where we can have one those shallow rigs stay busy, at least later in the year here, but it just depends how many locations we can get mapped up and get through the integration process and things.

Helpful. In your map there, you mapped out kind of the area that you say is perspective for the Moorefield. What is the data that you have that technology that specific area is more perspective for the Moorefield versus a… stuff to the south, southern part of your, more central development?

Well, it would be I guess the, how we have delineated that perspective area would be where we see it thickening and it's not as thick in other areas. And where we see decent attributes on the logs that tell us it's a gas-bearing organic rich shale. So, I mean, that’s how, roughly how we have outlined that perspective area within our acreage. And then going much further south of our acreage we haven’t looked that hard at that.

I mean have you taken your Fayetteville Shale well deeper just so you can have a look at the Moorefield or are you looking at older logs that previously went to the Arbuckle or somewhere?

Well we have purposely deepened pilot holes, strap tests to go through the Moorefield to get a look at it and to gather data.

Got you. And then that Bartlett well, what was the cause of the Bartlett well and the horizontal well?

I think that was about 2.9.

Even though it was a fairly low lateral, it was cheaper? I know it's kind of an average, but cheaper than other.

Yes. I will have to confirm that for you Joe. What we have going on in the well cost that is probably worth noting. We tried to give this reporting of comparison of previous quarter, but obviously the other thing that go into that are, where are the wells being drilled? And we have shallower parts of the play and deeper. And so we’re waiting at where those wells are would affect the period on period reporting and then… and obviously the length of the lateral. So all that goes into it.

And then lastly can you make any comment on what’s going on in the kind of West Texas Barnett/Woodford/other stuff?

Our holdings out there?

Or just any activity, any insights into that play, any updates?

It’s still lot… I think there is still lot of in the air there. We are seeing a little bit more of well data, but not a lot of it and its pretty scattered. So I think the jury is still way out on that play. It’s such an enormous area that has been leased up. It’s hard to believe that it’s all going to be good and it’s also to me hard to believe that there isn’t going to be some part of it that’s good. We are as we reported before we are kind of watching and waiting there a little bit with those higher cost horizontals.

Okay. Thank you, guys.

[Operator Instruction] We will go to Michael Bodino of Coker & Palmer. Michael Bodino – Coker & Palmer: Thanks for taking one more for me guys. Real quick question. I know we talked quite a bit about this earlier in terms of different variability in these wells, and I just wanted to ask Richard a question. Couple of years into this how would you asses even in some of your core areas the variability is it depth of the reservoirs, if the reservoir is at completion, length, lateral? I mean I assume that in every area you get a curveball on some variable out there that you have to work on, but is there any good rule of thumb that you would look and say in certain areas certain variables are more omnipresent?

Well, I would say this that we don’t have… we don’t see the criteria that would say certain depths are where it’s going to be good and other depths are not going to be. We have seen the variability within areas at different depths, so that’s not… I don’t think that’s a real driver. I think the main variability and I will give you a general answer, but we haven’t figured all that out yet. I think the main variability will be in the rocks, in the quality of the reservoir and how those rocks react to being fracture simulated. We have seen the variability in a macro and a micro sense, Mike.

I think I am going to add that because how the rocks reacting or simulated also means structural features that are present in the area where you are drilling. So the structural things like faults are important. Michael Bodino - Coker & Palmer: I assume there have been a lot of questions regarding this and I think it sounds like lot of the focus is on the frac design more than anything else and I just wanted to clarify that maybe more reservoir driven than anything else?

Well, it’s a good point Michael. Every one of these elements will be important and I think that any point in time that you believe the answers in these kinds of reservoirs until you have more of the data unfolded. You don’t… you just don’t know for sure. We know for darn sure that if we don’t pump a good frac job, if we only get two of the stages done, that’s a poor well. So right off some of that answers some of them mechanical problems if you don’t have a good cement job, the frac doesn’t stay in its zone. So within given pilot areas we know we have those kinds of difficulties. So simply the frac simulation is really important to it, but then the structural things we know in Griffin Mountain where we first began drilling. We had pretty poor results in a number of vertical wells. And then we moved away from that fault zone and started getting better wells. So we know that’s important. And then the gas in place, the original rocks, the clay contents all of those things are going to be important. But when you are drilling in… the other important thing is there is a 100 miles across here where we are producing gas in the east to the west direction. And so you know there is gas in there. The question is… and well the other thing, Richard didn’t say this, but it’s obvious, its thickness is also important. There are some areas here like where, like East Cutthroat is about 100 feet thick. We talked about that in the last conference call. Why is that? And so understanding those macro geological things are important and we are just now all getting the… starting to get the picture by drilling enough penetrations, so that we can understand the big picture geology. If you go back to the, read the Fayette… read the Barnett book. Don’t just listen to the news go read that book and you will see what’s unfolding here. Michael Bodino - Coker & Palmer: That helps a lot and I know statistically, we are going to get a lot more wells drilled, so we are getting a lot more good wells and we are just trying to understand whether we are getting an area that everybody has gotten more comfortable with and that’s what’s the creation of that or whether its something else.

I think it’s a combination of all the things because there will be certain areas that you identify that are really working well. And so you want to poke some holes in there continuing to drill on new sections where you can. But we also need to continue to poke holes where we don’t know the answers yet. And so that we can began and we can evolve to an answer. Michael Bodino - Coker & Palmer: Well, thank you very much Harold.

We will go next to Joe Allman with JP Morgan.

Sorry about that guys. In terms of the slick water, why do you think the slick water is working better than the crosslink gel?

It is a more complex factor treatment and connects up with more of the rock per dollar that we have pumped in there.

And just a quick one. The Jebel for the Travis Peak, that was a vertical well?

Yes. It's a vertical Travis Peak well

Okay, all right. And then Richard, you made a couple of points earlier in the presentation you were saying that one thing… three things observed into the IPs are 200 Mcf higher and then you are talking about slower decline. What was the other point you were making on the recent wells?

Well the IPs are a little higher, so you just you are seeing some of those are good wells affecting that big data set. And it’s a big data set, so they have to be pretty good to push it up. I commented that in the year or 180 day kind of period if you compare the old data set, the old data set was a little higher in that period not very much but a little bit. So, you are seeing some of the affect of some those four wells washing through. The third point I made was that in our oldest time production data, we see a nice flattening in the conformance, if you will to kind of how we have tight curbs. That’s I think the real positive thing for us to be seeing. It’s just a few wells as Harold pointed out but well that’s sure what you want to be seeing. And what I didn’t say really, a fourth point would be is if you drove the 180 to two quarters more on top of that, you will actually see that, we are a little higher in that period of results with the prior reporting.

And then you made another point in response to another question about the Moorefield and you are saying that technology is not there yet for the Moorefield. What technology were you referring to specifically concerned?

I think that was a sub-question that was asked about duly completed.

Duly completed.

Just mechanical challenge right now to do that. We hear about dual horizontal and things but when we are trying to isolate and do the multi staged fracs and the multiple laterals that’s where the real challenge is.

But the Moorefield want you to get off face on that. I mean the thing… where I see the Moorefield is and we have an area where we delineated where it could be prospective and we have one well that looked pretty darned good we drilled, the Carter well and then the follow-up well, Richard just talked about is producing a lot of water, its producing more water than we put in there. We don’t think its coming from the Moorefield section itself but we must fraced. Generally, we think fraced into something deeper that has water in it. And so, we got to go back and deal with how do you keep that from happening. Or maybe there is some false system there that we are latched up to and it’s bringing water. We don’t know the answers, but again it may be like some portion of the Barnett turned out where they had some water problems below the Barnett and getting the Ellenberger. We may have that happening with the Moorefield that you are having deal with it. So, we surely in the Moorefield, we just started and we have got a lot going on. Its hard to say maybe even we should try to focus a whole lot on the Moorefield right now as far as our activity in my mind.

Okay, very helpful. Thank you.

At this time there are no further questions in the queue. I will turn the conference back to Mr. Harold for any additional remarks.

Okay. It’s been one of our longer ones. I think we are at about an hour and 15 minutes now. So, I appreciate all the questions, they are good questions. I think it helps everyone to get a better understanding of what's going on here. And here we are now I guess about three years into the drilling activity. Seems like a long way. It’s not much compared to 18 years spent in the Barnett before things started working. So, I think the benefit of what they have learnt here but we are still early in this. It’s a big area; if we were focused in say 50,000 or 60,000 acres of leasehold position here I think we could tell you everything. But its 900,000 and it takes a lot of drilling, a lot of understanding and a whole lot of work. And that’s where we are. Appreciate your time. Thanks.

That concludes today’s conference call. We thank you for your participation.