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Executives

Harold M. Korell – Chairman and Chief Executive Officer

Steven L. Mueller – President and Chief Operating Officer

Greg D. Kerley – Executive Vice President and Chief Financial Officer

Analysts

Michael Jacobs – Tudor, Pickering, Holt & Co

Robert Christensen – Buckingham Research

Brian Singer – Goldman Sachs

David Heikkinen – Tudor, Pickering & Co.

Michael Scialla – Thomas Weisel Partners

Jeff Hayden – Rodman & Renshaw

Nicholas Pope – Dahlman Rose & Co.

Thomas Gardner – Simmons & Company International

Jason Gammel – Macquarie Research Equities

[Cedula Mercy] – CDP US

Scott Hanold – RBC Capital Markets

Joe Allman – JP Morgan Securities, Inc.

Dan McSpirit – BMO Capital Markets

Southwestern Energy Co. (SWN) Q2 2009 Earnings Call July 31, 2009 10:00 AM ET

Operator

Welcome to the Southwest Energy Company second quarter earnings conference call. (Operator Instructions) It is now my pleasure to introduce your host Harold Korell Executive Chairman of Board for Southwest Energy Company.

Harold Korell

Steve Mueller and Greg Kerley our Chief Executive Officer and Chief Financial Officer are with me here today. If you have not received a copy of yesterday's press release regarding our second quarter results, you can call 281-618-4847 to have a copy faxed to you.

Also I'd like to point out that many of the comments during this 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 in the risk factors and forward-looking statement section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe that the expectations expressed are based on reasonable assumptions, they're not guarantees of future performance and actual results or developments may differ materially.

Well, we're here to report another very good quarter despite the low commodity price environment. Our gross operative production from the Fayetteville shale reached significant milestone of 1 Bcf per day in July compared to approximately 500 million cubic feet per day at this time a year ago. It is truly amazing to think that it was only five years ago when we told the world about the Fayetteville shale play and our gross production from that play alone is now over 1 billion a day.

We've learned so much during that time and continue to do so as productivity of our wells continues to improve with each quarter. While current gas prices remain low, we believe lower industry drilling activity will result in higher prices over the next 18 months. With our focus on value creation and a world class resource to develop in the Fayetteville shale we are well positioned, not only to weather the current low commodity price environment with our strong balance sheet and financial flexibility, but also to benefit greatly when prices return to more normalized levels.

I'd like to now turn the conference over to Steve for more detail on our E&P and Midstream activities and then to Greg for an update on our financial results, and then we'll be available for questions.

Steven Mueller

During the second quarter of 2009 we produced 74.3 Bcfe up 65% from second quarter of 2008. Our Fayetteville shale production was 60.6 Bcf double between 9.6 we produced in second quarter of 2008.

Our remaining second quarter production came from East Texas where we produced 7.8 Bcf and from the Arkoma properties where we produced 5.8 Bcf.

In the first six months of 2009 we invested approximately $852.5 million in our exploration production activities and participated in drilling 388 wells. Of this amount, approximately $695 million or 82% was for drilling wells. Additionally, we invested $102.5 million in our Midstream segment almost entirely in the Fayetteville shale.

In the first half of 2009 we have invested approximately $793 million in our Fayetteville shale play including both our E&P and Midstream activities. At June 30 our gross for operator production was approximately 990 million cubic feet per day up from 850 million cubic foot at the end March.

We currently have 17 rigs drilling in the Fayetteville shale, 13 that are capable of drilling horizontal wells, and four smaller rigs that are used to drill the vertical portion of the wells. We expect to participate in approximately 575 gross wells in 2009.

As we discussed in our last teleconference, during 2008 the majority of our gas production in our Arkoma basin was moved to markets in the Midwest. This included the Fayetteville lateral Phase 1 portion of the Texas gas transmission or Boardwalk pipeline, which was placed in service on December 24. On April 1 the Fayetteville lateral Phase 2 and Greenville lateral portions of the boardwalk pipeline were placed in service and we began transporting a portion of our gas to eastern markets.

As a result of recent inspections, repairs and maintenance on the Fayetteville lateral, we have experienced curtailments that have impacted our ability to transport our production from our Fayetteville shale. Beginning in April 2009 Boardwalk reduced the capacity on or shutdown the Fayetteville lateral on several occasions due to various activities, including maintenance and pipeline inspection.

These activities, as well as similar repairs to the Greenville lateral, are expected to continue resulting in further curtailments. As an example, the southwestern operating gross production exceeded 1 Bcf a day on Monday and Tuesday of this week. A line inspection was started on Wednesday and total production was reduced 825 million cubic foot per day gross. And then this morning the production is now restored over a Bcf a day.

Currently our transport capacity is sufficient for us to produce our operator wells at approximately 1 Bcf a day. Our net share of this plus our outside operating production is approximately 715 million cubic feet a day.

Once repairs are started on the Fayetteville lateral Phase 1 facility then the Boardwalk pipeline, transport out of the production area will be limited to the existing Ozark and center point systems. We estimate that our total operator production will be curtailed to approximately 600 million cubic foot per day gross or 450 million cubic foot per day net.

In anticipation of these continued pipeline curtailments, we have revised and widened our previous gas and oil production guidance range for 2009. Previously it was 289 to 292 Bcfe and now it is 278 to 288 Bcfe. This revised production guidance is based on the portions of the Fayetteville lateral Phase 1 facility being out of service for 45 to 60 days starting in September and assumes total curtailed volumes will be approximately 15 Bcf.

At this lower production guidance, we will expect to have production growth of approximately 45% over the 2008 levels. Since 2007 the continuous improvements of our completion practices has resulted in quarter-over-quarter improvements and an average initial production rates. The average initial production rate for wells put on production second quarter 2009 was 3.6 million cubic foot per day per well. This is the highest average rate for any quarter since project inception up over 7% per day from our previous high of fourth quarter last year.

During the second quarter of 2009 our horizontal wells had an average completed well cost of $2.9 million per well, average horizontal lateral length of 4,123 feet, and average time to drill to total dept of 11 days from reentry to reentry. This compares to an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,874 feet, and average time to drill to total depth of 12 days from reentry to reentry in the first quarter of 2009.

I'll now move onto our Haynesville shale activity where we see encouraging results. The first horizontal well in our 50/50 joint venture targeting the Haynesville Bossier shale and Shelbine and St. Augustine county Texas the Red River 877 #1 reached total depth in the fourth quarter 2008.

This well, which had a completed horizontal lateral of 2,718 feet, was production tested a rate of 7.2 million cubic foot per day in the first quarter of 2009, and is currently producing approximately 1.8 million cubic foot per day.

The second horizontal well, the Red River 164 #1, was drilled approximately five miles to the southeast and reached a total measured depth of 17,124 feet with a 3,800 foot horizontal lateral. It was production tested 13.4 million cubic foot per day in the second quarter and is currently production approximately 7.8 million cubic foot per day.

We have completed drilling the third well, the Red River 619 #1 located in San Augustine County, with a measured depth of 17,244 feet and a horizontal lateral of 4,000 feet. Our fourth well, the Burrows Gas Unit 1H was recently spud. These wells are being monitored very closely and Southwestern Energy may participate in four additional Haynesville Bossier shale wells this year. The capital for this drilling is included in our total 2009 capital guidance of $1.8 billion.

Finally, we're participating in drilling 13 wells in conventional Arkoma basin and 23 wells in East Texas during the first six months of 2009, 21 of the east Texas wells are James Lime horizontal wells. Production from Arkoma and East Texas properties was 11.6 and 15.6 Bcfe respectively for the first half of 2009 compared to 11.9 and 16 Bcfe for the first six months of 2008. We currently have two operated rigs running in East Texas and none in the conventional Arkoma.

In summary, our E&P and Midstream businesses are expected to have continued strong results in the remainder of 2009 and beyond. We continue our focus on adding value, significant values created as we improve the operation and production performance of each well drilled in our world class Fayetteville Shale resource. In addition, we're also excited about our future opportunities at Haynesville, James Lime and Marcellus shale's.

I will now turn it over to Greg Kerley who will discuss our financial results.

Greg D. Kerley

As Harold and Steve have indicated, we had a very solid second quarter. We reported net income of $121.1 million or $0.35 a share for the quarter, down approximately 11% from a year ago as our production growth almost completely offset the effects of significantly realized lower natural gas prices.

While our cash flow from operations, before changes in operating assets and liabilities, was actually up 13% over the prior year to $325.3 million. Our average realized gas price during the second quarter was $5.01 per Mcf, which was more than $3 per Mcf lower than our average realized price a year ago. Our commodity hedge position increased our average realized gas price by $2.11 in the second quarter and our locational market differentials for basis improved from first quarter levels to approximately $0.60 in Mcf.

We currently have approximately 66 Bcf of our remaining 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.43 in Mcf. We also have basis protected on approximately 50 Bcf in the third quarter and 30 Bcf in the fourth quarter of our expected gas production through hedging activities and sales arrangements at an average differential of NYMEX gas price of approximately $0.35 per Mcf. Our detailed hedge position is included in the Form 10-Q that we filed this morning.

Operating income for our E&P segment was $174.4 million in the second quarter of 2009, compared to $215.1 million in the second quarter of 2008. The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses, which were partially offset by the 65% increase in our production volumes.

Our total cash operating costs continue to be some of the lowest in the industry. Our lease operating expenses per unit of production were $0.73 per Mcf in the second quarter of 2009 compared to $0.95 for the same period in 2008. The decrease primarily resulted from the impact that lower natural gas prices had on the cost of compressor fuel.

General and administrative expenses per unit of production were $0.34 per Mcf in the second quarter of 2009 compared to $0.41 for the same period last year. The decrease was primarily due to the effects of our increased production volumes, which more than offset increased compensation and related costs associated with the expansion of our operations.

Taxes other than income taxes were $0.08 per Mcf in the second quarter down from $0.16 for the same period in 2008 primarily due to lower commodity prices. Our full cost full amortization rate dropped to $1.46 per Mcf in the second quarter down from $1.82 in the first quarter of 2009, and down from $2.01 in the prior year. The decline was primarily due to the non-cash ceiling test impairment we recorded in the first quarter of 2009.

Operating income from our Midstream Services segment grew to $27.8 million in the second quarter up from $15 million for the same period in 2008. The increase was primarily due to higher gathering revenues resulting from the significant increase in our gathered volumes, which were partially offset by increased operating costs and expenses.

As of June 30, we had $196 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.2%. Our revolver balance included borrowings to pay off $60 million of senior notes during the second quarter. For the first six months of the year our debt outstanding increased by $135 million, resulting in total debt outstanding of approximately $871 million at June 30 and a debt to capitalization ratio of 28%. We have a strong balance sheet with significant financial flexibility and are well-positioned to weather the current commodity price environment.

That concludes my comments. So now we'll turn back to the operator who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first call comes from Michael Jacobs – Tudor, Pickering, Holt & Co.

Michael Jacobs – Tudor, Pickering, Holt & Co.

I'm trying to reconcile average economics in the Feds on the context of better IPs and EURs with respect to down spacing. Going forward should we apply different spacing assumptions to areas with higher or lower EURs?

Steven L. Mueller

I don't know if there are necessarily areas with higher or lower EURs. If you look at what we've done in the last 12 months, there's 3 million a day, across wells, across entire acreage that we've been drilling on. There's certainly though a scatter in wells as you drill. I'm not going to say they're all 3 million a day. You get all kinds of scatter even near some of the better wells. So I'm sure exactly what average you should use. I think the key point is that we're continuing to learn, as we learn both the EUR and rates going up.

Michael Jacobs – Tudor, Pickering, Holt & Co.

And if I can move to East Texas, pretty impressive rates, can you share the cost of the St. Augustine well and then put that in the context of targeted costs for East Texas and how you drive down costs over time?

Steven L. Mueller

And you're talking about the Haynesville, there?

Michael Jacobs – Tudor, Pickering, Holt & Co.

Yes.

Steven L. Mueller

The first two wells had a lot of science with them. We drilled vertical first, cored them, did all kinds of other things. They're well past $10 million. The third well that we just recently TDed, we have got pipe run, it's a 4,000 foot lateral and we're a little less than $5 million to date. So we think we're going to be getting that done in somewhere between $9 million and $10 million.

And that's the range I think that starts talking like some of the other operators are doing on the Louisiana side. There will be some more that we can take out of it, but we've already learned a lot and we've taken a lot out in the first three wells.

Operator

Our next question comes from Robert Christensen – Buckingham Research.

Robert Christensen – Buckingham Research

First question again is a Haynesville question, how are you selecting your positioning of these wildcat attempts? What goes into that decision making?

Steven L. Mueller

Well, we do have 3D over most of our acreage that we're drilling on so from a geological standpoint we're looking hard at the 3D. The next three or four wells that you see drilled, we have checked with partners and we're sharing some of the risks. So not all of those wells will be a 50% working interest for our company so that's the other major thing we're doing, we're sharing some costs as we drill some of these wells and test them.

Robert Christensen – Buckingham Research

That doesn't say anything about the location. You're drilling on the partner's acreage or they have a decision in the wildcatting? I'm just trying to think, are you seeking better rock somewhere? I mean the latest one –

Steven L. Mueller

The Haynesville on our acreage, we've got enough control right now that we can comfortably say that Haynesville across our acreage is between 130 foot and 160 foot thick. The first two wells, as I said, are about five miles apart. They're in what we call our jumble block which is we have three big blocks of acreage. It's the central block and for the immediate future most of our drilling will be in that central block. All of the wells in 2009 will be in that block and then as we look for 2010 you'll start to see us test on those other blocks.

Robert Christensen – Buckingham Research

My second question relates to, this may be heresy in the energy patch, limits to productivity in the Fayetteville shale. We've been tracking it for years quarterly, quarterly. I really appreciate the table that you guys put up quarterly. It's so useful, but at some point in time is there some limits because this is just a great quarter, Steve?

Steven L. Mueller

Yes, we've got a long list of things we're still trying. And we've talked in the past about how many stages we fraced and we talked about how perf intervals got lower. I will tell you that from a perf interval standpoint we did our first 75 foot perf intervals late last year. We did some 50 foot and preliminary information and we're not seeing much difference between those, that's very preliminary and we've still got some more to do, but we may on the perf interval be getting close to that part of it.

On the other side of it, as we've been putting more energy in the ground, more sand and more water, we're continuing to get better and better rates, and I think the whole industry's doing that. So, there's a whole list of things we're doing to continue to improve. And as long as we've got a long list to work on, I think we'll continue to improve.

Operator

Our next question comes from Brian Singer – Goldman Sachs.

Brian Singer - Goldman Sachs

How are you thinking about the trajectory of production once the curtailments in the pipelines end? Are you continuing to drill and not complete and immediately shut in and, therefore, be ready to be back to wherever you would have otherwise been in the late fourth quarter, or do you see a more sustainable step down in production in the next few months?

Steven L. Mueller

That sounds like a simple question, I don't know if I've got a simple answer. They key is how long are they going to be down and how long is the spacing for being down. Are they going to be down in one, two day chunks over a long period of time or are they going to be down significantly for 30 days or 60 days and they you can put it back up. And we don't know the answers to that.

So we've tried and Harold mentioned flexibility early when he talked about his portion. We tried to do this as flexible as possible. Today we've got about 55 wells that are in some stage of completion or some kind of activity heading towards completion, that they've TDed the wells.

That's not much more than a normal – normally we'd have between 30 and 40 wells, so we're not backed up that much today. Over time if it takes five months, we will have wells that we'll have drilled and not be able to put on production and we'll have to manage that. We will certainly frac some of them and have them ready to go on and then some of them we may not frac.

The other thing we're doing, we own 11 rigs. Over the next – really start somewhere around September 1, we're going to take each one of those rigs down. We have done maintenance on them or major maintenance on them in over two years. And we'll take each one down for a week to a week and a half and that'll slow the drilling by about, I think about between five and eight wells this year. And that's why if you notice our revision for total number of wells is down a little bit, that's doing maintenance while Boardwalk is doing their thing as well.

So we're being as flexible as possible. If it takes five months, we're going to have a lot of wells backed up and we may have to make some other revisions on whether we're drilling or not. If it only takes 60 days, we'll drill through it.

Brian Singer - Goldman Sachs

When you layer that in but really more when you think about where gas prices are, your hedges, the strong well results you're seeing, any early look on how you're thinking about 2010 from growth and spending perspective?

Steven L Mueller

We really haven't looked that far out, we're just trying to get through the Boardwalk thing right now.

Brian Singer - Goldman Sachs

Lastly any thoughts on decline rates from the couple wells that you're seeing in St. Augustine and the Haynesville, you mentioned where they are producing now. Are you seeing any hook in the decline curve where you think that we'll be at a lower decline rate relative to the rates you mentioned earlier?

Steven L. Mueller

We haven't seen anything, no. I kind of gave you two data points I gave you what the initial rate was and then what it was at various points in time. On that second well with that 7.8 million a day, that's after about 60 days worth of drilling, and if you put that on a tight curve, you're going to see that's well over 6 Bcf.

Now you've only got 60 days, so who knows if it's going to falloff or what it's going to do in the future. That first well, we're just over 170 days with that 1.8 million a day that I have there. You put that on a tight curve and you're in a 3 Bcf type range. Neither of them has seen any kind of drop, they've been smooth through their production.

Operator

Our next question comes from David Heikkinen – Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt

Just a follow up to Mike's line of questioning, thinking about the down spacing as you move forward then Steve, as you've tested you would expect a similar spacing to be applied across your acreage position?

Steven L. Mueller

Well, I don't know the answer to that yet. Like I say, we're seeing good wells across all of our acreage but I don't have enough data to be able to tell you if one part of the acreage is going to be down spaced to one and another part's going to be down spaced at the other. We're still several months away from having that answer.

David Heikkinen - Tudor, Pickering, Holt

So really don't expect the better area or worse area, just too soon to call on down spacing.

Steven L. Mueller

It's way too soon to call.

David Heikkinen - Tudor, Pickering, Holt

And then as you think about Boardwalk versus other lines and you tapped into CenterPoint and Ozark, how should we think about cost for transportation as we go into third and fourth quarter, if this lasts a little longer and then your basis for realized prices.

Steven L. Mueller

Greg had mentioned in his that we have put on significant basis hedges that are roughly $0.35 in the third, fourth and we've actually had some on first quarter of next year. And those are to the various hubs that we think we can get gas to.

David Heikkinen - Tudor, Pickering, Holt

Okay, so no change then?

Steven L. Mueller

I don't think there's going to be any significant change. If anything, there may be of a gas we're able to sell is actually going to be a little bit lower than this past quarter because we don't but those basis hedges in.

Operator

Our next question comes from Mike Scialla – Thomas Weisel Partners.

Michael Scialla - Thomas Weisel Partner

Follow on to Bob's question on just how far you can take the improvements on the productivity side. You mentioned putting more energy into the ground is lengthening the lateral even further from here feasible? I mean, is it possible to drive it across two sections at this depth or is that technically not achievable?

Steven L. Mueller

It's technically achievable. We have done and the industry has done cross-section wells already. We've done several wells over 5,000. We've got a handful of wells over 6,000 and for a geologic reason we actually have drilled a well about 7,300 feet lateral. So it's certainly technically feasible.

As you start looking at just the way the wells will kind of space out over time, no matter what the spacing is going to be, it's much harder to say with a 10,000 foot average lateral cover all what I call white space, make sure that you've got all your production covered and you've got all your reserves out of the ground, then it is with something a little less than that. So I don't think 4,000 is the right number but it's not 10,000 either, it's somewhere in between those.

Michael Scialla - Thomas Weisel Partners

Then looking at your guidance, it looks like you've taken third quarter guidance down more than fourth quarter, even though the maintenance is not set to begin until September. I would have thought it would have been the reverse. Can you help me understand what I'm missing there?

Steven L. Mueller

Our assumption is that they get out there in early September and work continually for 30 days basically in the third quarter. And then as you get into the fourth quarter, if it goes to a scenario where it's the five month scenario, they will go off. There will be issue where they're going to have to go away and if production may come back for a while and then they'll come back and work on it some more. So in the fourth quarter we've got more sporadic production or time that they're working than in the third quarter. But it's roughly the same number of days each quarter.

Operator

Our next question comes from Jeff Hayden – Rodman & Renshaw.

Jeff Hayden - Rodman & Renshaw

Just kind of want to start with the Haynesville, it looks like you guys talked about 32,800 net acres right now. I believe when you did the call last quarter, you said 50,000 so I'm assuming you let some stuff go. Could you give any color on whereabouts you let the acreage go and maybe what were the reasons for that, what did you see, etc?

Steven L. Mueller

We have dropped some acreage. It was to the far west part of our overall acreage position and it really is not in the Haynesville as we see it today, and it's much deeper. If you kind of break the acreage we have today into two sets, I said there's three major parts of it. The eastern two are roughly 12,500 foot deep. The western one is roughly 14,000 foot to get to Haynesville, and the acreage we dropped was significantly deeper than that, we just weren't going to get to it any time soon.

Jeff Hayden - Rodman & Renshaw

Jumping back over to the Fayetteville, I believe last quarter you guys had talked about possibly taking the rig count down to about 15 or kind of 11 horizontal rigs running. Any updates on that still expecting to lay off another couple of rigs or are you thinking about staying at the 13 level?

Steven L. Mueller

As it stands today, we're still on the schedule that later this year drop two more rigs get down to 11 big rigs running.

Operator

Our next question comes from Nicholas Pope – Dahlman Rose.

Nicholas Pope – Dahlman Rose & Co.

I know it's a little early to tell anything on production response when you look at some of the down spacing tests you'll have seen, but I mean have you'll seen anything with like pressure response or kind of frac hit data on what that down spacing potential looks like right now?

Steven L. Mueller

We don't have enough data to start putting trends together we've got a lot of anomalies. And actually, if you look at the press release and look at the production curve for the 4,000 foot laterals, you'll see at the very end of that 4,000 foot lateral, there's a single well and it jumps up above the line. That was actually a well that we drilled a down space well near and it took a frac hit and actually helped it.

Now, let me tell you right off the bat that there's only a handful of wells that, when they took frac hits, it helped them. Most of them either come on the same or come on a little less than they were before. But there certainly are wells out that have frac hits and what we have now is a bunch of data that we're sorting through and so we're just working our way through that.

Nicholas Pope – Dahlman Rose & Co.

And also just back to the pipeline, is there any recourse on that pipeline to recapture any money from what's being lost from the pipeline being down or is this like force majeure kind of activity?

Steven L. Mueller

Well, I'm sure if you talk to the pipeline company, they would say force majeure. It never really got up to full operational, so they would say they are still in the construction phase. And as long as it really takes a reasonable amount of time to get it fixed and we're back in business and on our curve, there's really no recourse that we'd want to do. If for some reason they can't fix the pipe and it stays at a low rate, then we'll just have to talk to them about what happens then.

Operator

Our next question comes from Tom Gardner – Simmons & Company.

Tom Gardner – Simmons & Company International

Following up on your prepared comments on the Fayetteville production impact due to pipeline downtime, can you mitigate some of the impact from rerouting the gas or has that been fully considered in your guidance?

Steven L. Mueller

Any kind of backhaul, any kind of reroute that we could find or know about is considered in our guidance, including the fact that we're going to accelerate a project that really was planned for the end of next year when we had higher production rates, we call it East End Line.

We're actually going to lay a line that has about 200 million a day capacity, have it operational in late September and we don't have 200 million to put in the line, we're got about 100 million to date to put in that line, but we'll bypass Boardwalk and go straight to NGPL and we'll get us a little more takeaway. And that goes back to an earlier question why the production looks a little bit more in the fourth quarter. We are doing some things, rerouting and drilling in a little bit different areas to take advantage of every bit of pipeline we can take advantage of.

Tom Gardner – Simmons & Company International

It's a nice lead-in to a follow-up question, just given these transportation issues, can you walk us through the timing of future pipeline expansions and possible pinch points and how should we think about 2010 growth?

Steven L. Mueller

Well, I think we're all right once we get through the Boardwalk repairs. If you remember, we talked about Phase 1 and Phase 2 in the prepared remarks. There's a Phase 3 of the Boardwalk Pipeline that has added compression and it's supposed to be in April of next year. They're on schedule to do that and that's just literally just delivering compressors out there and hooking them in. So I think that's in good shape.

And then our other commitment is Fayetteville Express and, while they're in early stages of that, we don't know of any reason why that would get delayed significantly. And with that third stage compression and Fayetteville Express, we think we're fine going forward.

Operator

Our next question comes from Jason Gammel – Macquarie Capital.

Jason Gammel – Macquarie Capital

In the press release, it said that gross production in the Fayetteville had reached a milestone of 1B a day in July and it says further in the press release that the transportation capacity per gross operated production was 1.05 Bs per day. Does that mean that you essentially would have been up against some transportation constraints had it not been for the curtailments?

Steven L. Mueller

No, and let me explain a little bit about the pipeline. In April, the pipeline was brought up on basically 72% of its rating. Late in April they ran their first inspection. When they ran that inspection, they de-rated the line across the entire line even though it had not been all inspected yet, to about 58% of its pressure. Once we get all this work done, we'll go back up to 72% and we'll be off and running from there. So it's really just all the work's going on with the pipeline that affect today, but we've got the capacity, once they get the repair work done.

Jason Gammel – Macquarie Capital

You guys had mentioned returning to a more normal price environment over the coming weeks and months. Could you just give us your outlook on the macro environment, what you see just in terms of production in the U.S. because of all the rig weight downs that sort of thing?

Steven L. Mueller

We're all pointing at each other, when you ask that question. This is one of those strange times where because of the Boardwalk pipeline issues, you kind of hope the gas is a little bit lower here for the next couple of months because you can't take advantage of it as much.

But I think, in general, our general philosophy is that there are some forces in play, especially with the overall production and the low rig count, that should we have a gas price increase in the future, we also think it's going to be very volatile. We think it's going to go up and it can come down as fast as it goes up and we think that'll happen certainly for the next year or so.

And so we're just watching it and as we can take some more hedges, we'll take some more hedges and we'll make decisions as it plays out. Again, the key to what we're doing is flexibility. If prices look like they're going to go up in 2010 later this year, we won't drop those couple rigs I mentioned in the Fayetteville. If they're staying the way it is today, looks like it's going to stay that way for a while, we'll make decisions then and go from there.

Operator

Our next question comes from [Cedula Mercy] – CDP US

[Cedula Mercy] – CDP US

If we look forward to 2010, can you talk a little bit about whether you'll be matching up the capital program to projected cash flows or would you, given your strong balance sheet at this point, would you be willing to take on a little bit more leverage at this point? Can you try and talk a little bit about how you're thinking about that?

Greg D. Kerley

We're in the early stages of even starting to look at 2010 and build our program, so we're several months away from knowing what that is going to look like exactly. And obviously our price environment will have a big inter-play with that.

We planned our 2009 and 2010 overall program as we entered this year to where we could withstand a low price environment during that entire two year period, and in that scenario we'd be modest borrowers this year and potentially next year, but still have at least half of our $1 billion credit facility still available to use as capacity.

So we're not uncomfortable in that situation if that's the price environment, but on the other side of that, it doesn't take a very – a $6 to $7 gas price environment, we'd be cash flow positive here in 2009, or at least cash flow neutral.

Operator

Our next question comes from Scott Hanold – RBC Capital Markets.

Scott Hanold – RBC Capital Markets

Steve, you talked a little bit about the down spacing test that you saw a few frac hits and I know you don't give too much color until you guys have a full opportunity to get a better handle on the data. But could you kind of give us some sense how tight some of that spacing is getting and maybe relative to what has happened say in other place in the Barnett where there's been a lot tighter down spacing. I mean frac hits are pretty typical in some of the tighter spacing wells and really give us a sense of what that means?

Steven L. Mueller

We are right now in the process of drilling about 400 wells at various down space levels. Most of those are being drilled at around 56 acre spacing. If you remember our pilot work we did was around 110 acres and we're just kind of splitting that spacing. And then we have a smaller number of wells that we're splitting again going down to 28 acre spacing.

And, as you say, the closer you get the more likelihood that you have frac hits and there's all kinds of things you can do with simulfracs and things that they've done in Barnett that's actually enhanced production in certain parts of their field. We're in the early stages of learning that so.

Like I say, frac hits are normal, we're trying to figure out as we get into a little tighter spacing is that helping or not helping and then how that works in overall plans as we go forward in the future. I just don't have enough information. It's coming in but we haven't been able to sort it all out yet.

Scott Hanold - RBC Capital Markets

In some of those wells that are in sort of that 56 acre spacing, have you seen any frac hits there, or has it been much less in those wells?

Steven L. Mueller

I don't know the exact percentage, but there's a fair number. It's not 50% but there's a fair number that you're getting frac hits at 60 acres. And frankly, every once in a while at 110-acres you get a frac hit, it's not normal but it happens.

Scott Hanold - RBC Capital Markets

Then looking also at 2010, and I'm not going to push you for it for guidance there, but I think you were all looking at getting some specialized rigs for the Fayetteville to kind of move from once in development stages. Can you kind of give us an update on what you're thinking in terms of adding some specialized rigs for the play and when that could happen?

Steven L. Mueller

We've certainly looked at designs and from what we've learned in drilling wells what we'd do different on rigs. But as you say we really haven't gotten thinking enough about 2010 or 2011 to figure out when we might do that.

Operator

Our next question comes from Joe Allman – JP Morgan.

Joe Allman – JP Morgan Securities, Inc.

Steve, in terms of the Marcellus shale, can you give us an update on what's going on there and when you might start talking some more details in the Marcellus?

Steven L. Mueller

Really there's not much update. We have picked up a little bit of acreage since the first quarter but it's not significant, and the acreage we've picked up has been kind of blocking in what we'll start drilling next year. We're continuing to look at some other bigger acreage blocks but haven't done anything yet on that.

What we're doing on our acreage in Marcellus today is permeating wells, getting the water rights in line and looking at pipeline right of ways those kinds of things for a drilling program in 2010. And we'll continue doing that the next couple of quarters and at the same time kind of opportunistically take down some acreages we can do it.

Joe Allman – JP Morgan Securities, Inc.

Second question, on the Fayetteville shale cost, the cost went down about $100,000 from the previous release. What's driving that and do you think that you can drive the cost lower? And what might be a target for the company for the average Fayetteville shale well cost?

Steven L. Mueller

There's a couple of big pieces that are driving that. Steel cost has gone down significantly so part of it's steel cost. Part of it is, on the completion side, the pumping services have continued going down from first quarter to second quarter, and then just taking that day out of the drilling time has done it as well. With what we're estimating today, we think we're going to exit the year at another $100,000 down roughly on our cost.

Operator

Our next question comes from Dan McSpirit – BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Can you discuss the choke size applied on the first to Haynesville shale wells and what you might apply going forward here to manage the decline rate going forward?

Steven L. Mueller

On the first well, I think I mentioned on the last conference call that we soon after testing that first well we put on a 1364 so as far as I know it's still on 1364 choke. So we haven't done anything to that one. And so it's a little lower than you might have in some of the other areas, but frankly that just has to do with takeaway capacity.

On the second well, I don't know exactly what the choke is it's about 3,900 lbs today at that 7.8 million a day so it's got a lot of pressure there, and I know it's got 20 on it but I don't if it's a 24 or 28 whatever the choke is.

Dan McSpirit – BMO Capital Markets

What's the plan going forward here, anything different than what was applied on the second well?

Steven L. Mueller

Not that I know of. As you look at the other wells we're going to drill they're all going to be roughly the same laterals those same kinds of frac stages, and I don't think we're planning to do anything to these wells. The key is keep them as constant as you can on choke size so you can really see what they're going to do.

Operator

Our next question is a follow-up from Robert Christensen – Buckingham Research.

Robert Christensen – Buckingham Research

Could you just tell us how in the field you would flex down your Fayetteville shale production for sort of the daily, weekly – I mean do you shut in wells? Do you choke them back? Do you run the compressors less? Just give us a sense of how physically you would flex them.

Steven L. Mueller

And you're talking about when Boardwalk does its work?

Robert Christensen – Buckingham Research

Yes.

Steven L. Mueller

There's a lot of ways we do it. When they completely shut in all of their system we're taking down a lot of wells. And we've got a list of wells that are easiest to take down and there's also part of that list where you can get into other markets, where you can't get into other markets. When they just take it down for a day or two, a lot of that we can do with just taking compressor stations down and letting the line pack a little bit. And so we do a combination of things depending on how long it's going to be down, how much it's going to be down.

Robert Christensen – Buckingham Research

The next question, Fayetteville wells when they have been shut in let's say for an extended period, how have they come back to life? Do you have any kind of –?

Steven L. Mueller

We really haven't seen any issues with them. Just like all wells, they have a little bit of a storage effect so they'll pop up a little bit when they first come on. But except for that we're not seeing any kind of damage like you might have in some other areas of the country.

Operator

Our next question is a follow-up from Michael Scialla – Thomas Weisel.

Michael Scialla – Thomas Weisel Partners

I just had one more on the pipeline, could you tell us what the nature of these anomalies are that Boardwalk talked about. And then do you think its potential for a widespread problem in the industry or do you think just isolated to Boardwalk?

Steven L. Mueller

I'll start with a widespread problem. We don't have any idea whether it's a widespread problem. What is basically happened is that they run an inspection device down the well bore, or down the pipeline and that inspection device historically hasn't been as accurate as the newest thing that's been run. And it's less than a year old it can tell anomalies in the pipe of less than a quarter inch. And when I say anomalies, say the pipe is slightly deformed at a quarter inch, it can pick that deformation up.

The older tools couldn't pick up anything near that kind of resolution so what's happening with the newer tool, you run it in these newer pipes and you're seeing a lot more anomalies than historically have been seen, and both the government and the pipelines don't know what to do with that.

So part of what's been going on with the Boardwalk pipeline in particular is that, as they run the inspection tool, they've already gone back and part of this last quarter was them going back in and taking chunks of that pipe out, taking it to the lab and they're doing tests on it right now to know if a quarter inch is significant or not or three-eighths is significant or a half inch is significant.

And once they figure that out and go back to FMSA, the government agency that's in charge of this, FMSA will then say here's the anomalies you need to take out and the others are okay. And that's why you 're hearing one to five months, that's why you're seeing the large spread in our estimate for how much we're going to be down, because no one knows yet in any kind of clarity how much of the pipe is affected and how many of these things they're going to cut out.

Operator

Our next question is a follow-up question from Joe Allman – JP Morgan.

Joe Allman – JP Morgan Securities, Inc.

Just separate from this Boardwalk pipeline issue, were you bumping up against any kind of high line pressures or issues related to the high level storage?

Steven L. Mueller

No, not really. As a matter of fact, in the second quarter the basis in general for the markets we go into closed up, and the reason for that was that that south crossing those other lines south of us coming out of [McKondin] and Barnett took some back pressure off some of those [McKondin] markets, so it actually has improved a little bit. Now whether it will stay that way I don't know, but we really haven't seen anything.

Operator

Ladies and gentlemen we have reached the end of our allotted time for questions. I would like to turn the floor back over to Mr. Mueller for closing comments.

Steven L. Mueller

Well, I want to thank everyone for being on the call. As we've talked about, the Boardwalk's going to be a little challenging here for the next couple of months, but we've got a really bright future ahead of us both with what we're doing with Fayetteville shale and we think we've got some exciting projects in James Lime, Marcellus and Haynesville's got our interest peaked. So we think there's some bright things going for us as we go into the future. Again, thank you and if you've got any questions give Brad or Greg a call and we can fill in some more questions.

Operator

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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