西南能源 (SWN) 2009 Q2 法說會逐字稿

Greetings and welcome to the Southwestern Energy Company second quarter earnings conference call. At this time all participants are in a listen-only mode. A brief question-and-answer session will following the formal presentation. (Operator Instructions). As a reminder this conference is being recorded.

It is now my pleasure to introduce your host, Harold Korell, Executive Chairman of the Board, for Southwestern Energy Company. Thank you, Mr. Korell, you may begin.

Good morning and thank you for joining us. 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 affecting outcomes many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statements section of our annual and quarterly filings with the Securities & 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, we're here to report another very good quarter despite the low commodity price environment. Our gross operated production from the Fayetteville Shale received a significant milestone of 1 Bcf per day in July compared to approximately 500 million cubic feet per day at this time a year ago. To me it's 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 a 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're 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 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.

Thank you, Harold. Good morning. During the second quarter of 2009 we produced 74.3 Bcfe up 65% from the second quarter of 2008. Our Fayetteville Shale production was 60.6 Bcf double the 29.6 we produced in the 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 and production activities and participated in drilling 338 wells. Of this amount approximately 694-- $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 invested approximately $793 million in our Fayetteville Shale play including both our E&P and Midstream activities. At June 30th our gross operated production was approximately 990 million cubic feet per day, up from 850 million cubic foot at the end of the-- at the end of 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 from the Arkoma Basin was moved to markets in the Midwest. This included the Fayetteville Lateral Phase I portion of the Texas gas transmission or Boardwalk Pipeline, which was placed in service on December 24th. On April 1st the Fayetteville Lateral Phase II and Greenfield 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 shut down 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 operated 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 to 825 million cubic foot per day gross and then this morning the production is now restored to over 1 Bcf a day.

Currently our transport capacity is sufficient for us to produce our operated wells at approximately 1 Bcf a day. Our net share of this plus our outside operated production is approximately 715 million cubic feet a day. Once repairs are started on the Fayetteville Lateral Phase I facilities on the Boardwalk Pipeline, transport out of the producing areas will be limited to the existing Ozark and Centerpoint systems. We'll estimate that our total operated 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 I facilities being out of service for 45 to 60 days starting 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 2008 levels. Since 2007 the continuous improvements of our completion practices has resulted in quarter-over-quarter improvements in average initial production rates. The average initial production rate for wells put on production in the second quarter of 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 in the fourth quarter of 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 link to 4,123 feet and average time to drill to total depth of 11 days from reentry-to-reentry. This compares to an average completed well cost of $3.1 million per well, average horizontal lateral link to 3874 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 on to our Haynesville Shale activity where we see encouraging results. The first horizontal well in our 50/50 joint venture targeting the Haynesville/Bossier Shale in Shelby and San Augustine Counties Texas the Red River 877 #1 reached total depth in the fourth quarter of 2008. This well, which had a completed horizon lateral of 2,718 feet, was production tested at a rate of 7.2 million cubic foot per day in the first quarter of 2009 and is currently producing approximately 1.8 million cubit 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 3,800-foot horizontal lateral. It was production tested at 13.4 million cubic foot per day in the second quarter and is currently producing approximately 7.8 million cubic foot per day.

We have completed drilling the third well, the Red River 16-- 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 #1-H 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 participated in drilling 13 wells in the conventional Arkoma Basin and 23 wells in East Texas during the first six months of 2009. Twenty one of the East Texas wells or 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 business are expected to have continued strong results in the remainder of 2009 and beyond. We continue our focus on adding value. Significant value is 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 opportunity in the Haynesville, James Lime and Marcellus Shales. I will now turn it over to Greg Kerley who will discuss our financial results.

Thank you, Steve, and good morning. 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 lower realized 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 or 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 to NYMEX gas price of approximately says $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 volume. 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 presser 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 noncash 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 30th 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 30th, 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.

(Operator Instructions) Our first question, gentlemen, is from the line of Michael Jacobs with Tudor, Pickering, Holt. Please go ahead with your question, sir.

Thank you and good morning.

Good morning.

Good morning.

Trying to reconcile average economics on the Fayetteville in 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?

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

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

And you're talking about the Haynesville?

Yes.

The first two wells have 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 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're taking a lot out in the first three wells.

Great. Thank you.

Our next question is coming from the line of Robert Christensen with Buckingham Research Group. Please state your question, sir.

Yes, thanks, guys. First question again is a Haynesville question. How are you selecting your position-- positioning of these wildcat attempts? What goes into that decision making?

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 picked 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 in (inaudible).

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

The Haynesville on our acreage, we've got enough control right now that we can comfortably say the Haynesville across our acreage is between 130 and 160-foot thick. We are the first two wells, as I said we're about five miles apart. They're in what we call our Jevelle 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 the wells in 2008 or 2009 will be in that block. And then as we look for 2010 you'll start to see us test on those other blocks.

My second question relates to, and 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?

Yeah. We've got a long list of things we're still trying, and we've talked in the past about how many stages we fracked and we've talked about how our perf interval has gotten lower. I will tell you that from a perf interval standpoint, we did our first 75-foot perf interval of late last year, we did some 50-foot, and preliminary information we're not seeing much difference between those. That's very preliminary, and we still got 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 so, and I think the whole industry is doing that. So there-- like I said, 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.

Thank you.

Our next question is coming from the line of Brian Singer with Goldman Sachs. Please go ahead with your question, sir.

Thank you. Good morning.

Good morning, Brian.

How are you thinking about the trajectory of production once the curtailments when the pipelines end? Are you continuing to drill and not complete or just immediately shut it or 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?

That sounds like a simple question. I don't know if I've got a simple answer. The 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 then you can put it back up? And we don't know the answers to that. So we've tried and Harold mentioned flexibility earlier 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 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'll 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 starting somewhere around September 1st, we're going to take each one of those rigs down. We have not 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.

That's really helpful. And 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 a growth and a spending perspective?

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

Great. And lastly, any thoughts on decline rates from the couple wells that you're seeing in San Augustine and the Haynesville? You mentioned where they are producing now. Are you seeing any hook in the decline curve where you think that there will be a lower decline rate after-- relative to the rates you mentioned earlier?

We haven't seen anything, no. And if you-- I kind of gave you two data points. I gave you what the initial rate was and then what it was at the 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, and now you've only got 60 days, so who knows if it's going to fall off what it's going to do in the future. That first well, we're at 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 the 3 Bcf type range. Neither of them has seen any kind of drop, they've been smooth through their productions.

Great. Thank you.

Our next question is from the line of David Heikkinen with Tudor, Pickering, Holt. Please state your question, sir.

Just 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?

Boy 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 parts going to be down spaced with the other. It's-- we're still several months away from having that answer.

Okay. So really don't expect the better area or work area just too soon to call on down spacing?

Yes, it's way too soon to call.

As you think about Boardwalk versus other lines, and you've tapped into Centerpoint and Ozark, how should we think about cost per transportation as we go into third and fourth quarter, is this lasted a little longer and then your basis per realized prices?

Well, 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.

Okay. So no change then?

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

Okay, good.

So--

Thank you.

Thank you. Our next question is from the line of Mike Scialla with Thomas Weisel Partners. Please state your question.

Hi, good morning, guys. Follow on to Bob's question on just how far you can take the improvements on the productivity side, you mentioned put in 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?

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 drilled a well about 7,300 feet lateral, so it's certainly technically feasible. As you start looking at just the way the wells are kind of spaced 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 got've all of your production covered and you got all of your reserves out of the ground than 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.

Okay and 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?

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 they've -- if it goes to a scenario where it's the five-month scenario, they will go off. There'll be issues where they're going to have to go away and your 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.

Thanks, Steve.

Thank you. Our next question is coming from the line of Jeff Hayden of Rodman & Renshaw. Please go ahead with your question, sir.

Hey guys, just kind of wanted to start with the Haynesville. 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 what part, whereabouts you let the acreage go and maybe what were the reasons for that, what did you see, et cetera?

We have dropped some acreage. It was to the far west part of our overall acreage position, and really is not in the Haynesville as we see it today, and it's much deeper. If you kind of break our acreage into the acres we have today in the 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.

Okay, appreciate that color. And then jumping back over to the Fayetteville, I believe last quarter you guys have talked about possibly taking the recount down to about 15 or kind of 11 horizontal rigs running. Any updates on that, still expecting to layoff another couple of rigs or are you thinking about staying in kind of the 13 level?

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.

All right. I appreciate it, guys.

Thank you. Our next question is coming from the line of Nicholas Pope with Dahlman Rose. Please state your question.

Good morning, guys.

Good morning.

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

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 that on 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 took frac hits that 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 there 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.

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

Well I'm sure if you talked to the pipeline company they would say force majuere. We've 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 the reasonable amount of time to get it fixed and we're back in business and on a curve, there's really no recourse that we 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.

All right. I appreciate it. Thanks.

Our next question is from the line of Tom Gardner with Simmons & Company. Please state your question.

Thank you, operator and good morning, everyone. Just following up on your prepared comments on the Fayetteville production impact due to pipeline down time, can you mitigate some of the impact through rerouting the gas or has that been fully considered in your guidance?

Everything that we could -- any kind of backhaul, and kind of reroute that we can 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 a line. We've got about 100 million today to put in that line, but we'll bypass Boardwalk and go straight to NGPO, and will get us a little more take away. 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.

That makes sense. And 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?

Well I think we're all right once we get through the Boardwalk repairs. If you remember we talked about Phase I, Phase II, in the prepared remarks. There's a Phase III of the Boardwalk Pipeline that has added compression and it's supposed to be in 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 at Fayetteville Express, we think we're fine going forward.

Thanks, Steve.

Thank you. (Operator Instructions). Our next question is from the line of Jason Gammel with Macquarie Capital. Please state your question, sir.

Thank you, guys. I just want to follow up on the question that was just asked. In the press release it said that gross production in the Fayetteville had reached a milestone of 1 B a day in July and it says further in the press release that the transportation capacity per gross operated production was 1.05 B's per day. Does that mean that you essentially would have been up against transportation constraints had it not been for the curtailments?

No and let me explain a little 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 derated 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 of this work done we'll go back up to 72%, and we'll be off and running from there. So there-- it's really just all the work that's going on with the pipeline that's the effect today, but we've got the capacity once they get the repair work done.

Okay, great that's very helpful. And then just a broader question, 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 weigh downs, that sort of thing?

Well 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 that 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's some forces in play, especially with the overall production and the low rig count, that should have 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. And 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 of rigs I mentioned in the Fayetteville. If they're staying the way it is today, looks like they're going to stay that way for a while, we'll make decisions then and go from there.

Okay. Thank you. Appreciate the comments.

Our next question is from the line of [Vadula Murhey] with CDP US. Please state your question.

Good morning.

Good morning.

I'm wondering kind of following up a little bit on Jason's questions sort of, 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 kind of talk a little bit about how you're thinking about that?

Well this is Greg 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 interplay with that. We planned our 2009 and 2010 overall program as we entered this year to where that 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 us as a 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.

Okay. Thank you very much.

Our next question is from the line of Scott Hanold with RBC Capital Markets. Please state your question, sir.

Thanks, good morning.

Good morning.

Steve, you talked about the down spacing test that you saw a few frac hits, and I know you don't want to give too much color until you guys have a full opportunity to get a better handle on the data, but can you kind of give us some sense that what-- how tight some of that spacing is getting? And maybe relative to what has happened say in other places 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?

Well, 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 a 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 that you get, the more likelihood that you have a frac hit, and there is all kinds of things you can do with simul fracs and things that they've done in the Barnett that's actually enhanced production in certain parts of their field. We're in the early stages of learning that, so as a frac hits are normal, we're trying to figure out as we get to those tighter spacing, is that helping, not helping, and how that works in overall plans as we go forward in the future. And again I just don't have enough information. It's coming in, but we haven't been able to sort it all out yet.

Okay and some of those wells that are in sort of that 50, 60-acre spacing, I mean have you seen any frac hits there or has it been much less in those wells?

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

Okay. All right. And then looking also at 2010, and I am not going to push you for guidance there, but I know you're-- I think you were all looking at getting some specialized rigs for the Fayetteville to kind of move from-- ones 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?

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

All right. Appreciate it. Thanks.

(Operator Instructions). Our next question is from the line of Joe Allman with JPMorgan. Please state your question, sir.

Yes, thank you. Good morning, everybody.

Hi, Joe.

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

There is not much update. We have picked up a little bit of acreage since the first quarter, but it is not significant. And the acres we've picked up has been kind of blocking in where 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 permitting wells, getting the water right, in line, and looking at pipeline right of ways, those kinds of things for drilling program in 2010. And we'll continue to do that the next couple of quarters, and at the same time kind of opportunistically take down some acreage as we can do it.

Okay, that's helpful. And then second question, on the Fayetteville Shale cost, the cost went down by about $100,000 from the previous release.

Right.

What's driving that and do you think that you could drive the costs lower and what might be a target for the Company for the average Fayetteville Shale well cost?

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 another $100,000 down roughly in our costs.

Okay. All right, very helpful. Thank you.

Our next question is coming from the line of Dan McSpirit with BMO Capital Markets. Please state your question, sir.

Gentlemen, good morning.

Good morning.

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

On the first well, I think I mentioned 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 1364s 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 take away capacity. On the second well I don't know exactly what the choke is. It's about 3900 pounds today, that's 7.8 million a day so it still has got a lot of pressure there. And I know it's, it's got 20 on it, but I don't know if it's a 24, 28, whatever the choke is.

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

Not that I know of.

Okay.

As you look at the other wells we're going to drill, they'll all going to be roughly the same laterals, with same kind 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.

Very good. Thank you.

Our next question is a follow-up from the line of Robert Christensen with Buckingham Research. Please state your question, sir.

Yes. Could you just tell us how in the field you would flex down your Fayetteville Shale production for the sort of 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?

And you're talking about when Boardwalk --

Yes.

Does it's work?

Yes.

There's a lot of ways we could 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 easier to take down, and there's also part of that list, where you can get into other markets where you can't get into 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 frac 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.

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

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.

Thank you, Steve.

Our next question is from the line of, a follow up from the line of Mike Scialla with Thomas Weisel. Please state your question, sir.

I just had one more on the pipeline. Could you tell us what the nature of these anomalies are that Boardwalk's talked about and then do you think it's potential for a widespread problem in the industry or is this do you think just isolated to Boardwalk?

I'll start with widespread problem. We don't have any idea whether it's a widespread problem. What has basically happened is that they run an inspection device down the well bore, or down the pipeline, and the-- that inspection device historically hasn't been as accurate as is very-- the newest thing that's been run, and it is 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 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 pipelines don't know exactly what to do with that.

So part of what's been going on with the Boardwalk pipeline, in particular, is as they've 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-eights is significant or half-inch is significant. And once they figure that out and go back to [FEMSA], the government agency that is in charge of this, [FEMSA] will then say here is the anomalies you need to take out, and these other ones 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 have to cut out.

That helps. Thanks.

Our next question is a follow-up question from the line of Joe Allman with JPMorgan. Please state your question, sir.

Yes thanks again. 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 of storage?

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, come in out of Mid-Continent and Barnett, took some back pressure off some of those Mid-Continent markets, so it actually has improved a little bit. Now whether it'll stay that way, I don't know, but we really haven't seen anything.

Okay. Very helpful. Thanks, Steve.

Thank you. 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.

Well I want to thank everyone for being on the call. As you can-- as we've talked about, the Boardwalk is 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 in the 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 is bright things going for us going in the future. So again thank you, and if you've got any questions, give Brad or Greg a call and we can fill in some more questions.

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