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Executives

Harold Korell – Executive Chairman

Steve Mueller - CEO

Greg Kerley - CFO

Analysts

David Kistler - Simmons & Company

Scott Hanold - RBC Capital Markets

Jeff Hayden - Rodman and Renshaw

Brian Singer - Goldman Sachs

Mike Scialla - Thomas Weisel Partners

Ben Dell - Bernstein Research

Jason Gammel - Macquarie Capital

Monroe Helm - CM Energy Partners

Joe Allman - JPMorgan

Stuart Wineman - Catapult Partners

Southwestern Energy Co. (SWN) Q3 2009 Earnings Call October 30, 2009 10:00 AM ET

Operator

Greetings and welcome to the Southwestern Energy Company Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions. Afterwards you may feel free to re-queue for additional questions. (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, sir, you may begin.

Harold Korell

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

Also I would like to point out that many of the comments during our 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 SEC. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

We had a solid quarter despite depressed natural gas prices, which were at a seven year low and the various curtailment issues we experienced related to the maintenance and repairs of the Boardwalk Pipeline. We do not expect these factors to weigh us heavily in the fourth quarter of '09 as the Boardwalk Pipeline was placed online sooner than we had expected and as gas prices appear to be moving higher than they had been over the past nine months.

As a result of the Boardwalk Pipeline being back online, we were able to reach another milestone last week, when we surpassed one Bcf of net production per day as a company. Meantime in other areas things continue to heat up in Pennsylvania as joint ventures are being formed, companies drill and report higher rate wells, and pay high prices in and around our acreage position. Our plan is to begin an active drilling program there in 2010.

In addition, as we detailed in our earnings release, good things are happening on our acreage in East Texas both in the James Lime and the Haynesville. As we look ahead, we see continued profitable growth in our production reserves, which coupled with our low cost structure will [create] tremendous value for Southwestern Energy and its shareholders.

I will now turn the teleconference over to Steve for more details 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 afterwards.

Steve Mueller

During the third quarter of 2009, we produced 73.2 Bcfe, up 38% from third quarter of 2008. Our Fayetteville Shale production was 58.8 Bcf, 60% greater than the 37.2, we produced in the third quarter of 2008. Our remaining third quarter production came from East Texas, where we produced nine Bcf and 5.3 Bcf from our conventional Arkoma properties.

As discussed last quarter, repairs and maintenance on the Texas Gas Transmission pipeline often referred to as Boardwalk Pipeline, laterals for the Fayetteville and Greenville areas, servicing our shale caused us to experience curtailments that impacted our ability to transport our production. Beginning on October 8, the Fayetteville lateral was placed back into service after being shutdown since September 1. The Greenville lateral was placed back in service in October after the shutdown.

The completion of these repairs ahead of our anticipated schedule as well as the continued strong performance of our Fayetteville Shale and East Texas wells are the reasons for revising our previous gas and oil production guidance for 2009 from 278 to 288 Bcf to the new range of 297 to 300 Bcfe. At this higher production guidance, we expect to have production growth of approximately 53% over 2008 levels.

In the first nine months of 2009, we invested approximately $1.2 billion in our exploration and production business activities and participated in drilling 476 wells, of this amount approximately $1 billion or 81% was for drilling wells. Additionally, we invested $167 million in our midstream segment, almost entirely in the Fayetteville Shale. Speaking of the Fayetteville Shale, we invested approximately $1 billion in the first nine months of 2009 in this play, including both our E&P and midstream activities.

At October 24, our gross production rate was approximately 1.23 Bcf per day, double the 600 million per day from a year ago. We currently have 17 drilling rigs running in the Fayetteville, 13 in are capable drilling horizontal wells and four smaller rigs that are used to drill the vertical portion of the holes. During the third quarter our horizontal wells had an average completed well cost of $2.9 million per well, average horizontal length of 4,100 feet and average time to drill to total depth of 12 days from out entry to reentry.

Beginning in late 2008, we began drilling wells in Fayetteville Shale to test tighter well spacing. Through September 30, we have placed over 200 wells on production that have well spacing of 700 feet or less representing approximately 65 acre spacing or less. Results today have been encouraging and would point toward the drilling of 10 to 12 wells per section in the Fayetteville Shale. We will fine tune this analysis as well date is added over the next several months.

Additionally, we are testing eight different pilot areas with well spacings that will range from 300 to 600 feet apart. During the third quarter we placed three wells in production with initial production rates over 6 million cubic foot per day, subsequent to the end of the third quarter and through October 23, we’ve placed two additional wells on production with initial rates over 6 million a day and including our highest rate well to date, the Linda Linn 08-12 1-23H located in Faulkner County with initial production rate of 6.7 million cubic foot per day.

I will now move onto our Haynesville Shale activity where we are continuing to 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 number one, reached total depth in the fourth quarter of 2008. This well with a completed lateral link of 2,718 feet was production tested at a rate of 7.2 main cubic foot per day in the first quarter of 2009.

The second horizontal well, the Red River 164 number one 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.

We have completed a third well; the Red River 619 number one located in San Augustine County with a measured depth of 17,244 feet and a lateral of 4,000 feet. This well was production tested in the third quarter at 16.7 million cubic foot per day.

Our fourth well, the Burrows Gas Unit 1-H is currently being tested. A fifth well, the Red River 257 number one is waiting on completion. And finally, we're currently drilling our sixth well, the Red River 257 number two which is targeting the middle Bossier both located in San Augustine County. Our total production from the Haynesville is currently approximately [34.7] million cubic foot per day gross or 10.2 million cubic foot per day net.

Finally, we participated in drilling 14 wells in the conventional Arkoma Basin and 33 wells in East Texas during the fires nine months of 2009. 28 of the East Texas wells were James Lime horizontal wells. Production from Arkoma and East Texas properties was 16.9 and 24.6 Bcfe respectively for the first nine months of 2009, compared to 18.6 and 24.1 Bcfe for the first nine months of 2008.

We currently continue to have two operated rigs running in East Texas and none in conventional Arkoma. In summary, our E&P and midstream businesses had a strong results in 2009 which we expect to continue into 2010. As we prepare our capital budget for next year, we will continue to be focused on adding value in all of our areas, including the Fayetteville, Haynesville, and Marcellus Shale.

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

Greg Kerley

We had a solid quarter despite depressed natural gas prices on the curtailment of a portion of our production due to maintenance and repairs on the Boardwalk Pipeline. We reported net income of $118.3 million or $0.34 a share for the quarter down from $218 million or $0.63 a share a year ago, primarily due to significantly lower natural gas prices.

Our results in 2008 also included an after tax gain on the sale of our utility asset of $35 million or $0.10 a share. Despite the decline in our earnings, our cash flow from operations, before changes in operating assets and liabilities was actually up 6% over the prior year to $331.8 million, as our production growth offset the effect of lower realized natural gas prices.

Our average realized gas price during the third quarter was $5.06 per Mcf, which was approximately $3.50 lower than our average realized price a year ago. Our commodity hedge position increased our average realized gas price by $2.21 in the third quarter and our average locational market differential was approximately $0.54 in Mcf.

We currently have approximately 33 Bcf of our remaining 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.41. We also have basis protected on approximately 50 Bcf of our expected fourth quarter gas production through our hedging activities and sales arrangements at an average differential to NYMEX of approximately $0.25 of Mcf, excluding fuel and transportation charges. Our detailed hedge position is included in our Form 10-Q that was filed this morning.

Operating income of our E&P segment was $172 million in the third quarter of 2009, compared to $281 million in the third 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 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 $0.76 per Mcf in the third quarter of 2009, compared to $0.96 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 for unit production were $0.38 per Mcf in the third quarter of 2009, compared to $0.33 for the same period in 2008. The increase was primarily due to higher payroll and other employee related costs associated with the expansion of our operations including a $5.4 million increase in incentive compensation that was accrued during the quarter, which was only partially offset by the effects of our increased production volumes.

For the year-to-date, our per unit G&A expense has declined from $0.38 per Mcf last year to $0.34 this year. Taxes other than income taxes were $0.10 per Mcf in the third quarter of 2009 down from $0.15 for the same period last year primarily due to lower commodity prices. Our full cost full amortization rate also dropped to $1.43 per Mcf in the third quarter down from $1.86 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 servicing segment was $25 million in the third quarter of 2009, up from $18.3 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 in the Fayetteville Shale, partially offset by increased operating costs and expenses. We invested approximately $1.4 billion during the first nine months of 2009 compared to $1.3 billion for the same period in 2008, and continue to expect that our total capital investments for the year will be approximately $1.8 billion. We have a strong balance sheet with significant liquidity and financial flexibility.

As of September 30, we had $285 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.1% for the quarter, our debt outstanding increased by $89 million resulting in total debt outstanding of approximately $960 million at September 30, and we had a debt to book capital ratio of 30%. Our debt to market capitalization ratio was only 6%. We believe that our focus on return on investment and our low cost structure combined with our large drilling inventory uniquely positions us to create significant value for our shareholders.

That concludes my comments and now we will turn back to the operator to explain the procedure for asking questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question is from David Kistler with Simmons & Company. Please state your question.

David Kistler - Simmons & Company

Wanted to touch real quickly on the well results in the Fayetteville. This last quarter we had a couple of wells that showed [flattish] ITs and slightly decreasing 30 and 60 day rates. I am guessing that's tied into the curtailment, but can you give us any additional color on that?

Harold Korell

You hit it pretty much on the head. As happened in the first quarter of this year, when we had some curtailments from last quarter of last year, there is a lot of play in the numbers because of the shut ins, and so by far the biggest part of that is that the other thing just to note if you compare what we did on the lateral links, lateral links is almost the same quarter-over-quarter, how much we fracked in the stages that we fracked and the (inaudible) intervals were almost identical on the wells, so part of that was us just testing spacing also on not varying some of those other parameters as much.

David Kistler - Simmons & Company

And then I guess kind of following down that line of questions, on the wells that IPs over 6 million a day. Can you talk about the lateral length that were there and the [frac] stages that were involved and what kind of learning might be taking place and how you think about then deploying capital and what not if that is a trend that you think you continue?

Harold Korell

The wells that we had that were over 6 million a day averaged a little over 4,500 foot lateral links, and there is actually a range on there from just under 4,000 to about 6,200 foot, the longest well we drilled to date lateral is not on production yet, but it is just over 8,000 feet. So, it’s not an issue of the length being physically able to drill it, it really comes down to not having any what we call white space, being able to cover the map with laterals and get as much as we can out of the ground. It looks like somewhere in the 4,500 to 6,000 foot range is where we're going to end up on those. You will see it continue to creep up over time. To do that though, and do it consistently with all of our wells we do need to have some rules changes with the government. Everything we have done that's basically greater than 4,500 feet, has taken an exception rule and we're working right now with the state to get past the exceptions to be able to do it on a regular basis.

David Kistler - Simmons & Company

What is the incremental cost uptick as you move to [45,000] to 6,000 kind of lateral stage?

Harold Korell

Those would have been where our average for last quarter was 2.9, say 6,000 foot lateral would be about 3.5.

Operator

Our next question is coming from Scott Hanold with RBC Capital Markets. Please state your question.

Scott Hanold - RBC Capital Markets

In the Marcellus, what are the plans? It sounds like you guys are going to be ready to ramp that up a little bit next year. Can you talk in terms of what we can expect, how many rigs, when you are going to get going and also as an extension of that the infrastructure just getting your gas out?

Harold Korell

We have not completely finalized 2010 budget. We’ve been working in 2009 to capture the water we need to drill, really with the three rig program. We are forming wells right now. I don't know that it will end up to be a three year rig program next year, but you should see us drilling early in the year in Pennsylvania, and then we'll kind of give more guidance on that as we finalize our capital budget. As far as take away, we drilled already four wells up there. We do have about 20 million of takeaway that we have to our name right now, and we think we can get some other takeaways. So as far as 2010 is concerned, we're preparing for that program and we think we'll be able to both sell our gas and drill and complete the wells when we need to.

Scott Hanold - RBC Capital Markets

On your hedging, looks like in your 10-Q you had some hedges and just give us your thoughts on how you're approaching 2010 and 2011 in terms of layering on additional incremental hedge? What's the price is there a price where you don't want to hedge below at this point?

Harold Korell

That is a pretty dynamic find as far as hedging goes. It starts with your financial condition, and depending on how your financial conditions it will tell you generally how much you have to hedge and you're in a very good position. So, we have been able to take a little more risk than we normally would going into both 2010 and as you say, we put some more in 2011. The hedges we put on in 2011 were in the mid $6, and then we have got one right around the $7 range, and that kind of tells what you we're targeting for overall prices. As we see those, you will see us work up hedges in both years.

Operator

Our next question is coming from Jeff Hayden with Rodman and Renshaw.

Jeff Hayden - Rodman and Renshaw

Can you just kind of jump into the Fayetteville real fast, with the commentary on the down spacing now testing even tighter, can you give us any update on what you're thinking as far as kind of where the rig count is going to go, what you think maybe the optimal number of rigs running the play is going to be?

Harold Korell

We have not been able to quite discern that yet. I would say when we gave guidance earlier in the year we said we were going to exit the year with 11 rigs running. More than likely it will be 13 when we exit this year. So, as we go into next year, we'll drill at least as many wells in 2010 as we did in 2009. We're looking at the whole rig situation and if and how we accelerate from there.

Jeff Hayden - Rodman and Renshaw

And then just really quickly with the second question just wondering as far as expense guidance goes pretty much no real changes from kind of what we saw in the third quarter?

Greg Kerley

That would be consistent, Jeff.

Harold Korell

And the only thing I would caution there is again, on the LOE a lot of large portion of that LOE is compression costs and as gas price moves up or down, that LOE will move up and down as well.

Operator

Our next question is coming from Brian Singer with Goldman Sachs. Please state your question.

Brian Singer - Goldman Sachs

When you look ahead to 2010 you highlighted some of the hedges you layered on, but how are you thinking about what level of free cash deficit if at all you would be willing to run and how that trades off versus maximizing production growth?

Greg Kerley

Brian, we're in the process of developing our capital plan and what we want our capital structure to look like, and what we expect production to be right now right in the middle of the flows with that. So, it’s a dynamic process for us and driven in part by what we see in the commodity price environment and what our hedge position is as we enter next year.

Harold Korell

The thing to add to what Greg said, you talked a little about whether it is maximizing production growth or living within cash flow basically, I want to remind everyone we maximize PVI and really don't target production growth. So, as we go into next year and we see what the prices are going to be, we will work on maximizing PVI however that works.

Brian Singer - Goldman Sachs

If we look at your historical wells that you so nicely lay out in your release, from the Fayetteville, maybe it is just a few of the wells that have been online for a while, but looking at some of the 4,000 feet laterals that have been on for almost two years, they're trending seemingly more above the 3 Bcf type curve than some of the other wells. I was wondering if there is anything to read from that if that all suggests that the decline rates start maybe a little less than expected.

Harold Korell

I am not sure you can read much from that with what we have today. It’s such a large area that we're going to need some more history and a lot of different places to say generally what the average wells are going to be and what the average shape of that well is going to be. Certainly the 4,000 foot laterals are performing better than the 3s and the whole group together. And as long as that continues that direction, we will continue adding lateral link like I talk about, continue adding more energy in the ground, but to say right now that there is an implication about what our [UR] is or how much better the UR, I don't know we're quite ready to say that yet.

Operator

Our next question is coming from Mike Scialla with Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

Can you talk a little bit more about those 200 wells that you drilled on the tighter spacing in terms of what kind of interference you might be seeing or is that 3 Bcf type curve do you think valid for even the 65 acre or less spacing?

Steve Mueller

In an optimum spacing, you want to have a little bit of interference, but not a whole lot of interference, and on average, and I need to emphasize, on average, because across the trend there is a lot of variation we're still trying to sort through. But on average on that 65 acres we talked about, we're getting somewhere between 12% and 15% interference. So there is some interference at that point, but I can tell you that there is a wide range.

Mike Scialla - Thomas Weisel Partners

And then you talked a little bit more about the Marcellus in terms of the geology that you see up in the area where you are and may be where your acreage is? How much is in Susquehanna versus Bradford and Lycoming?

Steve Mueller

I don't have the exact percentages right in front of me, but we have acreage in Lycoming, we have acreage in Bradford, Susquehanna as our major acreage positions and then we've got a little bit in couple other counties in Pennsylvania. In Lycoming, we have just over 20,000 acres and between Bradford and Susquehanna, Susquehanna has got more than Bradford. I would guess 60/40 on that kind of split as we look at it. It literally has three major acreage blocks, and so as we develop going into next year, we will concentrate on Bradford first and then we'll move out from there into the other blocks.

Mike Scialla - Thomas Weisel Partners

Anything else of the geology there? Is there any variation?

Steve Mueller

Well, the things we know with the wells we drilled and the people around us are we're in the thickest part of the Marcellus. There is not a lot of faulting, and we're learning like everyone else exactly where you want to land that because when I say thickest part, parts of our acreage is over 400 foot thick. So part of what we're doing is watching where the industry is landing their wells and then we can build on that knowledge as we go forward. So I think the big two things about it is there's good wells around us. We like what we saw in our wells and it is a thick session.

Operator

Our next question is coming from Ben Dell with Bernstein Research.

Ben Dell - Bernstein Research

I guess my question is on the Fayetteville. You've obviously increased the number of stages you've been doing over time, and it looks like the relationship with the [IP] is fairly linear. Do you have a feeling for what level of stages you won't see an improvement in IPs or where they look as though they're helping out if you assume 110-acre space?

Steve Mueller

Not yet. If I am watching and doing the spacing then there obviously will be some kind of stages that will pop out at. For instance, if you drilled as tight as 10-acre spacing, I would expect that you would have a lot of interference and you might actually back off on your stages and yet could get very good recovery possibly. That's some of the things we're testing. So as we go to smaller spacing, we're also going to test different stages as we go through it.

Ben Dell - Bernstein Research

And what's the largest number of stages you currently completed in the Fayetteville?

Steve Mueller

I don't know the exact number, but we have done several with 14 stages.

Ben Dell - Bernstein Research

Can you give us an idea of incremental cost per frac?

Steve Mueller

Per stage I really don't have that number right off the top of my head, but I would say that going back to a 10 stage versus a 14 stage, that's a couple hundred thousand dollars difference.

Operator

Our next question is coming from Jason Gammel with Macquarie Capital.

Jason Gammel - Macquarie Capital

I want to ask a question about the Haynesville activity that you have. It seems to me that the area that you're drilling in Western Shelby and St. Augustine County is delivering a lot better initial production rates than most of the rest of East Texas. I wondered if you could comment on the geology you're seeing there and maybe your theory on why the initial rates are so much higher than a little bit north of there.

Harold Korell

We certainly don't know at this point with only four wells if any information on them. But we think that the rock is more brittle there because of the carbonate ratio. We're seeing significantly higher carbonate there versus Northern Texas and really as you get into Louisiana it seems there is more silica sand than manganese carbonate. But it looks like that carbonate is making it brittle enough so that you can get better fractures and potentially have some natural fracturing or natural breaks in the rock. So that's always the thought right now and with little more wells we'll figure out if that's really true or not.

Jason Gammel - Macquarie Capital

Maybe as my second question, I will ask a follow-up on that. You have kind of been taking the Haynesville drilling more or less one well at a time basis. Based on what you have seen so far, would you expect that you will keep a one or two rig program active there into 2010 and may be beyond that?

Harold Korell

That's one of the questions that we're really working on as far as 2010 budget. Certainly with each well getting a little bit better as we drill the wells out there, that encourages to drill more wells. We need to see a little more not only our wells, but the industry wells to see how big this could be. Then we can make a decision on whether we will go faster or slow down. Certainly through the first quarter of next year, probably into the second quarter with the encouragement we have now, we'll continue drilling. And then we start to sort out from there.

Operator

(Operator Instructions). Our next question is coming from Monroe Helm with CM Energy Partners.

Monroe Helm - CM Energy Partners

Just a couple of questions following up on your East Texas activity. I know it's early days, but can you give us your best guess as to what you think the well costs are going to be for these Haynesville Bossier wells and what the URs are that you are targeting right now and maybe do the same thing for the James Lime?

Steve Mueller

As far as the well costs, our initial wells were well over $10 million. The last two are going to be in the $9 million to $10 million range. And we think we can get around $9 million wells. I don't know, maybe a little bit less than that. That's kind of what we are targeting for well costs in the Haynesville and we're not too far from that. As far as I am not sure, what we're targeting. We're trying to learn about what the URs could be. We don't have enough production to say for sure, but with the production we have on say that $13 million a day well, that's one that's got a little bit of time line. It's got three months or so on it. That looks like it is going to be in a 5 Bcf range, give or take. And that's using tight curves that the rest of the industry has because again we don't have enough data right where we're at.

In the James Lime, we're looking at 2.5 to 2.7 Bcf wells and I think the last well we drilled out there was just over $3 million to drill that well. That has come down and was almost $4 million earlier in the year, and the reason it's come down is early in the year. It was taking us about 30 days to drill a well. The most recent one we have done I think was 15 days.

Monroe Helm - CM Energy Partners

Just as a follow-up on those two, what's the minimum gas price you need to meet your (inaudible) on drilling these two different areas?

Steve Mueller

James Lime is economic on today's curve. It needs something in the high 4s, low 5s to drill at and it is fine as far as that goes. On the Haynesville, we need to have that 13 million to 15 million a day minimum wells and have those parameters I just described to make that work at today's curve.

If it is that first well, that 7 million a day well, you need something in the high 7, lower $8 NYMEX to do that.

Monroe Helm - CM Energy Partners

One follow-up if you don't mind. Just looking at your 10-Q, it looks like you really hadn't [added] to your hedge position in 2010 versus what you had at the end of last year. Is that right?

Steve Mueller

That is correct.

Monroe Helm - CM Energy Partners

The way the gas market is shaping up for 2010 you're going to add to your hedges for this year or are you more optimistic about where the gas prices are going to or just leave the hedge position like it is?

Steve Mueller

We have obviously left it here for a while. We have had that position most of the year. We think there is going to be some times where we can catch more hedges at a little bit higher price than we had today. So I am not going say that we're happy with where we are at, but we will just keep working at it.

Monroe Helm - CM Energy Partners

Follow-up to that, since you've not had hedges last year and you haven't done your 2010 drilling budget, but is this going to have an impact on how much capital you're willing to spend in 2010 relative to cash flow that you think you're going to throw off? In other words, if you had more hedges on higher prices would you have a higher drilling program in '010 than '09?

Steve Mueller

I would say that per se yes. It depends on how high and what that was.

Harold Korell

What's interesting, as these questions go on today, I think, Brian, hit at sort of the same question, and somebody has asked about how active we would be in drilling in the Marcellus and will we be more active next year. Same question kind of comes from the Haynesville. There was a question about the number of rigs we would have operating in the Fayetteville, and so when you begin to build a plan like this, all of those things are variable and moving targets and our capital planning has to be fluid to respond to where gas prices are moving.

So we need to be conscious. We have a lot of room on your balance sheet, but we also want to be conscious of not moving our debt up. So you guys are all hitting at all the questions about managing the company. And before we go out a plan, we want to turn over more cards, not about the performance of our wells and the inventory we have, but more cards about where pricing is going to be because we to want have a plan for 2010 that is a responsible plan relative to the debt levels we get at. It takes advantage of the opportunities we can in the optimum way to maximize PV.

We are just not there yet and we usually don't really enumerate a whole lot on next year's plan until we get our Board approval in December or sometimes in February. That's what you should expect there again. Good news is we have a lot of good things to do at these price levels. But we would do more if prices were higher.

Operator

Our last question is coming from Joe Allman with JPMorgan.

Joe Allman - JPMorgan

In terms of the Fayetteville, looking at the table that you provide in your press release, without the curtailments, are you seeing the IP rates increase in aggregate? Are you seeing the 30th day production on average increase in aggregate versus what we saw in the second quarter?

Steve Mueller

That's one of our problems. That's really hard to tell. Without the curtailments, the key there, when you shut in a well and then put it back on, there is what they call the storage effect. It changes the trends that you had for very short periods of time and trying to factor that in especially when it wasn't just that we had one shut in, but over the quarter we had three or four or five shut ins. And they weren't all those wells being shut in.

Harold Korell

He doesn't mean three or four wells shut in. He means three or four times that are shutting in multiple wells.

Steve Mueller

It wasn't necessarily the same wells every time there was a shut in, so trying to sort through that has been very difficult. So I would say the same thing we did at the first quarter where we had been shut-in in the fourth quarter last year. We need to watch for a couple more quarters and get these wells back stabilized again before I think much about any of the rates frankly.

Joe Allman - JPMorgan

Then a separate question. In terms of your LOE in the Fayetteville or (inaudible) what percentage of LOE is compression roughly?

Steve Mueller

A kind of answer in the other direction. Roughly $0.50 is what I will call fixed costs, a little over $0.50, and so in this quarter what was like $0.76, $0.78, that $0.26 or $0.28 was compressing.

Operator

We do have a follow-up question coming from Mike Scialla with Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

I was just wondering on your Haynesville wells any plans to test the Bossier over there, does that look prospective as well?

Steve Mueller

We are drilling a Middle Bossier well right now, and as far as perspective goes, one of the wells we drilled earlier we actually called the Middle Bossier. It has thickness and at least that core gave some indications to test it with the well we're drilling now. And we'll just see how it works from there.

Operator

We do have a question coming from [Stuart Wineman] with Catapult Partners. Please state your question.

Stuart Wineman - Catapult Partners

Just wanted to ask, would you be willing to give any color around where you might exit 2009 for production?

Steve Mueller

No. One of our problems that we've got and even trying to figure out exactly what our guidance should be for the fourth quarter is that we're still pointing on wells from that shut-in time period. And as they are pointing on wells we got a backlog. It will take us another month to really to get that backlog worked through of wells that (inaudible) partially completed or completed, and waiting. And so that will affect both fourth quarter and our end of the year numbers.

Stuart Wineman - Catapult Partners

And then on the Marcellus next year, is that going to be a full horizontal drilling program or is there still going to be verticals in that?

Steve Mueller

Everything we plan will be horizontal.

Operator

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.

Steve Mueller

I want to thank all of you for taking the time to listen to our call today. We've had a great quarter. We're looking forward to the fourth quarter, and we're looking forward to having all these problems behind us so we can get back and sort out some of these things we talked about. Thank you again and we'll talk to you here in another quarter.

Operator

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time and we thank you for your participation.

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Source: Southwestern Energy Co. Q3 2009 Earnings Call Transcript
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