Southwestern Energy Company

Q3 2009 Earnings Conference Call

Friday, October 30, 2009 - 10:00am EST

Officers

 Harold Korell; Southwestern Energy Company; Executive Chairman

 Steve Mueller; Southwestern Energy Company; President, CEO

 Greg Kerley; Southwestern Energy Company; EVP, CFO

Analysts

 David Kistler; Simmons & Company; Analyst

 Scott Hanold; RBC Capital Markets; Analyst

 Jeff Hayden; Rodman and Renshaw; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Mike Scialla; Thomas Weisel Partners; Analyst

 Ben Dell; Sanford C. Bernstein and Company, Inc.; Analyst

 Jason Gammel; Macquarie Research Equities; Analyst

 Monroe Helm; CM Energy Partners; Analyst

 Joe Allman; JP Morgan; Analyst

 Stuart Weinman; Catapult Partners; Analyst

Presentation

Operator: Greetings and welcome to the Southwestern Energy Company third quarter earnings conference call.  (Operator Instructions).  It is now my pleasure to introduce your host, Harold Korell, Executive Chairman of the Board for Southwestern Energy Company.  Thanks, sir, you may begin.

Harold Korell:  Good morning and thank you for joining us. 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 Statement sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Well, 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 to the Boardwalk Pipeline. We do not expect these factors to weigh as 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 1 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 high-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 afterward.

Steve Mueller:  Thank you, Harold, and good morning. During the third quarter of 2009, we produced 73.2 Bcfe, up 38% from the 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 9.0 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 the 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 shut down since September 1^st. The Greenville Lateral was also 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 Bcfe 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. As of October 24^th, our gross production rate was approximately 1.23 Bcf per day, double the 600 MMcf per day from a year ago. We currently have 17 drilling rigs running the Fayetteville, 13 that are capable of drilling horizontal wells and 4 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 re-entry to re-entry.

Beginning in late 2008, we began drilling wells in the Fayetteville shale to test tighter well spacing. Through September 30^th, we had 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 data 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 MMcf per day. Subsequent to the end of the third quarter, and through October 23^rd, we placed two additional wells on production with initial rates over 6 MMcf a day, 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 MMcf per day.

I’ll now move on to 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 #1, reached total depth in the fourth quarter of 2008. This well, with a completed lateral length of 2,718 feet, was production tested at a rate of 7.2 MMcf per day in the first quarter of 2009.

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 at 13.4 MMcf per day in the second quarter.

We have completed a third well, the Red River 619 #1, 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 MMcf per day.

Our fourth well, the Burrows Gas Unit 1H, is currently being tested. A fifth well, the Red River 257 #1, is waiting on completion and finally, we’re currently drilling our sixth well, the Red River 257 #2, which is targeting the middle Bossier, both located in San Augustine County.

Our total production from the Haynesville is currently approximately 34.7 MMcf per day gross or 10.2 MMcf per day net.

Finally, we participated in drilling 14 wells in conventional Arkoma Basin and 33 wells in East Texas during the first nine months of 2009. 28 of the East Texas wells were James Lime horizontal wells. Production from our 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 have had 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 shales.

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

Greg Kerley:  Thank you, Steve, and good morning. We had a solid quarter, despite depressed natural gas prices and 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 assets 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 per 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 per Mcf, excluding fuel and transportation charges. Our detailed hedge position is included in our Form 10Q 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 per unit of 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 non-cash ceiling test impairment we recorded in the first quarter of 2009.

Operating income from our midstream services 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^th, 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^th. 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. So now, we’ll turn back to the operator who will explain the procedure for asking questions.

Questions and Answers

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

David Kistler: I wanted to touch real quickly on the well results in the Fayetteville.  This last quarter we had a couple wells that showed flattish IPs and slightly decreasing 30- and 60-day rates.  I'm guessing that's tied into the curtailment, but can you give us any additional color on that?

Steve Mueller: I think the--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's a lot of play in the numbers because of the shut-ins.  And so, by far the biggest part of that is that.  And the other thing just to note, if you compare what we did on the lateral lengths, the lateral lengths is almost the same quarter over quarter.  How much we frac'd and the stages that we frac'd and the perf intervals were almost identical on the wells.  So part of that was us just testing spacing also and not varying some of those other parameters as much.

David Kistler: Okay, that's helpful.  And then, I guess kind of following down that line of questioning, on the wells that IP'd over 6 MMcf a day.  Can you talk about the lateral lengths that were there and the frac stages that were involved and what kind of learning might be taking place and how you think about them deploying capital and what not, if that's a trend that you think can continue?

Steve Mueller: Well, the wells that we had that were over 6 MMcf a day averaged a little over 4,500 lateral lengths and there's actually a range on there from just under 4,000 to about 6,200 foot.  So, on this well we've drilled to date, lateral is not on production yet, but it's just over 8,000 feet.  So, it's not an issue of the length--of 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.  So, you'll 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've 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 and be able to do it on a regular basis.

David Kistler: And just one quick one.  What is the incremental cost up tick as you move the 4,500 to 6,000 kind of lateral feet?

Steve Mueller: Those would have been--where our average for last quarter was $2.9, I think our--I'd say a 6,000-foot lateral will be about $3.5.

Operator: Our next question if coming from Scott Hanold with RBC Capital Markets.  Please state your question.

Scott Hanold: In the Marcellus, what are the plans?  I mean, it sounds like you guys are going to be ready to ramp it 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 issue, just getting your gas out.

Steve Mueller: We have not completely finalized the 2010 budget.  We've been working in 2009 to capture the water that we need to drill really with the three-rig program. We are permitting wells right now.  I don't know that it will end up to be a three-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 takeaway, as you know, we've drilled already four wells up there.  We do have about 20 MMcf of takeaway that we have to our name right now.  And we think we can get some other takeaway.  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 that we need to do.

Scott Hanold: Okay, good.  And then, the second question.  On your hedging, it looks like in your 10-Q you added some hedges.  And just give us your thoughts on how you are approaching the 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?

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

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

Jeff Hayden: Hey, guys.  Just kind of jumping to 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 may be the optimal number of rigs running the play is going to be?

Steve Mueller: 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 on to next year, we'll drill at least as many wells in 2010 as we did in 2009.  And then, we're looking at the whole rig situation and if and how we accelerate from there.  

Jeff Hayden: Okay.  And then, just really quickly for 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.

Steve Mueller: And the only thing I would caution there is, again, on the LOE, a lot--a large portion of that LOE is compression cost 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: When you look ahead at 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'd be willing to run and how that trades off versus maximizing production growth?

Greg Kerley: Well, 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 throes of 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.

Steve Mueller: I think the thing to add to what Greg said, you talk about whether it's maximizing production growth or living within cash flow basically.  I want to remind everyone, we maximize PVI and we 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: Got it.  Thanks.  And then, if we look at your historical wells that you so nicely lay out in your release from the Fayetteville, maybe it's 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.  And I was wondering if there is anything to read from that, if that all suggests that the decline rates may be a little bit less than expected.

Steve Mueller: I'm 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 in a lot of different places to say generally what the average was 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 3's and then the whole group together.  And as long as that continues that direction, we will continue adding lateral in places I've talked about, continue adding more energy in the ground.  But to say right now that there's an implication about what our EUR is or how much better the EUR, 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: 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 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 it's on average, because across the trend there's a lot of variation and we're still trying to sort through it.  But on average on that 65-acre that 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's a wide range.

Mike Scialla: Okay, thanks.  And then, can you talk a little more about the Marcellus in terms of the geology that you see up in the area where you are?  And maybe 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 is our major acreage position, and then we've got a little bit in a couple other counties in Pennsylvania.  In Lycoming, we have just over 20,000 acres and in 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.  And it's really--it literally is 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 to the other blocks.

Mike Scialla: Do you see anything as to the geology there?  Is there any variation?

Steve Mueller: Well, we're--the things we know with the wells we've 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 well 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 we're--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's a thick section.

Operator: Our next question is coming from Ben Dell with Sanford C. Bernstein and Company.

Ben Dell: 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 IPs is fairly linear.  Do you have a feeling for at what level of stages you won't see an improvement in IPs or where they look as though they are topping out, if you assume 110-acre spacing?

Steve Mueller: Not yet.  There will obviously be--depending what you end up doing in the spacing, there obviously will be some kind of stages that we'll top out at.  And I'll just give you a for instance.  If you drilled as tight as 10-acre spacing, I would expect that you'd have a lot of interference and you might actually back off on your stages and yet could get very good recovery possibly.  And 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:  And what's the largest number of stages you've currently completed in the Fayetteville?

Steve Mueller: I don't know the exact number, but we've done several with 14 stages.

Ben Dell: And in terms of the--can you give us an idea of incremental cost per frac?

Steve Mueller: First 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 $200,000 difference.

Operator: Our next question is coming from Jason Gammel with Macquarie Research.

Jason Gammel: Thank you.  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, in sort of Western Shelby and San Augustine County, is delivering a lot better initial production rates than most of the rest of East Texas.  I wonder if you could comment on the geology that you're seeing there and maybe your theory on why the initial rates are so much higher than a little bit north of there.

Steve Mueller: We think, and we certainly don’t know at this point with only 4 wells with 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 north in Texas and really as you get into Louisiana it seems that there’s more silica sand in it than there is carbonate. But it looks like that carbon 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 at least the thought right now and with a little more wells we’ll figure out if that’s really true or not.

Jason Gammel: Okay great. And then maybe as my second question I’ll ask a follow-up on that. You’ve kind of been taking the Haynesville drilling more or less one well at a time basis. Based on what you’ve seen so far, would you expect that you’ll keep a one or two rig program active there into 2010 and maybe beyond that?

Steve Mueller: 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 some more wells. We need to see a little more, not only our wells but the industry wells and see how big this could be and then we can make a decision on whether we go faster or slow down. Certainly through the first quarter of next year, probably in the second quarter, with the encouragement we have now we’ll continue drilling and then we’ll just have to sort it out from there.

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

Monroe Helm: Great results. 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 oil costs are going to be for these Haynesville Bossier wells and what the EURs are that you’re targeting right now and then maybe do the same thing for the James Lime?

Steve Mueller: As far as the well cost, our initial wells were well over $10 million; the last two are going to be in the $9 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, but that’s kind of what we’re targeting for oil costs in the Haynesville and we’re not too far from that. I’m not sure we’re targeting any EUR; we’re trying to learn about what the EURs could be. We don’t have enough production to say for sure, but with the production we have on say that 13 MMcf a day well, that’s one that’s got a little bit of time on it; it’s got three months or so on it. That looks like it’s going to be in the 5 Bcf range, give or take. And that’s using type curves that the rest of the industry has, because again, we just 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. It 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’ve done I think it was 15 days.

Monroe Helm: Just as a follow-up on those two; what’s the minimum gas price you need to meet your rates of return on drilling these two different areas?

Steve Mueller: Well James Lime is economic on today’s curve. It needs something in the high $4s, low $5s to drill it and it’s fine as far as that goes. On the Haynesville, we need to have that 13 to 15 MMcf a day minimum wells and have those parameters I just described, to make that work at today’s curve. If it’s that first well, that 7 MMcf a day well, you need something in the high $7s, low $8 NYMEX to do that.

Monroe Helm: Okay. One follow-up if you don’t mind. Just looking at your 10-Q, it looks like you really hadn’t put on any -- maybe I’m wrong on this but it looks like you really haven’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: Would you anticipate, given the way the gas market’s shaping up for 2010 that you’re going to add to your hedges for this year or are you more optimistic about where the gas price is going to just leave the hedge position like it is?

Steve Mueller: Well, we’ve obviously left it here for a while. We’ve had that position most of the year. We think there’s going to be some times that we can catch some more hedges at a little bit higher price than we have today, so I’m not going to say that we’re happy with where we’re at, but we’ll just keep working at it.

Monroe Helm: Just a follow-up to that; since you’re not as hedged as 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 at higher prices would you have a higher drilling program in 2010 than 2009?

Steve Mueller: I would first say, yes. It depends on how high and what that was.

Harold Korell: Well it’s interesting as these questions go on today. I think Brian hit 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. The 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, you know, 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 and we need to be conscious. We have a lot of room on our 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 we will continue -- before we put 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 want to have a plan for 2010 that is a responsible plan relative to the debt levels we get at, yet takes advantage of the opportunities we can and the optimum way to maximize PV.  So you know, we’re 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. So that’s what you should expect there again. The 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: 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. It’s really hard to tell. Without the curtailments, the key there, when you shut-in a well and then put it back on, there’s what they call a storage effect and 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 even all those same wells being shut-in.

Harold Korell: He doesn’t mean three or four wells shut-in, he means three or four times it was shut-in.

Steve Mueller: Times it was shut-in.

Harold Korell: Multiple wells.

Steve Mueller: And as I was saying, it wasn’t necessarily the same wells every time there was a shut-in. So trying to sort through that has been very difficult and so I would say the same thing we did in the first quarter where we’d been shut-in in the first quarter last year, we need to watch it for a couple more quarters and get these wells back stabilized again before I can say much about any of the rates, frankly.

Joe Allman: Okay that’s helpful. Then a separate question; in terms of your LOE in the Fayetteville or even just overall, what percentage of LOE is compression, roughly?

Steve Mueller: I’ll kind of answer it in the other direction. Roughly $0.50 is what I’ll call fixed cost, a little over $0.50 and so in this quarter it was like $0.76 or $0.78, that $0.26 or $0.28 was compression.

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

Mike Scialla: I just wondered on your Haynesville wells, any plans to test the Bossier over there; does that look perspective as well?

Steve Mueller: We are drilling a middle Bossier well right now. As far as perspective goes, one of the wells we drilled earlier we actually cored the middle Bossier. It has thickness and at least that core gave us some indications to at least 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 Weinman with Catapult Partners.  Please state your question.

Stuart Weinman: I 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 in even trying to figure out exactly what our guidance should be for the fourth quarter is that we’re still putting on wells from that shut-in time period. As they put on wells, we’ve got a backlog, it’ll take us another month really to get that backlog worked through of wells that either are partially completed or completed and waiting. And so that will affect both fourth quarter and our end of the year numbers.

Stuart Weinman: Okay thanks. 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’re planning 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 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.

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

See the reconciliation below of GAAP financial measures to non-GAAP financial measures for the three months ended September 30, 2009 and 2008.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.