Southwestern Energy Company Q1 2008 Earnings Teleconference

Friday, April 25, 2008

Officers

 Harold Korell; SWN; President, Chairman, and CEO

 Richard Lane; SWN; President, Exploration & Production

 Greg Kerley; SWN; CFO

Analysts

 Brian Singer; Goldman Sachs; Analyst

 Scott Hanold; RBC Capital Markets; Analyst

 Amir Arif; FBR Capital Markets; Analyst

 Gil Yang; Citi; Analyst

 Tom Gardner; Simmons & Company; Analyst

 Joe Allman; JP Morgan Securities; Analyst

 David Heikkinen; Tudor, Pickering and Co.; Analyst

 Jeff Hayden; Pritchard Capital Partners; Analyst

 Mike Scialla; Thomas Weisel Partners; Analyst

 Joe Allman; JPMorgan; Analyst

Presentation

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

Harold Korell: Good morning, and thank you for joining us. With me today are Richard Lane, the President of our E&P segment, and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of the press release we announced yesterday regarding our first 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 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 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, to begin with, we've had a very good start to 2008, as you can see in our first quarter results.  

Our progress in the Fayetteville Shale continues to improve, resulting in strong growth in our production volumes, which were up dramatically over last year.  This growth is primarily fueled by the Fayetteville Shale, where our gross operated production recently reached approximately 400 million cubic feet per day, up from approximately 155 million cubic feet per day a year ago.  

We also have begun to see the impact of our James Lime activity in East Texas, and as a result of these efforts, we have moved our second quarter production guidance up by around 15% compared to our previous estimate.  

Overall, I'm very pleased with our results, and we look forward to further guidance for the third and fourth quarter after completing the reassessment of our 2008 asset sales and capital investment plans.

I'd like to now turn the teleconference over to Richard for more details on our E&P activities and then to Greg for an update on our financial results, and then we'll answer questions.

Richard Lane:  Thanks, Harold.

Good morning.  During the first quarter, we produced 39.1 Bcfe, up 71% from the first quarter last year.  

Our Fayetteville Shale production was 23.6 Bcf, up significantly from the 8.2 we produced in the first quarter of 2007.  

Production from East Texas was 8.1 Bcfe, 5.9 from our Conventional Arkoma properties and 1.5 from our Permian/Gulf Coast.  

As a result of our strong first quarter performance, we now estimate that our second quarter production will range between 41.5 and 42.5 Bcfe.  

In the first quarter, we invested approximately $377 million in our exploration and production business activities and participated in drilling 169 wells.  Of the $377 million invested, approximately 84% was for drilling wells.  

In the Fayetteville Shale in the first quarter, we invested approximately $285 million, including $237 million to spud 122 wells.  As Harold said, at April 14, our gross operated production rate here was approximately 400 million cubic feet per day, up from approximately 155 million cubic feet per day a year ago.  

During the first quarter of 2008, our typical well had an average completed well cost of $2.9 million, an average lateral length of 3,285 feet, and an average time to drill of 15 days from reentry to reentry.  

As of March 31, we had drilled and completed 142 wells with lateral lengths over 3,000 feet.  We forecast that the average gross ultimate recovery from wells with greater than 3,000 feet, horizontal laterals, will range from 2 to 2.5 Bcf per well, with an average completed well cost of approximately $3 million.  As expected, we are continuing to see improved results as we are drilling our wells with longer laterals and completing them more effectively.  

In late 2007, we began a project to demonstrate the benefits of full-scale development strategy in a four-section area of our Southeast Rainbow pilot area in Conway County.  

Through the middle of April, we have spud 22 wells in the area, 21 of which have been drilled to total depth.  Based on the limited production histories of the 10 wells that are already on production, we're seeing improved initial production rates, shorter drill times, and lower costs than the offsetting wells.  We expect all the 22 wells will be fracture stimulated and on production by the end of the second quarter.

Results from the pilot area are already beginning to provide potential improvements for the play's full-scale development, including using multi-well pads to reduce costs and our surface impact and concentrating operations to improve overall efficiency.

And some new ventures activity --

In Pennsylvania, we currently have approximately 100,000 net undeveloped acres, where we believe the Marcellus Shale is prospective, and we are currently analyzing core on our first vertical well here and drilling our second.

In our Conventional Arkoma activities in the first quarter, we invested approximately $36 million.  We participated in drilling 26 wells here, including 15 at our Ranger Anticline Field and 5 at our Midway Field.  And our production from the Conventional Arkoma in the first quarter was 5.9 Bcf, up from 5.5 in 2007.

In East Texas in the first quarter, we invested approximately $52 million and participated in 14 wells.  Production from East Texas was 8.1 Bcf in the first quarter, up from 7.6 in the same period in 2007.  

We continue to be excited about the developing James Lime play, where we have a significant acreage position.  Through the end of the first quarter, we had four operated James Lime wells on production.  The gross initial production rate from these four wells ranged from 5 million to 14.4 million cubic feet per day.  

We're also currently testing our fifth operated well here.  Our current net production from the James Lime is approximately 12 million cubic feet per day, including production from some outside operated wells.  

Due to our recent success in the James Lime, we now plan to participate in approximately 21 net wells in 2008, and this is up significantly from our original '08 plan, which called for 10 net wells.  

In summary, we had an outstanding quarter in our E&P business and are looking forward to continued strong results in the remainder of 2008, including meeting or exceeding our PVI target, achieving significant production growth, and significant increases in proved reserves.

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

Greg Kerley:  Thank you, Richard, and good morning.  

Significant growth in our production volumes drove record earnings in the first quarter of $109 million, or $0.31 a share, more than double the prior-year period.  

Our operating cash flow also increased significantly to $283.7⁽¹⁾ million, up almost 100% from the prior year.  

Operating income for our E&P segment was $165.7 million during the quarter, up from $74.3 million in the same period a year ago.  

We produced 39.1 Bcf in the first quarter, up 71% from a year ago, and realized an average gas price of $7.70 per Mcf.  Our commodity-hedging program increased our average gas price during the quarter by $0.24 per Mcf.  

Our leased operating expenses for unit of production were $0.77 per Mcf-equivalent in the first quarter, up from $0.74 a year ago.  The increase was primarily due to increased production from our Fayetteville Shale play, which has higher per-unit operating costs than our other focus areas.  

General and administrative expenses per unit of production were $0.42 per Mcf in the first quarter, down from $0.47 last year, while the decrease was primarily due to the effects of our increased production volumes, which more than offset increased payroll and related costs associated with the expansion of our E&P operations.

Taxes, other than income taxes, were $0.16 per Mcf in the first quarter, down from $0.27 in the prior year, due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes and accrued severance tax refunds related to our East Texas production.

Our full-cost pool amortization rate averaged $2.30 per Mcf in the first quarter, compared to $2.24 a year ago.  

Operating income from our Midstream Services segment was $10.2 million during the first quarter, compared to breakeven a year ago.  The increase was due to higher gathering revenues related to our Fayetteville Shale play, partially offset by increased operating costs and expenses.

We are currently gathering about 470 million cubic feet of gas a day in the Fayetteville Shale play area through approximately 634 miles of gathering lines.  

Operating income per utility was $11.6 million in the first quarter, up from $9.4 million in the prior year.  The increase in operating income was due to colder weather, along with the implementation of a rate increase, which became effective August 1, 2007.  

We've been working for the past several months on improving our liquidity and strengthening our balance sheet, as well as positioning Southwestern for future growth.  

In November of last year, we signed a stock sale and purchase agreement for the sale of our utility subsidiary for $224 million plus working capital.  The sale is subject to certain closing conditions and regulatory approvals and is expected to close around mid-year.  

In April, we announced the sale of our portion of our Fayetteville Shale acreage for approximately $520 million, and we are currently marketing our Permian Basin and Gulf Coast E&P assets.

At March 31, 2008, we had total debt outstanding of approximately $1.1 billion, resulting in a capital structure of 41% debt and 59% equity.  The combination of our strong production growth, higher realized commodity prices, and planned asset sales is expected to significantly improve our balance sheet, and as a result, our total debt could decline to 25 to 30% by year-end.  

As you've heard from our comments today, we're off to a great start in 2008.  That concludes my comments, and I will turn it back to the Operator, who will explain the procedure for asking questions.

Questions and Answers

Brian Singer:  Could you talk a little bit more about the Southeast Rainbow pilot?  With the rates that you've seen and the costs having come down to, I guess, about $2.6 million, where do you think you are in that process?  What are your expectations for the remaining wells in terms of where you think you can take costs?  And what conclusion do you take for your larger acreage as you move towards more pilots within your Fayetteville position?

Richard Lane:  Well, Brian, we're really encouraged by what we're seeing there.  I think you can tell by the numbers of wells that we've talked about that we're really just getting going in that kind of mode.  

I think it's important to recognize that regionally in the play, the costs are going to vary because of depths and other things like that, so we almost have to look at not so much the absolute costs right there but the kind of savings that we think we can achieve per well.  That should be able to be duplicated in other areas.  So we're seeing somewhere around $200,000 worth of potential savings from that focused activity for some of the reasons we talked about in our release, and it's real, real encouraging.  We'll try to expand that footprint this year and verify it some more and try to go into that mode for most of what we do eventually.

Brian Singer:  Do you see further potential for cost decreases, or do you think $2.6 million is a good number going forward?

Richard Lane:  Well, $2.6 is specific to that area, which -- you know, my first point, so I wouldn't carry that across the entire play.  I think that the net difference we're seeing is probably the repeatable -- hopefully, the repeatable saving.  So --

Harold Korell:  There are two things, Brian, that affect that.  Maybe more clearly stated is that where we are drilling -- where the play is deeper and where we have to drill deeper, the costs won't likely be $2.6 million per well.  

Of course, the other thing that can affect this entirely is what happens to service costs as time goes on, and there may be some areas of the play where we can't set up and drill these nice geometric north/south patterns due to structural complexities that could exist there.  And so -- but that's just -- not saying we won't.  

We should incur savings as we're able to do pad drilling and do full development-type scenarios, but there are a lot of factors that come into play.  This is a very broad area we're drilling across, and I don't think it's possible for us to say exactly what those cost parameters are going to be across the whole thing.

Richard Lane:  Yes, I would also say, Harold, that we're still experimenting with our completion methodology there and trying some things that have some promise to be an economically positive impact but may cost more per well, so I think the thing to focus on is the efficiencies we might get that we can duplicate across the area.

Brian Singer:  Thank you.

Scott Hanold: Thanks. Good morning. Hey, when you guys obviously look at your 2008 production, I guess you didn't sort of update what your expectations are. Is there anything generally we should sort of look at as far as what your capacity looks like and kind of give us a sense of is there anything, constraints in the system we need to be aware of, and what's sort of the update on the Boardwalk Pipeline from your perspective?

Greg Kerley: Well, the Boardwalk Pipeline at this point is on schedule. We're still expecting it, at least the first leg of it, to be in service sometime before the end of the year, which will take us over to the east part of still the current markets that we service now, but just increase capacity there. And as far as constraints right now, we're building gathering line and adding compression to keep up with the field activity. So, we don't see any -- there's no delays in type orders or delays in compression being received or anything like that at this point.

Scott Hanold: Okay, very good. And as far as your capital budget, I guess the first quarter you spent a little bit more. If you sort of extrapolate that across the year versus where your original budget is, can you give us a sense of how much that could go up versus what your current budget's at?

Richard Lane: Well, one of the things that we try, as Harold indicated in his early comments, is that we're currently looking at or revisiting our plan and how it will be affected by our asset sales, also by the improvements that we've seen for well results. So, those things combined will really drive what we think capital for the rest of the year will be. And we're not ready yet to issue new guidance there. We've still got some work to do to develop that.

Amir Arif: Morning, guys. A question also on the multi-well pack rolling that you're doing. You talked about the cost and the savings synergies. Can you talk a bit more about the better rates you're getting out of these wells, and whether that's just due to the lateral lens or is it due to better optimization of the fracs, or what do you think that's driving that?

Richard Lane: I think it's both of those, Amir. When we look at the offset wells -- we're trying to pull the best analogy to the new activity, so we have an average lateral maintenance a little higher, and then we have the benefit of our newest thinking on completions. So, I think it's both of those things.

Harold Korell: You know, from the beginning of this play, we've talked about the name of the game being to get in touch with the most rock you can per dollar invested, and that's what we continue to work towards. And that means working towards improving the fracture stimulation. It means longer laterals, doing the best fracturing with it you can, which can mean a lot of technical things, some of which we believe we're getting some additional breakthroughs in regard to the completion itself, and of course longer laterals. And then work towards continuing to decrease the cost. As Richard had mentioned earlier, some of the things we're doing actually increase the cost, but if they increase the output more dramatically than the cost is increased, then PVI goes up, and we're about PVI.

Amir Arif: That sounds good. And just a follow-up. In terms of the spacing down to about 100-acres, are you seeing any kind of communication or do you feel that you can even take that spacing lower?

Richard Lane: We're not seeing interference, is the answer to the question. We're hopeful we can go lower than that. That just doesn't -- in my gut that doesn't seem like where we'll end up, and the well results confirm that so far.

Amir Arif: And final follow-up question, just on the lateral lens, how far do you want to push those lenses in terms of the formation you have and the rig capacities you have?

Richard Lane: Well, I think the rig capacity will do pretty much all we want to do. In those average numbers that we're publishing, we have some less than the average and some more than the average. We have really a pretty good number of wells that we've gone out to 4,000-feet and done those fairly well, without a lot of well problems. So, we're moving that direction.

Gil Yang: Good morning, everyone. Richard, if you look at your operations in the quarter, could you maybe just break down the overall -- the sequential change in the well performance, can you just sort of break that down into the different drivers or the different components that contributed to the better performance?

Richard Lane: Sure. I think the average lateral length, if you look at our table there in our release materials, you're seeing the average lateral length going up, and the increased rate, IP rates, 30 and 60-day rates, going up commensurate with that, so there's obvious correlation there, and then the improved completion techniques. We're doing some new things on how we perforate and the spacing appropriations, which we think is having an impact. So, I think it's all those things, Gil.

It's also, you know, hopefully we're getting smarter about this every month that we attack it. We're doing a better job, I think, on the geosciences and using the 3D seismic. That's having a nice impact for us. So, I think it's collectively all those things. Our team's doing a great job on it.

Gil Yang: Thanks for that answer. If I look at the lateral length increase, it's relatively minor compared to the volume IP increase. So is there a mix effect where you're drilling wells in better areas and fewer wells in poor areas? Is that a component as well? And so can you quantify between those different factors, how much is coming from each?

Richard Lane: I can't quantify it exactly, Gil. I'd have to have a lot of data in front of me to do that. But, it depends how far you're looking back. If you look back several quarters, I think we were, as we said, our '08 plan would be less exploratory in nature and be more in where we're more certain about what's happening and know how to best complete the wells, more in a development mode. So, I think you're seeing some of the effect of that.

Gil Yang: Okay. And just sort of the last question, follow-up, regarding that. Are you at the stage -- was the first quarter already at that full development mode stage or do you still need to transition into that development mentality more through the year?

Richard Lane: Yes, definitely. We definitely need to transition into it. And we've highlighted some areas that we would take that footprint that would be considerably bigger than the first one, that would be logical progression of that activity. And we're starting to prepare the things that have to happen before the rigs show up, to do that.

Tom Gardner: Morning, guys. Most of your drilling in the first quarter was in areas where you had 3D seismic coverage. Are there portions of your acreage that are condemned by this or that you would not drill, and in what specific ways are you using this seismic to high-grade?

Richard Lane: I wouldn't say there's -- they're not broad areas that we have condemned using the 3D seismic. It's more a section-by-section kind of look, Tom, that before we drill the wells we've got a detailed mapping where that well path is going and try to watch for faults and other complicating things. So, it's more of a high-grading well-by-well, not so much broadly across the whole play.

I will say there are some things we're doing with the seismic data that goes beyond just using the reflection data to map structure and faults and things, some other derivatives from the seismic data that we're starting to correlate with productivity. And then that's another benefit that we're starting to see. We need some more data on that to make sure that correlation holds up. And we're also probably not going to talk a lot about that as we go forward here.

Tom Gardner: I understand. And just as a follow-up to a previous question on spacing. Are you doing microseismic work or reservoir modeling, and what distance away from the lateral is that suggesting you're going to drain effectively?

Richard Lane: We are doing microseismic work. We've done several and we continue to do them. Really great tool. Sometimes the data is hard to interpret. But we think we are seeing where the fracs are going in a general sense. And the half-lengths we're seeing there are somewhere on the order of 500-feet. And again, that's not consistent to every stage or every well. But you know, it's helping us understand what's happening when we frac these wells and gives us the insight you're talking about there to how close maybe we can get.

Joe Allman: Good morning, everybody. Could you give us your plans for ramping up the rig count in the Fayetteville shale and could you also talk about ramping up the rig count elsewhere, outside the Fayetteville, and how you're thinking about that and what the constraints are?

Harold Korell: We don't have a plan to talk about other than what we have already talked about in regard to the Fayetteville. We have 19 rigs drilling there and we haven't modified that, I'd say, at this point in time. We've been focused on getting our -- keeping our helicopter balanced, I would say. Clearly we have lots of opportunities. We're building our workforce to be able to see a day when maybe we can accelerate and also keep our capital in balance and watch our balance sheet. So, we don't really have anything new to report on that.

I think we did put in the press release and Richard might have mentioned that we'll be drilling more wells in the James Lime, as part of our current plan this year. And that's primarily through shifting capital from some other project areas, not the Fayetteville, but from some other project areas into the James Lime. And as we go forward, as Greg mentioned, we're in the process here of re-looking at our year. There are quite a few moving parts right now that aren't settled enough for us to be able to tell you any more than we have, I think in our press release, which we've given you an idea of where we think we'll be in the second quarter.

We have pending, the sale of the acreage in the Fayetteville shale, which is moving in a closing direction. We still have pending the closing of the utility, which is moving in a closing direction. And we have thus far sold in a verbal auction, some of our Permian Basin properties and are moving through a sale process for the bigger part of that. So, we need to get clearly through those and then we can look at overall impacts on production, cash flow, where we would stand debt wise, and sometime later this year we'll talk about that with you. But, we can't do it until we're done.

Joe Allman: Thanks, that's helpful. And then the follow-up is, what are you seeing in the Fayetteville and outside the Fayetteville, in terms of the most recent trends for drilling and completion costs and just all service costs?

Harold Korell: You mean overall cost factors?

Joe Allman: Yes.

Richard Lane: Well, you saw the average for the quarter of $2.9 million. A lot of moving parts there, Joe. We have efficiencies going on and how quick it takes us to drill the wells. And you know, we talk about this reentry to reentry time, it's kind of a key time and as you know, maybe everybody doesn't know, we talk about that time, because we're using these spudder rigs. So, that's the date we're keeping track of there. But we're doing better there, so that's affecting it positively.

On generally and service costs, the big items would be the drilling and the pumping services and you know how we're positioned on the drilling side, by virtue of operating our own rigs. And that margin is still holding up nicely for us, to saving net to SWN. And we're seeing still good discounts on the pumping service side of things for cementing and stimulating and all that. Some pressure on steel costs, it looks like, upward this year, that will offset some of that. So, those are the main factors.

David Heikkinen:  Just one question in the Fayetteville around percentage of your acreage that you think will be developed over time, what are you thinking there now?

Harold Korell:  Well, I don't think we have gotten to that number.

David Heikkinen:  How much have you appraised, maybe is another way to describe it, if you drew a circle around where you've drilled, what percentage of acreage have you drilled the wells around?

Harold Korell:  Well, it's hard, it depends on how big you draw the circle, David.  We're not trying to avoid the question.  I don't think I know how to answer the question.  Probably still the best reference is to look at our map in our IR book that shows where the acreage is, and it's all within that brown, and you can see where we've drilled the pilots, and we continue to drill more pilots and fill-in.  And then people -- other companies are drilling intensely far over to the east, which was our last part of the buy area for us, actually, initially, and then some are drilling north of our acreage.  So it just depends I guess on how big a circle you draw around each pilot.

David Heikkinen:  Okay.  Thinking about the outside operated rigs, well count, how many wells do you think you participate in further to the east and further to the north that will be -- or even in your core that will be outside operated now, Harold?

Harold Korell:  Well, boy, I don't know how to answer it.  Richard, do you have any--?  With the sale of the property over to the southeast to XTO, you know, some of that's going, some of our outside operated will be going away because some of that acreage is operated by Chesapeake, and then Petrohawk has expanded its position.  Do you have any idea?   I don't.

Richard Lane:  That is affecting the overall count of non-op wells.  It's a good point, Harold, because we were getting a lot of the proposals out of that area.  But I think we're, you know, we're going to be somewhere probably between, somewhere around a 75, if I had to guess, 75 wells that we would have for non-operated.  Everybody doesn't give us their full-year plan, and so we're--

Harold Korell:  And when they do, it changes, so it depends on how aggressive some of the companies are going to be in there, and they seem to be gearing up.

David Heikkinen:  Yes, very -- we're seeing that increase across the other operators.  And then access to things, like sand and water, overall services access, as you're expanding your development area, can you talk some about that?  And that's my last question.

Harold Korell:  Yes, we're -- I feel real comfortable where we are there, David, at this level of activity and at higher level activities.  The resources seem to be there to do what we need to do.  Water wise we're -- we almost have too much water.  Right now, we've had a real rainy season, up there in the Arkoma Basin, and so from a standpoint of retention ponds and other types of water sources, we're kind of overflowing there, which is a good thing.  It's made it hard to get around and operate for, you know, wet conditions, but we have our water team dedicated to that, that we've talked about, and they're doing a great job on that and staying ahead of our needs there on the completed wells.  So we're in good shape there.  We don't see any lags in propant to complete our wells, and looking at some new things there that maybe could help save on costs there, so we're in good shape there.  And the overall service industry is building around the play and causing, frankly, causing more competition and better pricing.

David Heikkinen:  Just one final question.  Greg, on your second quarter guidance that includes the expected sale already, just to confirm that?

Greg Kerley:  The guidance that we have in the second quarter, yes, it does.

Jeff Hayden:  Well, most of my Fayetteville questions have been hit already.  So I guess jumping quickly to the Marcellus.  You guys have been adding more acreage.  You know, just wondering if you could give us any color on what you're having to pay out there as far as leased bonuses, you know, what kind of royalty you have to give?  And what are your plans for drilling a horizontal well?

Harold Korell:  Well, we won't give you guidance on our -- what we're paying in royalties.  And we're just at the early stages of drilling vertical wells now, and sampling the rock, and doing that kind of -- that physical work and all the assessment that we would want to do.  So not a lot of help to you, or not a lot of new information there, because we're just in the throes of doing those vertical wells.

Scott Hanold:  Thanks.  Hey, just jumping to east Texas, really quickly, I think you all said you had like 95,000 acres in the Angelina trend, could you tell me is that all perspective for James Lime, and if you could also draw some conclusions based on what you know now, what you think sort of spacing is, well cost is, and potential recoveries of some of those wells you all are drilling out there?

Harold Korell:  Well, Scott, I would say the acreage is all potential, which is real encouraging.  We certainly haven't sampled it densely.  We have drilled wells across a pretty far area, from east to west, so it is definitely all perspective, and we're trying to understand what drives some of the rates we're seeing.  We're seeing variable rates there.  

You know, the spacing is up in the air.  We're drilling -- maybe to guide you a little bit, I would say we're drilling longer laterals there.  We're drilling most wells somewhere in the 5,000 foot lateral length.  So we're starting with a little bigger footprint there, it's maybe something kind of nominally around a 160-acre kind of thing.  But we'll have to see as we go how the wells perform and what that ultimate drainage is, but we're real encouraged so far.

Scott Hanold:  What are some of the [AFEs] in the wells you've drilled today?

Harold Korell:  Oh, they're high 3s to $4 million.

Mike Scialla:  Wondering with the improved costs you're seeing in the Fayetteville, are you seeing any improvements in the number of wells?  You've had some mechanical difficulties with some wells, are you seeing the improvements there in terms of the percentage of wells that you're running into problems?

Richard Lane:  Yes, definitely, definitely, Mike.  We're -- I think some of the, you know, our good drilling practices that we've established are helping there.  I think the 3-D seismic is helping there.  But I can't give you an absolute number, but I do know weekly when we look through all the activity, that the number of problem wells and wells needing to be sidetracked is dropping off, and that's helping for sure.

Mike Scialla:  Great.  And any update on the severance tax situation in Arkansas?

Harold Korell:  Yes, it is a law.  It is resolved, and it's been signed by the Governor, and rather than me repeat the terms of it, probably just, Mike, you can go out and get that.  But I think a reasonably good outcome for us and for the industry, and it will still keep the activity moving along.  And all that begins I think in January of '09.  

But we were able to get a reasonable rate with exemptions.  Basically, the rate on the first three years for wells drilled in the Fayetteville will be 1.5%, and then if you've got a bad well that hasn't paid out after that period you can apply for an extension of a year, and then there's a 5% severance tax rate after that time and it's on a per well basis.  And then late in the life of the wells when the production rates drop down I think below 100 Mcf a day then the rate goes to 1.25% or something like that.  So I think a reasonable outcome to all of that.

Mike Scialla:  Great.  And one quick one on the Marcellus, can you comment at all about any industry activity and anything going on around your acreage by other operators?

Richard Lane:  Yes, we're seeing a lot more permits, Mike.  There's some public data, talking about rates starting to emerge from horizontal wells that are pretty encouraging, and pretty close to us.  We're seeing some horizontal wells being drilled.  So that the answers are coming quicker now with the State.  In Pennsylvania the way the rules work there's not a lot of reporting there that has to happen, so that's a challenge.  But definitely the activity has picked up.  There are some publicly reported rates that are encouraging on horizontal wells, and permits in and around, where we're active.

David Heikkinen:  Richard, just thinking about the areas where you have 3-D seismic coverage, how much of the acreage would you exclude for faults or karsts where you wouldn't want to drill?

Richard Lane:  Well, we don't have -- the karsting terminology kind of I think that you're referring to is grown out of some of the challenges in the Fort Worth Basin and where they have karsted carbonates underlying their objective that are water bearing.  We don't have that anywhere that we've drilled and don't expect to have that, so it's, you know, it's a much more minor problem and really unit specific.  Where if we have faults it doesn't mean we can't drill the well, we maybe place it in a little different spot.  So I know I'm not helping you with some kind of a percentage there, Dave, but I just--

David Heikkinen:  Yes, you know, where -- I'm just trying to think through risk factors in the play where you've been --

Richard Lane:  Yes.

David Heikkinen:  -- and what it sounds like, surface access from paths, directional access.  You've been playing around a lot of things, is what I'm hearing.

Richard Lane:  Right, right.  You know, I would say this, there'll be wells we don't want to drill in the play because of geologic reasons, but really when you look at it right now, it's providing us a tool to drill the best ones first.

David Heikkinen:  Yes.

Richard Lane:  So we're pushing those out.

Joe Allman:  Yes, thanks, again.  Harold, can you talk -- you know, people was a constraint, not having enough people was a constraint previously.  Could you characterize where that constraint is for you folks, now?

Harold Korell:  Well, I would say this, if you just took and said what's the overall package of wells we have to drill as a Company, say how do you create the most net asset value?  We've got thousands of wells to drill in the Fayetteville Shale, so something is holding us up.  And for the most part I would say that it would be people to accelerate the drilling activity, and we're continuing to hire new people, we're continuing to recruit people.  Our organization is more settled, I would say, than it was a year ago for sure, when we had reorganized and shuffled everybody around.  

So I think that our -- even with the same number of people we're able to accomplish more drilling and completion and more analysis of what we're, you know, basically what we're operating, is telling us.  So we're moving up that curve, and there will be some point in time where I would say we'll be prepared to go faster.  And by faster I mean drill more wells, put more rigs out there.  You know, if we're able to drill, we're getting some benefit now out of taking less days to drill an individual well, which automatically should move us in the direction of drilling more wells, but then there'll probably be some point where we want to put more drilling rigs out here, and we just have to keep that all balanced, the people and the capital, and the takeaway capacity, and all of those things that go into it, and services.  

But I would still say as far as keeping our helicopter going up and to the right, people is a constraint.  It's not one that's a constraint just for us, it is entirely across the industry, and we're all hammering away at each other.  And there comes a point where it's hard to -- I'd like to see some more M&A happen, that's always when there are people available, when somebody disappears.  Unfortunately, where prices are, it's less likely to see, in my view, combinations, other than special cases, so.

Joe Allman:  And then, lastly, could you talk about any prospectivity on your acreage for the Haynesville Shale?

Harold Korell:  I can't really talk about it.

Richard Lane:  It's present in those counties where we're active, Joe, and we're just starting to look at that, but can't give you a lot of color on it just yet, but the interval is definitely present there.

Operator:  And, at this time, we have no further questions.  I'd like to turn it back over to Management for any additional or closing remarks.

Harold Korell:  Okay.  Well, thanks, all of you, for joining us today.  We're excited and proud of the results we've had in this quarter, quite frankly.  I think it shows that the focus we have on present value creation and getting the most that we can per dollar we invest is working and that our teams of people, and some of them would be listening on the phone today.  

It feels good for those of us here sitting at the table but I want our employees to know and our people to know that clearly the efforts that they've been making over the past couple of years are starting to show here in the results, and as we're making improvements, particularly in the Fayetteville, and some of the other things we're doing, as well, in east Texas and in our conventional Arkoma Basin, which are less romantic but nonetheless adding volumes and reserves to our base level of performance.  

So thank all of you for being there.  We look forward to the rest of the year.  We'll have some exciting things, I'm sure, to share as we move on through '08.

(1) Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance 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. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. The table below reconciles net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.

	3 Months Ended March 31,
	2008		2007
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	283,717	$	142,403
Add back (deduct):
Change in operating assets and liabilities		13,370		(13,992)
Net cash provided by operating activities	$	297,087	$	128,411