西南能源 (SWN) 2008 Q1 法說會逐字稿

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.

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'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statement 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 have 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. 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, yhen to Greg for an update on our financial results, then we will answer questions.

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 convention 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 re-entry to re-entry. 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 was 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 drills at 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 a 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.

In some new ventures activity, in Pennsylvania, we currently have approximately 100,000 net undeveloped acres where we believe the Marcellus Shale is prospective. We are currently analyzing core on first vertical well here and drilling our second. In our conventional Arkoma activities in the first quarter, we invested approximately $36 million. We have participated in drilling 26 wells here including 15 at our Ranger Anticline field and five 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 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. 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'll now turn it over to Mr. Kerley who will discuss our financial results.

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 per share, more than double the prior year period. Our operating cash flow also increased significantly to $283.7 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 in MCF. Our leased operating expenses per 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 Fayetteville Shale play which has higher per unit operating cost than our other focus areas.

General and administrative expenses per unit of production were $0.42 per MCF in the first quarter, down from $.047 cents last year. While the decrease is primarily due to the effects of our increased production volumes which more than offset increased payroll and related costs associated with 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 mid-stream 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 for 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 have 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 utilities 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 a 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. 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. Now we will turn back to the operator who will explain the procedure for asking questions.

Thank you. The question and answer session will be conduct electronically. (OPERATOR INSTRUCTIONS) And we will take our first question with Brian Singer with Goldman Sachs, please go ahead sir.

Thank you, good morning.

Morning.

Could you talk a little bit more about the Southeast Rainbow pilot with the rates you have seen and the costs having come down to about $2.6 million, where do you think you are in that process, what are your expectations for 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?

Well, Brian, we're really encouraged by what we're seeing there. I think you can tell by the number 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 cost 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 encouraging. We will 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.

Do you see further potential for cost decreases or do you think $2.6 million is a good number going forward.

Well, 2.6 is specific to that area, which was my first point, so I wouldn't carry that across the entire play. I think the net difference we're seeing is probably the repeatable -- hopefully the repeatable savings. So --

Two things, Brian, that affect that, maybe more clearly stated is that where we are drilling -- where the play is deeper, 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. So 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. It's a very broad area we're drilling across and I don't think it's possible for us to say exactly what those costs parameters are going to be across the whole thing.

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 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.

Thank you.

Thank you. We will take our next question with Scott Hanold with RBC Capital Markets, please go ahead.

Thanks, good morning.

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 any constraints in the system we need to be aware of and what's sort of the update on the Boardwalk pipeline from your perspective?

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 year, which would take us over to the east part of the -- still the current markets that we service now, but just increase capacity there. And as far as constraints right now, I mean we're building gathering line and adding compression to keep up with the field activities. So we don't see any -- there's no delays in pipe orders or delays in compression being received or anything like that at this point.

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.

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

Appreciate it, thank you.

We will take our next question with Amir Arif with FBR Capital Markets, please go ahead.

Morning guys. Just a question also on the multi-well pad drilling that you're doing. You talked about cost and saving synergies, can you talk a bit more about the better rates you're getting out of these wells, and whether that's due to lateral lines or is it due to better optimization of the fracs, what do you think is driving that?

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, and so we have an average lateral length that's a little higher, then we have the benefit of our newest thinking on completions. So I think it's both of those things.

From the beginning of this play, we have talked about the name of the game being to get in touch with 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 frac treatment that you can, which can mean a lot of technical things. Some of which we believe we're getting some additional breakthroughs in in regard to the completion itself. Of course, longer laterals and then work towards continuing to decrease the cost. As Richard 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.

That sounds good. Just to follow up, in terms of the spacing down to about a hundred acres, are you seeing any kind of communication or do you feel that you can even take that spacing lower?

I think it's -- 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 will end up and the well results confirm that so far.

A final follow up question, just on the lateral length, how far do you want to push those lengths in terms of the formation you have and the rig capacities you have.

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

Sounds great, congratulations on the good results.

Thanks.

And we will take our next question with with Gil Yang with Citi. Please go ahead.

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?

Sure. I think -- the average lateral length, if you look at our table there in the -- 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. Then the improved completion techniques, we're doing some new things on how we perforate and the spacing of perforations which we think is having an impact. So I think it's all those things Gil, it's also -- hopefully we're getting smarter about this every month that we attack it. We're doing better job, I think, on the geosciences and using the 3-D 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.

Thanks for that answer, but 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?

I can't quantify it exactly Gil. I 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 are -- 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.

Okay. Just sort of the last question 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?

Definitely, we definitely need to transition into it. We have 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.

All right, thanks a lot.

You're welcome.

And we will take our next question with Tom Gardner with Simmons and Company, please go ahead.

Morning guys.

Hi Tom.

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

I wouldn't say there's -- they're not broad areas that we have condemned using the 3-D seismic, it's more a section by section kind of look, Tom, that before we drill the wells we have got a detailed mapping where that well path is going and trying 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's some things we're doing with the seismic data that goes beyond just using the reflection data to map structure, 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. We're also probably not going to talk a lot about that as we go forward here.

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

We are doing micro seismic work. We have done several and we continue to do them. Really great tool, sometimes the data's hard to interpret, but we are seeing -- 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, it's not consistent to every stage or every well, but 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.

Great, thanks guys.

We will take our next question with Joe Allman with J.P. Morgan, please go ahead.

Thank you, good morning everybody.

Hi Joe.

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, how you're thinking about that and what the constraints are?

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. Let's say at this point in time, we have been focused on getting our -- keeping our helicopter balanced, I would say, with -- clearly, we have lots of opportunities, we're building our work force to be able to see a day when maybe we can accelerate, 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, Joe and Richard might have mentioned that we're drilling -- we will 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 relooking 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 have given you an idea where we think we will be in the second quarter.

We have pending the sale of the acreage in the Fayetteville Shale, which is moving in the 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 will talk about that with you. But we can't do it until we're done.

Got you, that's helpful. 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?

Oh, you mean overall cost factors.

Yes.

Richard, do you want to --

Well, the -- 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. We talk about this re-entry to re-entry time, it's kind of a key time. As you know, maybe everybody doesn't know, we talk about that time because we're using the sputter rig. 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 in service costs, the big items would be the drilling and the pumping services. You know how we're positioned on the drilling side by virtue of operating our own rigs, and that margin's still holding up nicely for us for saving net to [swim]. 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.

Got you, okay, very helpful, thank you.

We will take our next question with David Heikkinen with Tudor, Pickering, Holt, please go ahead.

Good morning.

Morning.

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?

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

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 around?

Well, it's hard, it depends on how big you draw the circle, David. I'm 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. You can see where we drilled the pilots and we continue to drill more pilots and fill in. 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. Then some are drilling north of our acreage. So it just depends I guess on how big a circle you draw around each pilot.

Thinking about the outside operated rig well count, how many wells do you think you participate in further to the east and further north or even in your core that will be outside operated now, Harold?

I don't know how to answer, Richard, do you -- With the sale of property over to the southeast XTO, 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.

That is affecting the overall count of non-op wells, that's a good point, Harold, because we were getting a lot of the proposals out of that area. But I think we're going to be somewhere, probably between -- somewhere around 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 --

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.

Yes, very. We're seeing that increase across the other operators. Then access to things like sand and water, overall services access as you're expanding your development area, can you talk some about that? That's my last question.

Yes, 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 have 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 wet conditions, but we have our water team dedicated to that, we have 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 profit 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.

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

The guidance we have in the second quarter, yes, it does.

Okay, thanks, that was it.

(OPERATOR INSTRUCTIONS) We will take our next question with Jeff Hayden with Pritchard Capital, please go ahead.

Thanks, morning guys.

Morning.

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

Well, we won't give you guidance on 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 physical work and all the assessment that we would want to do. So not a lot of help to you or not a lot more new information there, because we're just in the throes of doing those vertical wells.

Okay, thanks guys.

Yes.

(OPERATOR INSTRUCTIONS) We will take a follow up with Scott Hanold with RBC Capital Markets, please go ahead.

Thanks. Jumping to East Texas really quickly, I think you all said you had like 95,000 acres in the Angelina trend. Can 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 recovery of some of those wells you all are drilling out there.

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 prospective and we're trying to understand what drives some of the rates we're seeing, we're seeing variable rates there. 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, maybe something kind of nominally around 160 acre kind of thing. But we will have to see as we go how the wells perform and what that ultimate drainage is, but we're real encouraged so far.

What are some of the AFEs on the wells you have drilled to date?

They're high threes to $4 million.

Okay, thanks.

And we will take our next question with Mike Scialla with Thomas Weisel Partners, Please go ahead.

Hi guys.

Hi Mike.

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 improvements there in terms of the percentage of wells that you're running into problems?

Yes, definitely, definitely Mike. We're -- I think some of the -- our good drilling practices that we have 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.

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

Yes, it is 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 reasonably good outcome for us and for the industry and it will still keep the activity moving along. And all that begins, I think, 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. 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 that.

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

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's picked up. There are some publicly reported rates that are encouraging on horizontal wells and permits in and around where we're active.

Okay, thank you.

We will take a follow up question with David Heikkinen, please go ahead.

Richard, just thinking about the areas where you have 3-D seismic coverage, how much of the acreage would you exclude for faults or you [carts] where you wouldn't want to drill.

Well, we don't have the karsting terminology kind of I think that you're referring to has 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 have drilled and don't expect to have that. So 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 --

You know where I'm going. I'm just trying to think through risk factors in the play where you've been and what it sounds like, surface access from pads, directional access, you can plan around a lot of things.

Right, right. I would say this, there will 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. So we're pushing those out.

Thanks guys, I appreciate it.

We will take a follow up with Joe Allman, with J.P. Morgan, please go ahead sir.

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

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, I'd say how do you create the most net asset value, we have thousands of wells to drill in the Fayetteville Shale. So if something's 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, 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 -- 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 will be prepared to go faster. By faster, I mean drill more wells, put more rigs out there. 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 will probably be some point where we want to put more drilling rigs out here. We just have to keep that all balanced, the people and the capital, and the take-away capacity and all those things that go into it, 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.

Lastly, could you talk about any prospectivity under your acreage for the Haynesville Shale?

I can't really talk about it.

It's present in those counties where we're active, Joe. And we 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.

Okay, very helpful, thank you.

And at this time we have no further questions. I would like it turn it back over to management for any additional or closing remarks.

Okay. Well, thank all of you for joining us today. We're excited and proud of the results we have 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, 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 have 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 will have some exciting things, I'm sure, to share as we move on through '08.

Once again ladies and gentlemen, this will conclude today's conference. We thank you for your participation. You may now disconnect.