西南能源 (SWN) 2008 Q3 法說會逐字稿

Good day. Welcome to the Southwestern Energy Company third quarter earnings teleconference. At this time, I'd like to turn the conference over to the Chairman and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Good morning. Thank you for joining us. With me today are Steve Mueller, President of Southwestern Energy, and Greg Kerley, our Chief Financial Officer. 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 many of the comments during this conference call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are forward-looking statements sections of our annual and quarterly filings with the SEC. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To begin with again, Southwestern Energy has had a great quarter. Our financial results are outstanding and in our Fayetteville Shale play we continue to see significant improvements in well performance as we implement new completion techniques across the play. As a result, gross operated daily production volumes had risen to approximately 600 million cubic feet per day at September 30 up from about 260 million cubic feet per day a year ago. Adjusting for our improved performance, we have now moved our full year production guidance to a range of 190 to 192 Bcfe for 2008 which is an increase of approximately 68% compared to last year.

I am also very pleased to report that our financial position and balance sheet are both in great shape. We had over $425 million of cash and cash equivalents on hand at the end of the quarter, reduced our debt to total capitalization ratio down to 25% and our $1 billion unsecured credit facility was completely undrawn. While we understand that these are uncertain times in our economy we believe that Southwestern Energy, with our low cost operations and the financial strength and flexibility to pursue highly accretive drilling programs, is well positioned to add significant value for our shareholders. I would now like to turn the teleconference over to Steve for me details on our ENP and midstream activities and then to Greg Kerley for an update on our financial results, and then we will take questions.

Thank you, Harold. Good morning. During the third quarter of 2008 we produced 52.8 Bcf up 76% from third quarter of 2007. Our Fayetteville Shale production was 37.2 Bcf up significantly from the 14.7 we produced in the third quarter of 2007. We produced 8.1 Bcf from east Texas and 6.8 Bcf from our conventional Arkoma properties. We produced another seven-tenths of a Bcf from Permian and Gulf Coast assets prior to the closing on the sale of nearly all the properties there.

As a result of our continued strong production performance, we now estimate that our fourth quarter production will range between 53 and 55 Bcf and our full-year 2008 production will range from 190 to 192 Bcfe. We are expecting flat to 4% production growth between the third and fourth quarters of 2008 mainly due to the restrictions associated with the delayed completion of the board walk pipeline in our Fayetteville Shale. I will be discussing this in more detail later.

In first nine months of 2008 we invested approximately $1.2 billion in our exploration and production activities and participating in drilling 580 wells. Of this amount, approximately $954 million, or 83%, was for drilling wells. Additionally, we invested $134 million in our midstream segment almost entirely on the Fayetteville Shale.

Now let's talk about the Fayetteville shell development, in the first nine months of 2008, we invested approximately $1 billion in our Fayetteville Shale play, including both our ENP and midstream activities. At September 30 our gross operated production rate reached another milestone of approximately 600 million cubic feet per day. We are currently experiencing restrictions related to the Fayetteville Shale production as a result of the delayed completion of the boardwalk pipeline. Due to construction difficulties, including hard rock formation on one major boar, the Phase I completion date that was originally anticipated to be at the beginning of fourth quarter of 2008 is now scheduled for late in the fourth quarter. As a result, we have delayed placing some of our wells on production and delayed completing some wells until this take away issue is revolved.

During the third quarter of 2008, our typical well had an average completed well cost of $3 million, average lateral length of 3,736 feet and an average drill time of 12 days from a reentry to reentry. This compares to an average time of 14 days to drill and 3500 -- just over 3500 foot lateral last quarter. Additionally, we continue to improve our completion practices with our wells completed averaging higher initial 30th and 60th day production rates ranging from 13% to 16% above our results in the second quarter.

During the first three quarters of 2008, we continued testing closer perforation cluster spacing in our horizontal wells with very positive results. We have now tested this technique in 132 of our wells and seen a significant improvement in early production. We estimate that the ultimate recovery on these wells is improved by 20% to 25% and we are currently planning to utilize this technique in all wells we plan to drill for the remainder of the year and in to 2009. Associated with this completion technique and longer laterals, we now except completed well costs to average approximately $3.1 million per well for the fourth quarter.

As a result of the continued performance of our Fayetteville Shale well, we signed a precedent agreement with the Fayetteville Express Pipeline on September 30 to further expand the further takeaway capacity from an area starting in late 2010 or early 2011. Fayetteville Express Pipeline is a joint venture of Kinder Morgan and Energy Transfer.

Now let's talk about some of the other areas. In Pennsylvania we currently have approximately 110,000 net acres where we believe the Marcellus Shale is perspective. We have drilled our first three wells, vertical wells in Bradford and Susquehanna County located in northeast part of the common well. Two of these wells were completed and tested in third quarter with encouraging results. One vertical well is waiting on completion. We rent recently finished drilling our first horizontal well which we expect to complete in the fourth quarter.

In the first nine months of 2008, we invested approximately $104 million in our conventional Arkoma basin property. We participated in drilling 61 wells here, including 21wells that are (inaudible) field and 9 wells at our midway field. Our production from the conventional Arkoma for the first nine months of 2008 was 18.6 Bcf compared to 17.8 Bcf the first nine months of 2007. In the first nine months of 2008, we invested approximately $122 million in east Texas, where we participating in 35 wells, 14 of which were James Lime horizontal wells. Production from east Texas was 24.1 Bcf in the first nine months of 2008, up from 22.7 in 2007.

As we previously announced we assigned a 50/50 joint venture with a private company to drill two wells targeting the Haynesville interval of the Bossier Shale in Shelby and St. Augustine County Texas. The first vertical well is drilling and is expected to reach total depth by the end of the first quarter. In summary, we continue to have outstanding results in our midstream businesses and expect continued results in the remainder of 2008 and well into 2009. I will now turn it over to Greg Kerley who will discuss our financial results.

Thank you, Steve. Good morning. As Harold indicated, our financial results for the quarter were outstanding. We had record earnings of $218 million or $0.63 per share, which was over four types our earnings for the same period last year. Our record results were driven by the significant growth in our production volumes and by higher realized natural gas prices.

Our third quarter results included an after tax gain of $35.5 million or $0.10 a share from the July 1 sale of our utility. Our operating cash flow also increased significantly to $312 million, double the prior year period. In the third quarter of 2008, operating income for our EMP segment was $280.6 million, up over threefold from the prior year period. We produced 52.8 Bcf in the quarter, a 76% increase from a year ago, and realized an average gas price of $8.56 MCF up 29% from the prior year period.

Our lease operating expenses for unit production were $0.96 in MCF equivalent in the quarter up from $0.67 a year ago. The higher per unit costs were driven by primarily by our gathering and compression costs in the Fayetteville Shale play, including the impact of higher natural gas prices on the costs of compression fuel. We expect our lease operating expenses to average between $0.92 and $0.97 per MCF in the fourth quarter.

General and administrative expenses per unit of production were $0.33 per MCF in the third quarter down from $0.46 last year. The decrease was primarily due to the effects of our increased production volumes which more than offset increased incentive compensation, payroll and related costs primarily associated with the expansion of our ENP operations. We expect our unit G&A costs to average between $0.32 and $0.37 in the fourth quarter.

Taxes other than income taxes were $0.15 per MCF in the quarter compared to $0.11 in the prior year period due changes in the mix of our production volumes. Our full costs pool amortization rate average $1.86 per MCF in the third quarter down from $2.56 a year ago. The decline in the average amortization rate was primarily the result of our sales of oil and gas properties in the second and think quarter of 2008, the proceeds of which were credited to the full cost pool. Operating income from our midstream services segment was $18.3 million during the quarter, up from $4.1 million 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.

At September 30 we were gathering about 675 million cubic feet of gas a day in the Fayetteville Shale play area through approximately 793 miles of gathering line. Effective with the sale of our utility on July 1, we are no longer engaged in natural gas distribution operations. We received $223.5 million for the utility after post closing adjustments and expenses, and in order to receive regulatory approval for the sale and certain related transactions, paid $9.8 million to the utility for the benefit of its customers. We recorded a pretax gain on the sale of the utility of $57.3 million in the third quarter.

By the end of the third quarter we closed on all but $21 million of our planned 2008 divestitures which were result in total gross proceeds of approximately $1 billion. As a result of the tax gains realized from our EMP asset sales and the sale of our utility, we recorded a current tax provision of approximately $107 million, all of which is related to alternative minimum tax. As a result of the turmoil in the financial and credit markets that is occurred over the past few weeks, liquidity has become a major concern of many companies. I am pleased to report that Southwestern Energy is in great shape.

Over the past several months we have dramatically improved our financial flexibility and strengthened our balance sheet. We had $426 million of cash and cash equivalents at the end of the third quarter and our $1 billion unsecured credit facility remains completely undrawn. Our strong financial results along with our asset sales combined to lower our debt to total capital percentage to 25% at the end of the quarter down from 37% at year end, 2007 and our net debt at September 30 was 12%.

We have a strong banking group and believe that our long term relationships will weather the current downturn and benefit us for years to come. In our commodity hedging program we have not incurred any counterparty losses and believe that the counterparties to our current hedging contracts remain solid. Overall we are very pleased with our performance to date and our finance usual position. We are in great shape as we head into 2009 with one of the strongest balance sheets in our history. That concludes my comments. Now we will turn it back to the operator who will explain the procedure for asking questions.

Thank you. (OPERATOR INSTRUCTIONS). We will take our first question from Scott Hanold, RBC Capital Markets.

Good morning.

Morning.

Can you talk about the 60-acre down spacing? How do you think about this? Obviously you won't go into this you are pretty early, so your long-term development strategy isn't, I guess for lack of a better term isn't compromised. Can you kind of give us a sense of how you are approaching this to the 60 acres and what sort of adjustments you are making in case you think 40 acres is the right number?

Scott. This is Steve. What we are doing is really we have targeted somewhere between 150 and 200 wells that will have some kind of down spacing consideration with them. First pass is basically splitting what we did in some of our pilot areas which is roughly that 60 acres. Part of that 60 acres will be drilling between wells we have drilled in the past also so we can see what happens between older producing wells as compared to just drilling them straight up new. And then, we will continue to, the down spacing until we run into a situation where we are comfortable that we figured out what the right spacing is. So we just keep working it down from there, but it is a couple hundred wells worth which is between four is six months of drilling, and then to get production you are probably looking this time next year between really results that we can say here is what it looks like to right spacing for certain areas.

Okay. At 60 acres and/or even if you were to think in terms of 40 acres at this time, is there any major change in the way you drill your patterns right now?

Not significant change. 60 acres would just be split whack we did in our pilot area. We were roughly 110 acres in the pilot area.

Okay. Okay. Got it. And as my follow-up question maybe for Greg, when you look at our cash position, obviously it is, over 400 million, very strong at this point.

You do, you did have to for I guess accounting purposes book the provision for the AMT. When that gets paid out would that be an early '09 event and would that be a reduction to cash or is that already accounted for in your current cash position? There's about half of it, Scott, that is already paid, and the balance will be paid in the fourth quarter and then in in part over the year as we get into the beginning of 2009.

Okay. Got it. Appreciate it. Thanks.

We will take our next question from Amir Arif at Friedman Billings.

Good morning, guys. Just wondering, I know you haven't given your '09 guidance and you won't be doing that until late December or so, but how you are thinking of spending relative to your cash flow and in terms of acreage expiring coming up, how things are shaping up when you look at '09?

As you noted, in your question we are still building our plan for 2009 and I would say with the backdrop of everything that is going on in the economy and the world, we will be maintaining our options open as we move right up to that time period. I guess the, kind of the way we are been talking about it internally is what -- keeping your options open is smart, and you know, the analogy I have been using internally is a little like driving on the freeway and following the car in front of you. If you follow one far length behind and that car stops you are darn near almost certain to hit it. If you follow five car lengths behind, you are going to get tired of people getting if front of you. Maybe we want to be three or four car lengths behind. Just keep our options open. We have a lot of flexibility in how we do what we are doing going forward. Good thing is we are well suited to take advantage of opportunities. But, I guess the answer for right now is we are not at a point to put out our 2009 plan.

Okay. Sounds good. Thanks, Harold.

Our next question comes from Brian Singer Goldman Sachs.

Thank you. Good morning. Just following up in term of the flexibility l of our balance sheet, do you see opportunities for acreage or property acquisitions either in Fayetteville or in some of your other core areas that you may want to expand and is that something that you might look to do to the extent that asset financed values remain distressed and depressed?

We want to keep all of our, it is kind of right to the prior question, we want to keep all of our options open, and keep our eyes open. Fortunately, we did some of the things we did earlier this year not because we knew things were going to go bad in the financial markets but because we thought they were fundamentally the right things to do and selling the utility and exiting our positions in the Gulf Coast and [Fermia], and really so we can have people available to do more what we should be doing in east Texas and Fayetteville and then finally testing the market with a piece of our acreage in the Fayetteville Shale. And there's no doubt right now as we look around we see companies that aren't as well prepared for the times we are in as we are. And those projects or those things if they were things we became interested in would, we would have to lay them along side of the other things we have to do and match them up with our capability to fund them and then make decisions on an individual basis.

Great. Thanks. Big question on the (audio cut out), we have seen a continuous improvement in 30 day, 60 day average rates over the last year partly because of the longer laterals, partly because of technology know how and moving up the learning curve. Can you just comment where you feel you are on that learning you to the extent to which you expect to continue to use longer and longer laterals and see improving initial production rates? Where are we on that scale?

Well, each area has is a little different on the scale. I will hit the topside. As far as longer laterals, there is some practical length where you are not going to drill any longer lateral and the shallower parts of our play, you are probably not going to get much more than 4,000, 4500. As you get deeper towards the middle you can get some longer laterals but we haven't reached it yet and that's part of what we are testing and the rock will tell us that. You will get to a point where you just can't drill effectively and we will know what that lateral length is. As far as the completion techniques go, in the last nine months we have gone from basically putting 1 to 2 million pounds of sand and about 1 million to 2 million gallons of water in a single well to some of these ones with longer laterals over 4 million pounds to date. We are still getting incrementally very good results.

We can continue to put more energy in and continue to decrease our intervals between our perforations and that will just continue going on. Since we haven't seen any kind of break over or any kind of slow down there, I can't tell you what the end is. Again, there's some practical point but I don't know where that one is at.

On the day drill wells you saw we took another couple of days out or almost two days out from the second quarter. We think there that once we are on pad doing full development that we can average somewhere around 10 or maybe a little below 10 days a well but we have to get the full development stage. That's down the road a ways.

Great. Thanks. Any constrains to you're seeing in terms of the ability to procure (inaudible)

We are not seeing at all and our sand is not a very difficult sand to have overall. We know it is not coated, it's not high string (inaudible). There hasn't been an issue that direction. But because we have got so much sand, we have actually purchased our own sand mine and towards the middle of next year, second quarter some time we will have that up and running and we will be supplying about 70% of our own sand.

Great. Thank you.

We will take our next question from David Heikkinen at Tudor Pickering & Holt.

Good morning. Greg, just had a question. Current hedge position and basis hedges and rolling into 2009 as well, any update to your hedging?

Just what we had in the press release this morning. We have about 11.5 Bcf commodity price hedged at 838 NYMEX and 17 Bcf with a collar of about I think it is [4 or 7 and 76] ceiling of about 1070 and about 43 Bcf of basis protected for production that is basically protected at an average of about $0.92 to a dollar.

Maybe I was, I didn't phrase that very well. Thinking about what would be the floor price given where gas prices are now where do you want to layer in more hedges for more protection or what is your target for percent hedge as we roll into '09 and then 2010? That's what I meant to say.

Well, we historically would like to be around 50% or so hedged as we enter a year at least. And we are, we have got about 135 Bcf of production hedged right now. So, we are in pretty good shape right now but, again, we are looking for opportunities to hedge and we get some cooler weather as we get into the winter months and November and December we will take advantage of that.

I think it is just adding to that, Greg, it would be fair to say that at prices where we are right now, we probably are not encouraged to and haven't done recently more hedging.

Yes. And thinking about now operationally, Steve, and you have talked about drilling on pads and some of the site specific rigs, you are still thinking about drilling four 4500-foot laterals in that overall pattern? Is that a general thought of long-term development or do you think you go across lease lines over time?

Well, that goes back to kind of the state rules. Right now the state rules you are supposed to have 500-foot offsets between wells and off your lease lines as well. As you go to that down spacing you have to get exceptions. Right now we are getting those exceptions fairly easily. So we have drilled some wells actually over 5,000-foot laterals already. When you get to the full development stage, again, I don't know exactly what those lengths are going be. That's just part of our learning curve.

Yes, but the exceptions are case by case still.

They're still case by case. There's no change in field rules and probably the only change has been when we first started drilling if we wanted exception it took a little bit of time. Now they're understanding better why we might want to drill longer wells or why we might want to drill closer to lease lines. We are getting those exceptions much, much faster.

Federal land, just the update there kind of timing of process?

We have actually drilled the on some private acreage right up in kind of on two sides surrounded by federal acreage. We are working that way with the rigs right now. In the case of federal, it is just like any other federal area, you want to put together units and we will start exploratory units and work through the development unit phase. We have begun the discussions on showing the VLM what those unit areas would like to do an a federal unit standpoint. Waiting their comments back and I except some time next year, early in the year, we will have unit designations and then we will drill some wells in federal the way we are planning next year.

Okay. Thanks, guys.

We will take our next question excuse me our next question from Gil Yang, Citi.

Hi. Just a follow up on that last question, Steve. The 500-foot spacing is a lease line, not a well separation?

It is both.

It is both. Okay. But you need to get exceptions to --

Right. So as we are doing down spacing we have to get exceptions just to do the testing, but we are getting those easy.

Okay. What does your micro seismic work tell you about how far the [frack] wings extend out from the older space laterals, older space [fracks] versus the tighter space today?

It doesn't tell us a whole lot. As we have increased the clusters, it is getting a little more fuzzy on the seismic along the way. I think part of your question are we getting as far out on our wings now as we were before with the technique that is we have got. Theoretically, we are designing them to get that far out and that's part of the reason from going to 2 million pounds to 4 million pounds, because on a (inaudible) interval we are putting the same amount of energy in the ground. But part of the reason for trying to do the spacing work is to help solidify whether we really are doing that or what is actually happening down there.

Okay. And then the last question is for the sand mine are, do your cost savings associated with doing that for the wells, is that built into your $3.1 million or would there be cost savings that would be seen, is it a cost savings issue or more availability and how is that built into you -- ?

We did it because we thought there was some cost savings and we didn't want to worry about the availability part of the overall problem. In general, service companies versus what we think we can do it. We can do it for about half of what the service companies were charging us for sand, maybe even less than half. What that right now would be about $150,000 per well. And that affect will not come in, like I say until early second quarter of next year. So we have not factored that into any of the '08 type numbers. And as we start talking about '09 later we will factor that in.

Okay. Is the 150 in total cost or in savings?

About $150,000 savings per well.

Okay. All right. Great. Thank you.

Our next question comes from Jeff Hayden, Rodman and Renshaw.

Morning, guys. Just a couple of quick questions. One, wonder if you can give us a little color on what your exit rate for the quarter was in term of production? And then also with the asset sales kind of behind us now, a little color on how we can think about the deferred tax percentage going forward.

On the exit rate for the quarter are you talking about net or Fayetteville or -- ?

Fayetteville and total company if possible.

We are probably doing in the 560 to 570 range exit rate as a company give or take, and that being net rate. On the Fayetteville, really over the last three to four weeks, we have been 600 to 610 on a gross basis on Fayetteville and that goes back to Boardwalk issues.

And we will take our next question from Mike Scialla, Thomas Weisel Partners.

Hi, guys.

Morning.

Morning.

In terms of the Fayetteville lateral, how mump production do you estimate being curtailed or how you many wells are waiting on completion?

Today we have got 29 wells that are [fracked], hooked up to the tanks and we can put on production. What we have done, we haven't slowed down drilling obviously because we have the same number of rigs running. We were a month ago doing between 7 and 9 frack jobs a week, wells a week. What we have done is dropped that to 5 to 6 range on a number that we have done a week and so we slow that down. So part of our completions are going to moving into next year. As we continue to drill that 29 will go up from there.

Okay. Remind me how much of your production in the Fayetteville moves through that Center Point pipeline? There's still capacity on your other major take away pipeline in the area. Is that not right?

We have got everything, everything we can possibly get out of the Fayetteville we are getting out of it right now with a small exception, on any given day there's 15 to 20 million a day we make decisions about, but we are max out at that 600 through any kind of outlets you can get. And on Center Point itself, we are moving total and this isn't just on the Fayetteville but we are moving about 240 million a day of total gas on Center Point.

Okay. And then in terms of the split on your rigs, can you say on the 15 rigs that are drilling horizontal wells, how many are drilling in what you would maybe call new areas versus development areas?

That varies but roughly five rigs are new areas, proven up acreage, those kind of things and the rest of the rigs are drilling second wells on a section or doing something in that direction, second, third, fourth wells.

Thank you.

Our next question comes from Jason Gammel with Macquarie.

Thank you. Can you guys remind us how your take away capacity in the Fayetteville is going to step up from the existing 600 as Boardwalk is completed and then Fayetteville Express is completed and any other pipeline expansions that I may be missing?

In the case of the Boardwalk, once it gets on very quickly we he have about 550 million a day. It is really two stages but that will be within a few months of each other. And then ultimately on Boardwalk we will have 800 million a day take away on a gross basis. The new project that we signed up the Fayetteville Express, that one when it goes on in 2011 over again about a 12-[month period will end up having about 1.2 Bcf a day and then firm on other pipelines, we have roughly 220 to 250 million a day that we either have or continue to roll as long as we want to do that.

Okay. Great. And then my second question, now that you are about three years into into the drilling program on the Fayetteville, have you seen anything that would indicate that any of your 860,000 acres would not be economic at let's say a $7 NYMEX price?

We really haven't. As, part of what we have done over the last quarter as we got this new working on our new completion techniques we have drilled wells on the far eastern part of the acreage to the far western, and have gotten very good wells. If you look at any of the third party stuff that's out there you will see we have got 4 million a day test rates across our entire acreage block. Right now we haven't condemned any of our acreage under any gas price really.

To be clear, we have had some wells that weren't economic in an area.

The geology changes across the area also. Some areas have more faults than others and you are not going to drill through a fault and close to a fault. Where there's a fault we drop something out but on a percentage basis that's not very much.

Okay. Thank you guys.

We will go next to Tom Gardner, Simmons and Company.

Hi, guys. Just had a follow up to Brian's question. He mentioned basically practical limits to lateral lengths and what that meant with regard to rates and reserves. I understood you to say that you see or you project a practical limit somewhere in the 4,000 to 4,500 foot range on lateral length. Is at that correct?

Well I in the shallow areas if you think about your acreage position, the north side of our acreage position is fairly shallow. You can be as shallow as 2,000 feet and encounter Fayetteville Shale. The southern part of our acreage, that's more like 5500, 6000 feet on the very southern end. The practical limit is how much pipe you can push in a hole from what you are standing up on the [derek]. So it has to do with just the physics.

On shallow acreage, and that's why you will see for instance [Petro Hawk] has a little less average lateral length than us. That's because in general they are shallower acreage than we are drilling. That's just a practical physics issue. It's not a rig issue or anything else. What will happen is you will get to the point you physically can't move the pipe anymore and your drilling rates will drop off and you know you have done it for that rock in that area.

With regard to the corresponding rate and reserve uplift, you really haven't seen, as you put it, a break over in that, and you would expect the rates and reserves to maintain that relationship to lateral length going forward?

There's -- yes we have not seen the breakover and there could be a point throughout where it does break over but we haven't seen it. So I don't know how to answer the other part.

I think we don't know the answer is what, is really, so we have to drill the wells on that spacing and have a long enough production history on them to compare them to ones drilled on different spacing.

Different space, different lengths.

The day we have, we haven't seen it but that doesn't mean that it won't be there.

What is the longest lateral you have drilled to date.

Just over 5,000 feet. We have done a couple.

Okay. The second question I have is sort of a follow[-up to your, you mentioned that the additional [proponent] and more energy, I assume that's more horsepower you are pumping into the completion. Are you pumping that benefit under the perf cluster completions, that 20% to 25% uplift?

Well, there's, we are doing two different things. We have got the clusters and then we have got the number of stages that is we do. That horsepower is in the number of stages. We have gone from a year ago three to five type stage numbers to the day where nine to 11 stages. Each one of those stages are about the same size as the three to five were before. That's where you get more energy in the ground.

I got you. Thanks, guys.

We will go next to Joseph Allman ,

Hi, everybody.

Morning.

The just a follow up to that, some of the questions Jason was asking about the increasing capacity. So, to get the Fayetteville production to ramp up to meet the capacity that's coming online, do you expect a ramp up the drilling activity significantly and over the next couple of years, and would you do that on your own or would you consider bringing in a partner?

Joe we, as you know from prior discussions about this, we have had in our mind that there, when we look at the overall Fayetteville Shale play that the way to maximize the present value is one of the ways is to do what we can in terms of drilling as rapid of a pace as possible. So, as we have thought about each of the years as we have moved along in our plan, in our heads it has been that we would put additional rigs out here to accelerate. And that is a decision that I would tell you based upon where we are sitting here right today is one of those that we mull over in our heads and we look forward at all of the uncertainties and the market places and everything else and that gets wrapped up in our 2009 plan for example, falls under the category of maintaining our options open and maintaining flexibility. There would be some point in time clearly in the play when we would want to drill more wells per year than we are.

One of the good thing that is happening to us is that as we have been able to continue to improve our operating performance and drilling, we are actually drilling more wells per year with the same number of rigs and that has been quite substantial improvement if you think back to some of these conference calls when we had much longer amounts of time required to drill an individual well. We are down now in this quarter to averaging 12 and Steve has said we can go to 10. So we are getting more activity and more drilling. The answer so bringing in somebody to do this is, would be like giving away equity in the company. And it doesn't compute for me when the value creation even at current price levels we are achieving with our drilling. But as a corporation, as a company overall, we need to keep the balance sheer much like our had helicopter of the cover of the annual report turned out to be very [profetic] for this year, and I think it is also applicable to next year. We want to keep capturing acreage and we want to keep making improvements and keep improving our efficiency. And there will be a time we will want to do additional drilling, put more drilling rigs out here.

Okay. So based on your obligations you have to get gas into the pipelines do you, is there a need to ramp up the activity to some extent if not if '09 then in 2010?

Well all of that has to come together as we see the impact of the results and depends upon how you model the improvements we might see with some of the things we are doing currently.

Okay. That's very helpful. Thank you.

We will go next to Dan McSpirit, BMO Capital Markets.

Gentleman, good morning.

Morning, Dan.

Can you comment or do you have comments on other pay zones you may be testing, obviously or namely the Moorefield and the Chattanooga?

In the case of Moore field, we haven't done anything on it from over a year ago. And part of the reason for our [XTO] sales on some of our properties was let them do testing on that. From that standpoint we really haven't done anything else. On the Chattanooga, we will drill a couple of Chattanooga tests, maybe even get one started this year, but we will drill a couple of them into this year and going into 2009 and start getting information on it.

Okay. Then a follow-[up question with respect to the well or wells you are drilling with lateral lengths greater than 5,000 feet. Can you comment on planned number of stages, frack stages, on those wells and the spacing between frack stages?

We are still experimenting. So I can tell you that the once we have just recently done were 75-foot cluster spacing between the between the first and the stages on that I think the most we did on one of those really long laterals was 12 stages. If we go to a 50-foot cluster spacing on our perforations, which we are doing in some of our other wells and experimenting with right now, those might go up, it mi go up another two, three four stages. So, that is the kind of range.

Okay. Very good. And then lastly, on [Waylu], any comments you are certainly realizing success there as is Petro Hawk as you comment in your press release if they're operating two rigs. What have you determined EURs at all? Are you willing to comment on cumulative production rates at this point?

What did you say? What did you say.

I'm sorry.

We are looking at each other wondering what that.

Different question for a different company. No need to comment.

We don't know, but it sounds good.

You should be there. Thank you very much.

(OPERATOR INSTRUCTIONS). We will go next to Joe Magner, Tristone Capital.

Good morning. There was a time some several quarters back when you all discussed resource potential of your acreage based on estimates of gas in place and (inaudible) recovery. As your results continue to get better and as you continue to optimize drilling and completion designs, has your understanding of that gas in place or has your sort of estimate of recoveries changed at all? Can we expect an update at some point in the future on recoverable resource estimates? Thanks.

Well, as far as the kind of gas, every well we drill gives us more information about the gas in place and we have a group that their whole job is to work on gathering all of the information we have and put it in a big picture for us, and whether that is completion technique, drilling technique, gas in place, or any of the other rock characteristics, permeability, frosting, those things that go with it, so we are continuing to update that and getting new information. I don't know that when you start saying about are we going to update in the future and do things, I don't know that as we get the important things, and as with we apply them in the field you will see that, but I don't know that we are going to do an update as far as that goes. We have to see what happens.

And our next question comes from Marshall Carver, Capital One.

Yes, I had a couple of questions. The first one on the wells that you put online in the third quarter, you had been putting on about 80 wells a quarter and you stepped up to 97. Did you tie a bunch of wells on at the beginning or at the end of the quarter, were they spread throughout the quarter? Just trying to get a feel for how much of the Q3 beat was timing versus rate?

Well, towards the end of the quarter you were starting to see the Center Point issue. So we actually slowed down a little bit at the end of the quarter, but other than that it was pretty constant right through the whole quarter. When I say the last quarter maybe the last two weeks we slowed down. But it was pretty much consistent across that. I think what you were seeing that well count completion going up was a function of those drilling days going down so you are drilling more wells per quarter and complete more wells per quarter.

You would always have the variability of midstream of the gather system lateral and different compression systems coming on. It is not strictly a drilled, completed and necessarily directly and to the pipelines because in some of the areas we have to build out and expand the piping system in order to put them on and they come on in groups also. It could be a lot of variability in that over time. You have to keep that in mind.

Okay. Thank you. Did you give the production break down by area? I missed the first minute or two of the call.

We did. Is there any particular one.

I just was hoping for the break down of east Texas conventional and Fayetteville and any other, I guess -- if you can give me the break down again I would appreciate it.

Okay.

Have you got it, Greg?

For the conventional it was 6.8,Bcfe, Fayetteville Shale, 37.2, east Texas 8.1, the Gulf Coast, Permian, others is about 0.7, and that if I did that right that should add out to 52.8.

Okay. Thank you very much. Sorry about that.

Okay.

And Mr. Kerley, we have no other questions standing by at this time. I would like to turn the conference back over to you for any additional or closing remarks.

Okay. Well just to sum all of this up when you look at Southwestern Energy, what we, where we are positioned is financially strong. Our balance sheet being now at 25% debt to cap. We have a low cost structure as our DD&A rates are in the sub $2 per MCF range and being impacted positively by further drilling in the Fayetteville Shale. We are in a grated position on our projects. That's evidenced again in our cost structure plus the size of the projects we have in front of us can have substantial impact on the results going forward. We have a growing production volume and that will drive in front of us just because of our activity levels, and then, with all of that summed up we have the flexibility to act. We have options open to us which will position us really well to keep our eyes open for opportunities in the market we are in. So I want to thank you again for joining us and have a good day.

And, once again, ladies and gentlemen, that does conclude today's conference call. We do thank you for your participation. You may disconnect at this time.