Southwestern Energy Company. Q2 2008 Earnings Call Transcript

Jul.31.08 | About: Southwestern Energy (SWN)

Southwestern Energy Company. (NYSE:SWN)

Q2 2008 Earnings Call

July 31, 2008 10:00 am ET

Executives

Harold Korell - President, Chairman and CEO

Steve Mueller - President, Southwestern Energy

Greg Kerley - EVP and CFO

Richard Lane - President, E&P Company

Analysts

Brian Singer - Goldman Sachs

Gil Yang - Citi

Joe Allman - JPMorgan

David Tameron - Wachovia

Mike Scialla - Thomas Weisel Partners

Robert Christensen - Buckingham Research

Amir Arif - FBR Capital Markets

Brian Corales - Coker & Palmer

David Heikkinen - Tudor, Pickering, Holt

Marshall Carver - Capital One

Tom Gardner - Simmons & Company

Scott Hanold - RBC Capital Markets

Operator

Good day and welcome to the Southwestern Energy Company's second quarter earnings teleconference. Today's call is being recorded. 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 Steve Mueller. Steve is actually President of Southwestern Energy now, Richard Lane, the President of our E&P company and Greg Kerley, our Chief Financial Officer. If you have not received the copy of the press release we announced yesterday regarding our second quarter results you can call 2816184847 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, we have the good fortune to once again report record results for this quarter. Our knowledge about how to drill and complete our wells in the Fayetteville Shale continues to improve and evolve, and this is leading to higher productivity in our horizontal wells. This is clearly showing up in our production volumes. As of July 1st, our gross operated production for the Fayetteville project reached approximately 500 million cubic feet per day which is up from about 200 million cubic feet per day a year ago. We're also seeing good things from our activities in the James Lime play in East Texas and from our conventional Arkoma Basin properties.

Adjusting for our improved performance, we have now moved our full-year production guidance from 181 Bcfe to 185 Bcfe for 2008 which is an increase of approximately 60% compared to our performance last year. As I mentioned earlier, Steve Mueller, who joined us in June is here today and I want to turn the conference over to him for details on our E&P activities in Midstream and then to Greg Kerley for an update on our financial results and then all four of us will be available for questions afterwards.

Steve Mueller

Good morning. Thank you Harold. During the second quarter of 2008 we produced 45.1 Bcfe, up 74% from the second quarter of 2007. Our Fayetteville Shale production was 29.6 Bcfe, up significantly from the 10.7 Bcfe we produced in the second quarter of 2007. Production from East Texas was 7.9 Bcfe, 6 Bcfe from our conventional Arkoma properties and 1.5 Bcfe from our Permian and Gulf Coast assets.

As a result of our continued strong production performance, we now estimate that our third quarter production will range between 47 Bcfe and 49 Bcfe and our fourth quarter will be between 50 Bcfe and 52 Bcfe. As Harold said, we expect our full year 2008 production will range between 181 Bcfe and 185 Bcfe. In the first half of 2008, we invested in approximately $739 million in our Exploration and Production business activities and participated in drilling 343 wells. Of this amount, approximately $605 million or 82% was for drilling wells.

In the first half of 2008, we invested approximately $547 million in our Fayetteville Shale play, including $459 million to sped 262 wells. At July 1st, our gross operated production rate reached another milestone of approximately 500 million cubic feet per day, including approximately 12 million cubic feet from our 14 wells producing from conventional reservoirs. Net production from the Fayetteville Shale in the first half of 2008 was 53.2 Bcf, up 18.9 Bcf from the first half of 2007.

During the second quarter of 2008, our typical well had an average completed well cost of $2.8 million, an average lateral of 3,562 feet and an average drill time of 14 days from re-entry to re-entry. As you may remember, this compares to 16 days to drill a 25-foot, 100 laterals just one year ago. During the first half of 2008, we achieved positive results testing closer perforation cluster spacing in our horizontal wells. We tested this technique on 38 of our wells during the first two quarters and have seen a 15% to 20% improvement in early production compared to the average initial production of wells in which we did not use this technique.

We estimate that the ultimate recovery on these wells will be improved by corresponding 15% to 20% and we are currently planning to use this technique on all the wells we plan to drill for the remainder of the year. Associated with this new completion technique and longer laterals, we now expect completed well cost to average $3 million per well for the rest of 2008. Also in the second half of 2008, we plan to test the down-spacing of wells at or below 80-acre spacing.

In Pennsylvania we currently have approximately 105,000 net undeveloped acres where we believe the Marcellus Shale is prospective. We have drilled our first two vertical wells on the Bradford and Susquehanna Counties located in the northeast part of the Commonwealth. We expect to complete and test the wells during the third quarter. We also plan to drill at least two additional test wells, one of which will be horizontal well on our acreage by the end of the year.

In the first half of 2008, we invested approximately $72 million in our conventional Arkoma Basin properties. We participated in drilling 46 wells here, including 21 at the Ranger Anticline and nine wells in our Midway field. We have also begun to drill horizontal wells both at Ranger and Midway and early result from these wells are very encouraging. Our production from the conventional Arkoma during the first six months of 2008 was 11.9 Bcf compared to 11.7 Bcf for the first six months of 2008.

In the first half of 2008, we invested approximately $78 million in East Texas where we participate in 23 wells, 12 of which were James Lime horizontal wells. Production from East Texas was 16 Bcf from the first six months of 2008, up from the 15.1 Bcf in 2007. We hold approximately 100,000 -- 102,000 gross acres in Angelina River Trend which consists of several separate development areas where we target the Pettet, Travis Peak and James Lime formations.

We drilled 18 wells in this area during the first six months of 2008, all of which were either productive or in progress at the end of the second quarter. We continue to focus our drilling activities here on the James Lime formation where we have nine operated wells on production which had an average gross initial production rate of 8 million per day. Our current net production from the James Lime is approximately 23 million cubic foot per day, including production from five outside operated wells.

We also announced the signing of the of a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale intervals in Shelby and San Augustine Counties and that's in Texas. Approximately 41,500 acres in our Angelina River Trend are included in Shelby and San Augustine and Nacogdoches Counties.

In summary, we continue to have outstanding results in our E&P business and are looking forward to continued strong results in the remainder of 2008. I will now turn it over to Greg Kerley who will discuss our financial results.

Greg Kerley

Thank you, Steve and good morning. Our record results for the second quarter were primarily driven by the significant growth in our production volumes as we reported earnings of $136.6 million or $0.39 cents a share, up from $47.6 million or $0.14 cents a share for the same period in 2007.

Our operating cash flow increased to $288 million, almost double the prior year period. In the second quarter of 2008, operating income for our E&P segment was $215 million, up from $81 million in the prior year period. Steve indicated we produced 45.1 Bcf equivalent in the second quarter and we realized an average gas price of $8.17 in MCF, up from $6.90 in the prior year period.

Our lease operating expenses per unit of production were $0.95 cents per MCF equivalent in the quarter, up from $0.73 cents a year ago. The higher per unit costs were driven primarily by the impact of higher natural gas prices on the cost of compression fuel and increased gathering costs. As a result we now expect our per unit lease operating cost to range between $0.92 cents and $0.97 cents in MCF equivalent for 2008, which is up about $0.07 cents from our previous guidance.

General and administrative expenses per unit of production were $0.41 cents per MCF in the second quarter, down from $0.48 cents last year. The decrease was primarily due to the effects of our increased production volumes which more than offset increased incentive compensation in payroll and related costs primarily associated with the expansion of our E&P operations.

We continue to expect our G&A to range between $0.42 and $0.47 cents per MCF equivalent for the full year. Taxes other than income taxes were $0.16 cents per MCF in the second quarter, down from $0.21 cents in the prior year period due to changes in the mix of our production volumes and accrued severance tax refunds related to our East Texas production.

We have reduced our unit cost guidance for the year by $0.05 cents and currently expect our rate to range between $0.15 and $0.20 cents per MCF equivalent. Our full cost pool amortization rate averaged $2.01 per MCF in the second quarter of 2008, down from $2.41 a year ago. A decline in our average amortization rate was primarily due to the reduction in our full cost pool that results from the previously announced sale of a portion of our Fayetteville Shale acreage.

Our Full Cost Accounting notebook gains recorded as a result of our sales of oil and gas properties. However as a result of the significant tax gains realized from the sales of our oil and gas properties that closed during the second quarter, we recorded a current tax liability of approximately $47 million, all of which is related to alternative minimum tax.

Operating income from our Midstream Services segment was $15 million during the quarter, up from $2.3 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. We are currently gathering about 600 million cubic feet of gas a day in the Fayetteville Shale play area to approximately 736 miles of gathering lines.

Our natural gas distribution segment realized a seasonal operating loss of $900,000 in the second quarter, compared to a loss of $1.7 million during the same period last year. Effective July 1st, we sold our utility business for approximately $230 million subject to post closing adjustments. We expect to book a gain from this sale of approximately $55 million in the third quarter.

Over the past several months, we have dramatically improved our liquidity and strengthened our balance sheet. We have sold or have entered into agreements to sell assets resulting in total gross proceeds of approximately $1 billion. In the second quarter, we sold certain oil and gas leases, wells and gathering equipment in our Fayetteville Shale play for $518 million. Additionally we have sold or have agreements to sell all of our oil and gas properties in the Gulf Coast and the Permian Basin for approximately $250 million in the aggregate. Approximately $179 million of these proceeds will be received in the third quarter and finally as I mentioned earlier, we have closed on our previous announced sale of our utility.

These proceeds have reduced our debt and will help fund our 2008 capital program. At June 30th, 2008 we had $177 million of cash on our books and total debt outstanding of approximately $736 million resulting in a capital structure of 33% debt and 67% equity and our debt could decline to as low as 25% by year end. We expect to end the year with one of the strongest balance sheets and financial positions in our history, well positioned for future growth. That concludes my comments and we will turn it back to the operator to explain the procedure for asking questions.

Question-and-Answer Session

Operator

Thank you. The question-and-answer session will be conducted electronically. (Operator instructions). Our first question will come from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you very much. Good morning.

Harold Korell

Good morning.

Steve Mueller

Good morning.

Brian Singer - Goldman Sachs

When you think longer term over let's say 2009, 2010, how do you see the balance sheet playing out? You have obviously just highlighted a number of the assets sales that you have made to shore up the balance sheet. When you think about your spending levels and free cash, do you see further asset sales down the road or do you think that Fayetteville gets into a position where you can continue to grow, maybe take up the net tangible capital a little bit, but be comfortable with that?

Harold Korell

Brian, a lot of variables go into answering that question. One would be, what is the gas price during that time period, one that is becoming less of a variable to us. We know our production volumes are growing substantially, as you can see from the information that we’ve been presenting over the last few quarters in the Fayetteville Shale and of course, the other variable is what would be our investing. We do not use the term spending, but the word we use for it is investing. What will our program be? What investment levels will we be looking at in our capital program for those years? So there are a lot of moving variables.

I can tell you, though, that just looking at this year, the direction of our production and where prices have been are driving our debt levels down in addition to the dispositions of properties that we’ve just done. The dispositions that we’ve done, properties we’ve sold in 2008, I would say all except the Fayetteville Shale represented strategic decisions. In other words, our strategy is not to be a utility company and over the years we’ve looked to an exit there, which came to us, and so we took advantage of that.

The Gulf Coast and the Permian areas are areas that we’ve played and had activities in for a number of years and just had a difficult time building to what we would consider a position that was worth us pursuing it, and so we decided to exit those, some part due to the capital we would benefit from there, but I would say more so just not to have the distraction of those activities going on and being able to redeploy the people who are working on those, on projects that we think have a higher return.

The Fayetteville Shale disposition was to test the market at that time and really sets us up nicely as we go forward. Having said all of that, which is disclaimer and backdrop, the future will depend upon gas prices and will depend upon the idea generation activities we’ve internally, will depend on how our Marcellus turns out and whether something develops on that acreage where someone is going to drill a couple of wells for us in Haynesville. So, many moving variables. However, what I can tell you is things look a whole lot brighter for us in terms of balance sheet now than they did a year ago. No small factor is the way our production volumes are growing.

Brian Singer - Goldman Sachs

When you think about the activity level and Fayetteville, is there some high gas price environment in which you would drill more and lower gas environment in which you would drill less and can you put any numbers around that?

Harold Korell

Well, again, it depends upon the performance of the wells and what I can tell you is our analysis, as we look at the Fayetteville Shale would tell us, we ought to want to drill more wells there. We are trying to organically drilling more wells there by the fact that our wells are drilling in less time and therefore with the rates that we currently operate we are drilling more wells there just with the same number of rigs.

We are looking at when should we put more drilling rigs out here and we are analyzing that continuously as I have talked about this in the past, one of our things that we’ve had to balance is to make sure that if we do put more drilling rigs in the Fayetteville, that we’ve the capability to manage all of that operationally in an appropriate way, so that we keep our results up where we want them to be and that means people. We’ve continued to add people and we’ve been patient about that because we had the feeling of what it was like during '06 and early '07 when we put all these rigs on line and some of our results were not as good because we just did not have the people to be analyzing, well, all the information flow that was coming back at us.

I would tell you that we are a lot better positioned to add rigs now than we’ve been and at gas prices where they are, those wells are hugely profitable and unless there would be some really serious drop, if there were a serious drop that occurred for an extended period we would, that would be, that would be something that would affect investment decisions then going forward. We also like to hedge the first couple of years of production. So we try to take some of the price risk out of there. So I think should you expect us to add rigs there? Yes.

Brian Singer - Goldman Sachs

Thanks and if I could get one more, one very quick one. It looked like in the second quarter, your average IP rate in the Fayetteville is up versus the first quarter, but the 30-day and 60-day were down a little bit. Is there any color around that?

Harold Korell

Yes, Steve or Richard would you like to --?

Steve Mueller

Brian, this is Steve Mueller. I think it is really just statistics. We’ve looked at those wells in a lot of details and a lot of different ways and you are just not seeing all the wells and when I say statistics, these wells you got to remember are drilled over several square miles, so they are not drilled. This is not a development program and each area has got a little different characteristic to it and it is just how you drill the wells. Those numbers will go up I think in to the next quarter.

Harold Korell

I think the other thing to say, Steve is that some of the wells that have a full 60 days, let's just stop and talk about how the numbers work. We drilled, what is that, 80 or so wells in the second quarter? So some of them were drilled on the first day, the first 13 days of the second quarter and some were drilled on the later, and so what you are seeing and obviously that did not go without notice here either, is that some of the wells that we drilled early on in the quarter which now represent the wells that have 60 days of production, those wells, when you go back to look at them, had lower IPs. So there is a grouping of wells there that were not as good we drilled early in the quarter.

Brian Singer - Goldman Sachs

Thank you.

Operator

We will move on to our next question. Our next question will come from Gil Yang from Citi.

Gil Yang - Citi

Hi. Greg maybe, can you comment on the cents per MCF effect of the asset sale on the DD&A in the quarter?

Greg Kerley

Sure. Sure, what we saw was when we think when all sales are going to be factored in, it will probably have about $0.35 to $0.40 cents in MCF impact of lowering our rate. Now, there are a lot of different factors that factor into what that rate is, our reserves that are added during a period, our costs that are added during the period, so a lot of moving parts there also, but on a pure sale, the fact of the credit that goes to the full cost pool, it had about that impact.

Gil Yang - Citi

Just following up on that, as you add new volumes to the full cost, what is the apparent rate of the new reserves that you are adding to that pool? Is it in the 250 range?

Greg Kerley

It is lower than that, obviously, because besides the effect of the sale, the rates hanging in there a little over $2 right now, $2.01.

Gil Yang - Citi

No, no. That is on the income statement. Okay, so as you drill new wells, you are still adding them and you take the $3 million divided by a little less than two Bcf per well? Is that the--?

Greg Kerley

That is correct, I mean correct right now. It will depend on what we ultimately, our bookings are for the year for those wells.

Gil Yang - Citi

Okay.

Greg Kerley

What our reserve revisions are from the prior year and I think the $2 right now based on what we are looking at this point is a good number and of course that is going to change one way or the other as we finalize our audit reserve numbers at the end of the year.

Gil Yang - Citi

However, I think about your SORT OF F&D or DD&A going forward, the incremental figures, what other costs are there besides that $3 million per well? Is that hooked up and completed and hooked up or are there additional pipeline costs and other --?

Greg Kerley

There are other costs in the DD&A pool, our capitalized interest, our capitalized G&A and seismic, we put all costs that are evaluated as they get moved into the pool. So, it is not just the total drilling and completion costs on an individual well basis.

Gil Yang - Citi

Okay. How much are those other items on a DD&A basis?

Harold Korell

Gil, if you are just isolating the Fayetteville and you can talk about those numbers, but our finding costs like what we reported last year and how it is looking this year is your best guidance towards any quarter of what is happening.

Gil Yang - Citi

Okay.

Steve Mueller

I think the other way to look at that, when I was making some comments about the Fayetteville, in the first half, we spent $550 million. $460 million of that was for drilling, splitting the wells and drilling. So, there was an incremental capital investment that would go into that DD&A pool on top of that. As Richard says, each of the areas has those kind of investments besides the drilling enforcement.

Harold Korell

I think the interesting thing to stop and think about here on this is that there are DD&A rate is the sum of all of the capital that is in the depreciable pool, all the reserves for the company that are in that pool, one divided by the other. Each quarter, as we add capital investments and add reserves, they go in there, and so they incrementally have an effect on the overall company DD&A rate.

From an earnings perspective, the $2 DD&A rate we are seeing now is a hell of a nice base to be at as a company and has to be one of the lowest that is even out there. The change, which you are noticing now, is simply from the fact that prior to the sale of the $518 million worth of properties to DD&A, we had moved into the DD&A base the cost of all of that acreage and the cost of whatever drilling and investments had been made by the company up to that time.

Now, we sold 5% of our acreage in the Fayetteville Shale play for $518 million. So, that is just simply you back that out of the depreciable base, and it has $0.35 to $0.40 impact on the DD&A rate. Now you know as you think about it as a company and you are going to be thinking about that happening into a bunch of other companies right now who have accumulated acreage at 100 like ours.

Good fortune we’ve is that and we’ve been saying this all along is that our cost basis on this matters, and we’ve a very low capital investment on the land we’ve in the Fayetteville Shale. Now, we’ve sold just 5% of it. So, that has been recovered. The depreciable base is down. So, it is going to affect our DD&A rate and that is going to have a positive impact on earnings and on retained earnings. It just blows on through.

Gil Yang - Citi

Okay. Fair enough, Harold. My second question, just wrapping up on the acreage, you say you are going to drill behind your 3D going forward. What leasehold issues do you have to hold leases and does the drilling behind the 3D reflect that you held everything or does it mean that you have enough of a clock that you do not need to worry about it for now?

Harold Korell

We still have acreage to earn. So, we still have a portion of our wells that will be stepping out into new sections in the play in between where we’ve drilled to be able to earn. So, we still have a piece of that going on. We need to have. We do not intend to lose acreage that we want to hold.

Gil Yang - Citi

So the 3D does cover some new areas?

Harold Korell

Yes, yes.

Gil Yang - Citi

Okay.

Harold Korell

I think the good thing, Gil, is that we are not being led around by the lease expiration schedule. We’ve gotten ahead of that and we are managing it instead of it managing us.

Gil Yang - Citi

Great. Okay. Thank you very much.

Operator

Thank you. Our next question will come from Joe Allman from JPMorgan.

Joe Allman - JPMorgan

Yes. Good morning, everybody.

Harold Korell

Good morning, Joe.

Joe Allman - JPMorgan

Greg, could you talk about what you are expecting for current taxes for the third quarter and the fourth quarter and then when do you expect to start? I am assuming that the current taxes for the rest of the year are related to the asset sales. Then when would you expect to start paying current taxes on an ongoing basis?

Greg Kerley

Joe, that is one of those multi-bearable points too. With the other sales that have closed in the last half of the year and that will have an impact, obviously, which would create some additional alt minimum taxes for some of those sales.

Whether we pay current taxes or not will really be driven more by what gas prices are now to the balance of the year, but we’ve definitely used up quite a bit of our net operating loss, carry forward with all these gains. However, as we go forward, it will be really driven by what is our plan for 2009 and what is our total capital investments, because as you are aware, a large portion of our capital investments are deducted on the current year, the intangible costs portion of it.

So, right now it is too hard to say what 2009 is going to hold. We do expect that we will have some additional taxes that will be currently payable that will record between now and the end of the year. However, again, most of those will be driven by alt minimum taxes, which will be prepayments effectively that you get benefit of in paying less taxes in future years.

Joe Allman - JPMorgan

Okay. That is helpful. Thanks. Then the second question is either Steve or Harold or Richard, could you just describe that close perforation cluster method that you are now using for your fracture stimulations?

Steve Mueller

I can start talking about it a little bit. If you think historically about fracture stimulations, there is two issues that you always worry about. It is how much energy you are going to put in the ground and how you are going to disperse that energy when you put it in the ground.

Historically, you put very few perforations in a lot of energy and you try to make a single frac wing going out a long distance. What we are doing is trying to break up more rock than having rather than just a single wing. The way you do that is spread your perforations out and distribute that energy that is going into the ground. That is the perf cluster part of it.

Then to encounter more rock, you need to do more of those clusters along the wellbore. How much energy you put in the ground may take several times to do that. So, we will have several stages. We’ve increased the number of stages from 5 to 9 to 10, 12 range on stages. That is how many times you actually frac. Then we’ve also put those clusters closer together. The whole concept there is just bust up more rock near the wellbore.

Now, that also works back into your spacing. If you are not making the fracs go out of spore and you are busting up more rock near the wellbore, then you might need to have tighter spacing. So, we are working on both of these issues at the same time as we go through it.

Joe Allman - JPMorgan

Okay. Very helpful. Thank you.

Operator

Our next question will come from David Tameron from Wachovia.

David Tameron - Wachovia

Hi. Good morning. A couple of questions. Can you give a little bit of a detailed question, but can you give me what your CapEx spend has been just in the Fayetteville over the last 12 months. Maybe that is a number you have got to chase down and get back to me on that is fine.

Harold Korell

The last 12 months would because we probably do not have that.

David Tameron - Wachovia

Okay and the number for this year is still targeted the same as your new presentation on that one point?

Harold Korell

Yes.

David Tameron - Wachovia

Okay and second question. It is a little bit further out, but have you looked at the proposed SEC rule changes and if so any first take on what it may mean for reserve bookings, I realize it is 18 months down the road, but any initial take on those changes?

Harold Korell

Well, I mean, in general, you can read them, we can read them, everybody's read them, so you could see that plays like the Fayetteville Shale assuming prices were the same under either scenario, you would have the ability to book wells that were further off than one well from any producing well.

In fact, we’ve had a restriction that we could only book the ones parallel, but not off the ends as far as proven undeveloped, so there would be flexibility in adding proved undeveloped reserves likely under those scenarios to what numbers and are not going to talk about that today obviously because we haven’t done any numbers on it, and then the pricing thing itself, it would have an impact depending upon where your end prices were versus the 12 months leading up to that because that would be a rule change.

Generally, what I would say is that the changes that have been put out and proposed are pretty much in line with the comments the most of the industry players have made. Then the other one, of course, is that if in fact they give you the option of reporting probable and possible, then we would have to look at all of those numbers and figure out what we’ve put there and that is going to create huge variability I think on most, how companies deal with that, but I think that what they are proposing is generally really quite good because I think that it will make more transparency and clarity to what the real reserves are particularly behind these resource play, relative to the rules that have been artificial in the past.

Steve Mueller

The other thing I would add, Harold, is that the question also, as the effect for the end of this year and I do not think it is clear whether these rules would be in place by then and whether they would affect year-end reserves or not.

David Tameron - Wachovia

All right. Then from a borrowing basis, they would loan on PDP, so it really should not have an impact on that, correct?

Greg Kerley

Well, this is Greg. One of the benefits of Southwestern Energy, we do not have a bond base. Our credit facility is an unsecured facility, so it has no impact on what our borrowing is, our borrowing ability.

David Tameron - Wachovia

All right. Thanks, nice quarter.

Harold Korell

Thank you.

Operator

Our next question will come from Mike Scialla from Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

Hi.

Harold Korell

Hey, Mike.

Steve Mueller

Hi, Mike.

Mike Scialla - Thomas Weisel Partners

It looks like the last 150 Fayetteville wells you have added on line, you have only excluded one for mechanical problems and that compares to about I think 7% of your first 415 wells or so. Is there anything in particular that you have learned there that is led to that kind of improvement?

Harold Korell

Well, lots of things, Mike. It is nice to see that being noticed. I am sure our operational teams would appreciate that, our drilling guys in particular, but we’ve smoothed out a lot of things and a lot of it has to do with our drilling practices. We are having a lot less trouble with some problematic intervals above the curve. That is going smoother. Building the curve and getting into the horizontal part of the hole has gone better as well.

We’ve changed a lot of the best practices we are using in both those parts of the hole, which set the stage for the completion part of the hole running smoother, smoother holes, less stock [ph], all those kinds of problems with side tracks and so all those things have been really just compounding and helping us have less problems. I think the 3D seismic has helped significantly as well. We are staying in our zone. Most of the wells we are able to stay in zone more consistently than without that data and also steer the wells better. So all those things are coming into play and our completion methods as well, how we are doing the wells are all having a positive effect on that.

Mike Scialla - Thomas Weisel Partners

Do you think that one out of a 150 kind of number is sustainable or those are just an anomalous situation?

Harold Korell

Well, I do not know what the exact number is. However, we just keep striving to smooth out our operations and learn from what we’ve done in the past and we’ve a high amount of our wells in areas that we’ve already drilled, so we’ve some benefit of that as well. As we step out in new areas, I am sure we will have to learn some things also.

Steve Mueller

Mike, we are on a steep learning curve as you can see with the days going down on the wells, but with that learning curve, I think you can expect these kind of numbers in the future. You might have one or two blowups along the way, but we are learning fast. I am very comfortable. We can continue that learning curve.

Mike Scialla - Thomas Weisel Partners

Based on the current price and cost environment, can you give some sense in terms of percentage how much of that 857,000 acres you have that you would not be willing to drill at this point?

Harold Korell

None of it.

Mike Scialla - Thomas Weisel Partners

That is a pretty good number.

Harold Korell

Well, we do not know enough to say we do not want to drill on any of it, Mike, but we also do not know enough to say we want to drill on all of it.

Mike Scialla - Thomas Weisel Partners

Right.

Harold Korell

That is the way I will have to answer that.

Steve Mueller

Yes, we certainly have not condemned any broad areas, Mike, and in fact when you look at the first half of this year versus a year ago or more, areas that were not as high performing, we’ve actually done even better in those now, so as time goes on and we improve the cost side and the performance side, it is all up for development.

Harold Korell

Part of the question, area we are trying out least about is on, you remember our map is that area that flops off over and up and into the west, which a lot of is federal acreage that we are beginning to put our plans together on. It is long-term leases and so we haven’t done very much over there. We do not know a lot about that, but we know that the section is present and that area we just have not done very much on that fraction.

Mike Scialla - Thomas Weisel Partners

Okay. Thank you very much.

Operator

Your next question will come from Robert Christensen from Buckingham Research.

Robert Christensen - Buckingham Research

Hi. Over to the field. It seems to have been lost in the minds of many. What is the future there? It was a big part of your company a while back. Are we experiencing a loss of output in the field or is there new technology that you apply up there?

Steve Mueller

Bob, on the --

Harold Korell

Go ahead.

Steve Mueller

Sorry, Harold. It certainly is not lost on us. It is been a tremendous asset and it continues to be a tremendous asset. Some day when we are done drilling there, it is a huge cash cow for us and so we’ve one rig working over there right now. Some of the things still left to do, we did do a horizontal well there that tested about 8 million a day and producing pretty darn well and now looking at doing some more of those there in the second half of the year. So, perhaps there is some more of that to do based on the performance of those wells and also our East Texas team has been adding new assets and backfilling our opportunities set with new things and new production coming from them.

Robert Christensen - Buckingham Research

How many more horizontals might you do? Was this one on the edge of the field? I think I understood it to be there, but I was excited about that. I am very encouraged to hear these results. More horizontals to do there?

Steve Mueller

Well, I think it would be, just what I said. It is going to depend on how these next few go and there is some more potential for there, but I am not really prepared to quote you a number on how many we could do.

Robert Christensen - Buckingham Research

My second question coming back to the conventional above and below the Fayetteville and I think I asked it last quarter and you said it would be back half loaded drilling for the Hale and the ore and maybe sometimes in out buckle. What are your plans there? That excites me.

Richard Lane

Yes. I think as the year emerges, it certainly is turning out that way, that more of those tests will be in the second half of the year than the first half of the year. We’ve borrowed a rig that was designated for that area to help on some of the other Fayetteville drilling, so I think the second half of the year we will have a bigger push there for that. There are certainly good potential and proven potential in the token section. We’ve seen some really nice producers there that will keep pursuing as well in the deeper section.

Robert Christensen - Buckingham Research

Thank you, Richard.

Richard Lane

You are welcome.

Operator

Thank you. Your next question will come from Amir Arif from FBR Capital Markets.

Amir Arif - FBR Capital Markets

Good morning. First of all, congratulations on a great quarter. First question is, can you give us some more color on the results you are seeing from your multi-well pad drilling? I know you started talking about it last quarter. I just wanted to see, what you think of it today.

Harold Korell

We are seeing a cost savings and a greater number of percent of the wells that we are doing in 2008 because it is going well. That number is going up maybe from what we planned at the start of 2008 or when we were putting our plan together in 2008, so we think, full year probably, approximating maybe three quarters of the wells that we do will have the benefit of that multi-well pad situation and we will keep pursuing that, but we are seeing some savings there. I do not think we are seeing all that ultimately we might see there, but so far it is going pretty well.

Amir Arif - FBR Capital Markets

The primary benefit has been the cost savings? You are not really seeing as much synergies between wells?

Richard Lane

Well, the synergies, what we are seeing is centralization of lots of things and economies of scale on the surface operations. For example, we have less lease roads, miles of lease roads to get to the same amount of wells. We have lower surface location costs, well location costs. We have a centralization of facilities, both from the producing side and from the Midstream side, a chance to deliver water for the completions more efficiently and at a lower cost. So it is all those things, Amir, that are coming into play.

Amir Arif - FBR Capital Markets

Okay. Second question, on the production numbers, you currently have 500 million a day gross. Where do you see being by the end of the year?

Richard Lane

Are you talking about the Fayetteville Shale there?

Amir Arif - FBR Capital Markets

Yes.

Richard Lane

I do not think we’ve forecasted that completely in to the end of the year. I think the quarterly guidance that just came out is probably your best guide to where that is headed. We see nice increases in the rest of the quarter and it is going to continue to grow, obviously.

Amir Arif - FBR Capital Markets

Sounds great. Thanks.

Operator

Our next question will come from Brian Corales with Coker & Palmer

Brian Corales - Coker & Palmer

Hey, just a couple of quick ones. Harold, you talked in the past about accelerating one of the biggest impediments is really people. Is that still the case? I mean the balance sheet is much better than it has been. Just curious on what the big hindrances are that could be for accelerating further into Fayetteville.

Harold Korell

No, I think we always have to look at the overall environment that we are in. One of the thing is, somebody asked a question a few minutes ago, was the lack of real serious problem mechanical wells in the Fayetteville Shale and I think what you are seeing there is the result of being patient about getting our organization up and running right, so that we have efficiency in what we are doing not just going faster and not gaining all that efficiency.

That is what we’ve been looking for, being able to understand the information flow we are getting back out of our wells about how we are tracking them to know we are doing that right, get to the point where we are operationally drilling the wells effectively and we’ve been recruiting people and we’ve been moving people around with the asset sales we’ve been able to move people from those projects over to the more important projects and so we’ve been patiently positioning ourselves and we will put more rigs out here. It is not a capital issue for us right now and we just want to do it in a workman-like manner in the right way.

Richard Lane

Let me add, we want to incorporate our learning and that goes into even what kind of rig you would put out there and we do have one rig that is a little bit different than the others that we are testing right now that we are working with and as we look down the road at what rigs even to put out there, we are trying to get up that learning curve so when we do bring out new rigs we can even do better with what we are doing.

Brian Corales - Coker & Palmer

Just one more on the asset sales side. Are you all still looking to either sell additional Fayetteville assets or potentially some of the other assets that may not be as core to the company at this point?

Steve Mueller

Well, we normally would not comment on something we hadn't announced like that, but so that is the company line on that. We do not have anything pending right now.

Brian Corales - Coker & Palmer

Okay. Well thanks so much.

Operator

Our next question will come from David Heikkinen from Tudor, Pickering, Holt

David Heikkinen - Tudor, Pickering, Holt

Good morning. Just thinking about your Fayetteville development, wanted to hit first on the pilots for perfect clusters and spacing assumptions. Can you walk us through how that is going to be oriented, number of wells per section or what you are thinking there?

Harold Korell

Well on the perfect clusters as Steve reported, we are watching the production from the first 38 that we’ve done and we are real encouraged on what we are seeing there and those rates are holding up. So it' s not just an early time phenomenon, but we will keep watching those and pursue doing those on most or all the wells that we’ve left for the year. Additionally, I think we reported that the other part of the equation that Steve did mention is that you can affect all this with two different geometries, one up and down the wellbore and one how close the wellbores are together, so the perfect cluster spacing is attacking up and down the wellbore and the second one we reported we are going to start testing the wellbores being closer together so --

David Heikkinen - Tudor, Pickering, Holt

Will those be still north-south oriented similar to the Rainbow pilot where you are then just filling in between those wells and still drilling an east-west well on the northern and southern boundary? That is what I was trying to get to.

Harold Korell

Yes, yes, David, that is the general pattern we would have in mind right now and it is just a matter of how close we can get them and where the economics are and the best recoveries are and ideally I think we want to be doing them from inception in a section, not going back --

David Heikkinen - Tudor, Pickering, Holt

Right, and infilling?

Harold Korell

And infilling.

David Heikkinen - Tudor, Pickering, Holt

So how many feet apart are you doing? Can you give us that on your --?

Harold Korell

Well, most of our wellbores right now are a thousand feet apart or greater and we talked about this yesterday, we’ve some regulatory limitations right now that with 560 feet between wellbores, if some day development warranted more than that is something you could work with, but right now that is the sideboards on it.

David Heikkinen - Tudor, Pickering, Holt

Okay. That helps me visualize it. Then thinking about your average days continuing to come down, can you talk about what your ideal well would be if you did everything right with the best rig, best crew, each operation, how fast could you drill a well re-entry to re-entry?

Harold Korell

Boy, our drilling engineers that are listening right now are shaking in their boots. I would turn this over to Steve and Richard.

Steve Mueller

Yes. I will say, part of the re-entry to re-entry, just how far the wells are apart that you are going to. Do I just get a well or do I have to move it several miles to get to the next location. When you start talking about our demo area, we’ve had some wells as low as 12 days already and part of that was just the fact of the skidding part, part of it was the crew working together just learning as it were on that demo area so we know we can get it somewhat slower in the right conditions but across the entire play and what it is actually going to average, there is a lot that goes in to that.

David Heikkinen - Tudor, Pickering, Holt

No. That is helpful. Greg, just one question going forward. On the Midstream side with 600 million a day today, how should we think about operating income for that business heading forward into the third and fourth quarters?

Greg Kerley

It is going up a little bit from what our previous guidance was. I think we are, obviously we had a strong second quarter and it is going to be really dictated, obviously, by the Fayetteville Shale production volumes. Right now, you know, we are at 50 to 55 million is the guidance out there but it could go up a little bit from that if we continue to see the build that we are seeing in the first half of this year.

David Heikkinen - Tudor, Pickering, Holt

Okay. That is helpful. Thanks. That was it.

Operator

Our next question will come from Marshall Carver from Capital One.

Marshall Carver - Capital One

Yes, most of my questions have been answered but I had a couple more. On the Haynesville wells, are those going to be vertical or horizontal and what is the timing on those? Hello? Hello, hello.

Operator

Stand by. It looks like we are having some audio issues. We will be back momentarily.

Harold Korell

Hello.

Steve Mueller

We are back online. Patch us back in.

Operator

I will. This is the operator again. (Operator Instructions). We will move on, back to our question from Marshall Carver from Capital One.

Marshall Carver - Capital One

Haynesville wells, are those going to be vertical or horizontal wells?

Greg Kerley

Marshall, I think we just caught part of your question but I think we’ve got the crux of it. I do not think it is totally determined yet what those first wells will be. We are still programming that. Ultimately we want to try the horizontals, obviously, but we are still working on that program.

Marshall Carver - Capital One

What was the logic behind doing a JV? Did the private company have expertise in that or something?

Greg Kerley

There were several things. They did bring some expertise and some regional work. That leapfrogged us forward in our understanding there on the play. I will tell you it is a pretty darn big step out from where the known activity and the well tests have been reported. So certainly, a significant risks there and, we will get a look at it, the leverage of the deal there we will get a look at those wells and then if it works out, then we’ve got a real nice partner there in place to pursue it.

Marshall Carver - Capital One

Okay. Thank you. One last question. In the Fayetteville, at this point what percentage of your rigs or wells would you say are in development mode versus the first wells in a section?

Greg Kerley

I would say we are probably somewhere in the 90% on that, Marshall.

Marshall Carver - Capital One

Okay. That is helpful. Thank you.

Operator

Thank you. We will move onto our next question, Tom Gardner from Simmons & Company.

Tom Gardner - Simmons & Company

Good morning, everyone.

Harold Korell

Hi Tom.

Greg Kerley

Good morning.

Tom Gardner - Simmons & Company

Hey, Harold. We are hearing reports that pipeline and infrastructure constraints and these prolific resource plays, with the stellar growth you are having in the Fayetteville, can you discuss the pinch point for activity both in production as well as activity?

Harold Korell

Well, that is a pretty big question. From a standpoint of working from our well heads towards the market, our pinch point could possibly be later this fall if Boardwalk does not get completed as scheduled in their first leg of that. We do not see that as a huge restriction on us achieving our objectives, but there could be some period there if they do not get their first phase of that project done exactly on the time they had talked about. Then, of course, the same thing would hold true as to the second stage, which should happen in the first month in '09. Beyond that, it becomes a question of what all volumes people try to push into those pipelines and markets and what the demands are at the other end. So it is a bigger question that I can completely answer for you.

Tom Gardner - Simmons & Company

Well, jumping over to the East Texas James Lime, I just wanted to get a sense for your view on how big the opportunity is given your success there, how much of the play do you now consider perspective, what spacing reserves costs do you have going forward?

Richard Lane

Well, Tom, this is Richard. We obviously have not fully delineated it. We can see really all the acreage we have there I would feel good about saying certainly it is perspective and but it is another stretch to say proven, we are not there yet. However, you know, there is a lot of potential there, probably north of 100 wells given our acreage base. I do not think we know the spacing yet, so that number is going to move around with that. We will probably try some of the same things that we are talking about in the Fayetteville there as well, although we are dealing with the different reservoir. So a lot of potential will stay busy there the rest of the year. The good news is even in the areas that are the low rates that we’ve seen, we still look like we’ve a play to pursue there and then we’ve had some areas with really, really high rates, so a lot of potential there. It is hard to quantify entirely right now.

Tom Gardner - Simmons & Company

Well, thank you very much.

Richard Lane

Thank you.

Operator

We will move onto our next question from Scott Hanold from RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Good afternoon. The question going back to the closer perforation clusters because it seems pretty significant for you as you can increase, obviously, the size of the wells with a minimal capital cost and just so I understand this right and when you basically, what are, doing is essentially trying to get more recovery in and around the wellbore versus reaching out as far and also could you talk about, is this done elsewhere to a great extent or is it, how did this sort of process come about? Is it something that you are just testing out and it worked?

Richard Lane

Well, I think that when you think about, Steve framed it really well, I think early on there when you think back about the early times and terminology like limited entry, you would have a stage you wanted to pump into and so you would have a small amount of perfs spaced out to a great degree so that would be the limited entry part of it such that when you were pumping on those, all the energy is going into that limited amount of perfs and really what we are doing here is let's take that same stage and let's pump, basically the same amounts of volumes but let's have the fracturing going on closer together and does the stage take it? Is it doable? Is it mechanically doable and do we see a performance increase from it and the answer to both of those is yes and yes. I do not know that we’ve micro sized enough of those wells to say we can define a change in the half length of those fracs or not, but that is part of what needs to get done as well.

Scott Hanold - RBC Capital Markets

Okay. How did it come about, doing this? Is this done in the Barnett as well or is it something you are just playing around with in the Fayetteville?

Richard Lane

Though there is certainly some Barnett players, and in which part of Barnett perimeter are trying to do this. There is also some work been done on the Woodford that choose some of these clusters. However, really from our perspective it is just trial and error. However, we started it, looked like we were getting a little bit better wells with one spacing and we just kept cutting the spacing down and making more clusters, so right now we are at about 75-foot apart on those perforation spacings, so you are not going to see that go down too much more. We are pretty close together right now.

Scott Hanold - RBC Capital Markets

Okay. How about simul fracs? Have you done enough testing on that where this clusters, your closer clustering is maybe better than doing simul fracs or can you do that simultaneously, both of those in conjunction with each other and what are your thoughts there?

Steve Mueller

We have done some simul fracs. Jury is still out on the benefit of what they are going to do for us. We will be doing some more of those along with this, as I said, it is a series of things go with it, spacing, how many wells you are fracing at one time with the simul frac and that all goes together and we will be trying that and it is a continuous improvement to our project. We would just continue to do that. We do not expect we are ready to get a magical answer anytime soon. This is one of those things we just keep improving. If we run in somewhere it is not improving, we will try something else.

Scott Hanold - RBC Capital Markets

Okay.

Harold Korell

This question is, I think Steve has done a pretty good job here this morning of opening up and trying to paint a verbal picture. It is easier if we had a chalkboard here but if you think about drilling a horizontal well, you would want to use every effective foot of that wellbore if you could and so placing perforation clusters closer together is about contacting more rock and Richard had said up and down a laterally along that wellbore, you would want to use that hole that you created in the earth to contact as much of the rock adjacent to it, and for as far out from the wellbore as you could. If you carry this to the ultimate answer, if you just jump there today, it would be you would have figured out how close to put those clusters optimally. Then by pumping the energy, and it is only going to go out a certain distance from the wellbore. Under the old limited entry, you are trying to create long linear fractures. That goes back to conventional wisdom about how the fracture is stimulating rocks, you try to go as far as you can.

However, if in fact, you think about this where we do not probably have a lot of profit out there in those long fractures, you may actually create a long fracture and not have much conductivity of it. So, better answer may be clusters closer together along the lateral, and then wellbores that are spaced closer together. Then the ultimate answer would be if you could do it, you would take two townships of land, drill all the wells, put all the world's pump trucks out there and probably pump energy into it, break it all up like one day. However, of course, you cannot do that. You have practical limits on how much horsepower you can put out when the wells are drilled and all that. So really the question on simul-frac is, how many simul-fracs to do at one-time if that was the way to do it? However, there are real world fragmentations on some of this. Maybe the reason we do not have not seen real improvement in simul-fracs as we’ve got our wells spaced too far apart and they have not really impacted each other in a way that they would. On the other hand, from some our technical folks meeting with some other companies, we are not hearing the 100% consensus that simul-fracs are benefiting always either. So there is a lot of going on here and we will just continue to increment our way along. Good news is we are making progress on it.

Scott Hanold - RBC Capital Markets

I appreciate that color. One quick one, going back to the Haynesville, you gave a little bit of color there. Is there anything in particular you saw on your acreage like a $8 in older well log that may have touched it, got you interested? Or is there a lot of industry activity there, and we are going to test it but at this point, that is about all you know?

Harold Korell

Reality for us is, most of that activity is several tens of miles away from us that has been going on. If you had to come right inside to Southwestern Energy and say how do you feel about it, our acreages? We’ve commented on this each time we’ve been asked the question, the answer was we do not know because we are quite a ways away. However, if you had to ask our technical team, they are not real high on our acreage as to the Haynesville potential. If we thought it was a lay down 100% thing, we would probably have invested our own money in drilling. So here we’ve a chance of someone coming in and putting some of their dollars into it and if it works, that is great because we will have half of whatever it is on the acreage that we’ve committed to the deal. They have brought some acreage, and it is with a quality group of people who can focus 100% on making it work. So that is our thinking on it.

Scott Hanold - RBC Capital Markets

Are you being carried on part of the cost or is it straight up 50/50?

Harold Korell

No, we are being carried on the cost early on.

Scott Hanold - RBC Capital Markets

Okay. All right, thank you.

Steve Mueller

Let me just add that, you ask about us do we’ve any information nearby? There are a couple of wells nearby that actually have drilled through the Haynesville. So we’ve seen and compared to some logs that are as Harold said, 60, 100 miles away depending on which wells you are looking at. As you would expect that far away, there are some similarities but there is also lot of differences. So that is why we say we just do not know.

Harold Korell

As we would look at our plan, we would not be drilling these wells right now with our money. That does not mean they should not be drilled, it is just one interesting comment. I think it goes back to a question Tom Gardner asked was, what about all this gas? Well, if the Haynesville is good here, then we got a heck of a lot of gas going to come online in this country. It is interesting for us to have one of these data points if it is good all the way down here for us to understand that early on.

Scott Hanold - RBC Capital Markets

Thank you.

Operator

We’ve a follow-up question from Joe Allman from JPMorgan.

Joe Allman - JPMorgan

Yes, thank you. Hi, again. In terms of that JV in the Haynesville and Bossier shale, does that JV include just the deeper drilling or does it also include the shallower stuff that you are producing on? Then, is my understanding correct that you are being carried 100% for the first couple wells?

Harold Korell

Yes, that is right Joe. The farm-in block is restricted to just the deep Haynesville/Bossier interval. Then we’ve the larger JV that we are going to pursue all of the targets there that we’ve been looking at. Some Travis Peak, some James Lime and the Bossier.

Joe Allman - JPMorgan

Okay. So you have a larger JV with the same private company or --

Richard Lane

Right.

Joe Allman - JPMorgan

Okay, got you. You are being carried 100% on the first couple wells?

Harold Korell

In the farm-out area.

Joe Allman - JPMorgan

In the farm-out, okay. Then another issue, another question, I think your rig count in the Fayetteville moved up from 19 to 22 and the increment is additional smaller rigs?

Richard Lane

Right.

Joe Allman - JPMorgan

Could you confirm that? Then, do you have any defined plans at this point to add rigs? Would they be horizontal capable rigs? Also just could you comment on just what you are seeing with drill and complete costs? Any concerns you have maybe about the availability of steel and issues like that?

Richard Lane

What was the last one?

Joe Allman - JPMorgan

Just issues related to steel, availability of steel and things like that.

Richard Lane

Well, I can confirm that the incremental additional rigs are the sputter-type rigs, just working and managing our inventory of wells, we need spudded and ready, so that is what the additional rigs are. I do not think we’ve committed to a date that we would add new rigs. Like Harold said, we are working that. We are much better positioned to do it now. Steve mentioned, good point is we are starting to get some more clarity on what the future rigs that you would want out there would look like. Some of that has to do with the type of operations we are doing today and what we think they will be in the future. So, we do not have a number there but that is coming and we can see our way towards doing that. On the steel side, that market is tightening. Obviously, we’ve pretty good inventories in place for the key tubes that we need, probably the tightest area is on the 5.5 inch side in the casing world, and we’ve a pretty good inventory there that we are working at to actually to extend some.

Joe Allman - JPMorgan

Okay. Then just, also on drill and complete costs, could you comment on what you are seeing recently with drill and complete costs?

Harold Korell

Yes, there is a lot of factors there. You saw it go down quarter-on-quarter, and there are some plusses driving it higher and there are some minuses driving it lower. Intuitively, say while you are drilling longer laterals, you completed more wellbore, it seems like it should be going up. That is true, except we’ve counteracting that. We have on the dry hole side of things, we have costs going down because we are getting more efficient and doing them quicker. On the completed well side of things, we are seeing some better pricing and better competition in our play there that are driving discounts higher and costs to complete lower. So a lot of moving parts there but the net-net effect of it is that, we saw the move quarter-on-quarter. Then, we think on the full-year basis and for the third and fourth quarters, we will see those numbers moving up slightly.

Harold Korell

I think I said in mine about $3 million, that is what we are using internally going forward.

Joe Allman - JPMorgan

Okay, very helpful. Thank you.

Operator

Our next follow-up question will come from Gil Yang from Citi.

Gil Yang - Citi

Hi, Harold. I think you touched on this a little bit earlier in talking about the frac density question. However, does the increased density on those fracs necessarily change the spacing? In other words, could you do close your spacing just because you are doing the tighter frac density or not necessarily?

Harold Korell

Well, you could do both. Really the question of the spacing, the perforation clusters along the wellbore is a matter of, as Steve had said, possibly getting higher recovery of the gas within the box that you effect by the fracture itself. In other words, if by spacing those perforation clusters further apart as we’ve been, we are leaving gas unrecovered in between those clusters. Then, it is the right thing to do to, first of all, make the best use of that wellbore and get as much gas as you can nearby it. Then the question just then becomes, does the extension of those fracs go far enough out? Do you drain the gas that was between it, be between that wellbore and the next one, however, far away it is?

The idea would be to move that other one close enough to where you have got the economic case, the best economic case for recovery and economics. That is always going to be affected by where gas price is and everything else. Ultimately, these kinds of rocks will be drilled on tighter spacing, is what it boils down to. Some day you may have wells 10 acres apart or something if gas price is high enough.

Gil Yang - Citi

Okay. However, the tighter frac density does not change the volumetric footprint of each well by itself?

Harold Korell

Yes, it could because if in fact, by having the perforations too far apart, you do not affect the gas in between those perforations along the wellbore. If now you affect it, you have increased the amount of gas that you are coming in contact with. Now, you could have drawn the same box but the point is, you may have not actually been affecting all the --

Gil Yang - Citi

Okay.

Richard Lane

I think if you look at the chart that we published, you are seeing the IPs go up and we said we are think the EURs going up 15% to 20%. We do not think that is because we are getting further out, we think that is because we are giving better recovery from the rock right around the wellbore.

Gil Yang - Citi

No what I was actually wanting to get out is that, the basic answer is the box size if you draw it on a piece of paper it is the same size basically what you are doing.

Harold Korell

If not upside, is that arbitrary drawing is what it amounts to but wherever you draw it, then if you do more perforations along there, you are probably improving the recovery factor.

Gil Yang - Citi

Okay. Then just one point of clarification, the box is actually not smaller than it used to be, whatever that arbitrary boundary was, you are not drawing it smaller?

Harold Korell

It could be, Gil.

Gil Yang - Citi

It could be.

Harold Korell

Again going back to that, if I have a single perforation I am trying to get a long frac wing, I really do not have a box anymore. What I have is a serrated scissor-looking thing that goes back and forth.

Gil Yang - Citi

Yes.

Harold Korell

Hedge trimmer is what it looks like. We are trying to smooth out the hedge trimmer and make more box-like.

Gil Yang - Citi

Okay.

Harold Korell

So, we think from a volume standpoint, we are contacting better rock or more rock closer to the wellbore, but at the same time we are making that hedge trimmer look boxier.

Gil Yang - Citi

So it may actually, the wings may be farther less far out than they used to be?

Harold Korell

Right, right.

Gil Yang - Citi

Okay.

Harold Korell

Maybe, yes. It depends on the volume, it actually depends on the hydraulics of what you are pumping on each date.

Gil Yang - Citi

Right.

Steve Mueller

However, that is the concept that we are looking at and then we will figure out what are spaces.

Gil Yang - Citi

Right, right. Has micro-seismic told you anything about the wing lengths?

Harold Korell

No. I think we’ve talked about that a little earlier, Gil. We haven't confirmed that.

Gil Yang - Citi

All right, great. Thank you.

Harold Korell

You bet.

Operator

Our next follow-up question will come from Mike Scialla from Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

Yes, I just wanted to ask one on the Marcellus, the consensus there seems to be, it'll be a slow point of development, so far as to say it'll be 2012 before you see any real meaningful volumes from that play. Given the lack and sickness of the shale, I do not think it has a chance to be as good as the Barnett. I want to see your thoughts on that?

Harold Korell

Well, everybody's got a different standard for meaningful, but I think we will see meaningful volumes before then. If you are talking about how it would compare and build up a production to the other plays that is not very clear, we know there are some infrastructure challenges there. In terms of the rock itself, we are pretty darn encouraged with what we’ve seen, what we’ve taken out of our vertical wells from a resource standpoint.

Richard Lane

I will add although that there are some other layers of complexity, especially with summer water issues that are in Pennsylvania. The whole industry is trying to doing with those reversals complexity. So the whole industry is trying to figure that out right now but so forth, the bodies that are involved, regulatory bodies are working with us and want to work with us. So, I think it is a little too early to say that it is going to be really slow but there are more agencies, so it takes a little bit of time to get through all those agencies.

Mike Scialla - Thomas Weisel Partners

Okay. Then just one more. On the James Line, you mentioned you might try completing them or use some of the things you have learned from the Fayetteville. How are you completing those wells right now that single, lateral with multi-stage fracs or what are you doing there?

Harold Korell

They are single laterals, they are longer, routinely going out 5000 feet, they drill real well. We are using open hole packer systems there where majority of what we are doing in the Fayetteville is not. So that is our basic well design right now, and doing pretty well. We will just have to look into if anything that we’ve been learning in the other areas is applicable there.

Mike Scialla - Thomas Weisel Partners

Okay. Thank you.

Operator

At this point we’ve no further questions. I would like to turn the call back over to the speakers.

Harold Korell

Okay. Well, just to wrap this up, a couple points of maybe perspective as I think about it. Beginning 2008 I would say that, Southwestern Energy was in not a period of being very aggressive about its capital program. In fact, I would say early in the year, we were holding back to some extent and have increased our CapEx, yet here we are in the second quarter of this year and having a 70% production growth.

Performance is improving in the Fayetteville shale. As you can see from the numbers, the James Lime has contributed to our production actually growing in East Texas and our production is growing in the Arkoma basin. Other just point of perspective to me, production growth, prices where they have been in the first half of the year and asset sales have resulted in us being really in a very lower debt level and improved balance sheet from where we anticipated we would be. Another outfall from the asset sales is, we are actually now having recovered some of the cost that we had invested in the Fayetteville shale acreage. We are set up now with a lower DD&A rate and that is going to be good for a going forward perspective on earnings.

So, we really like where we are and they are encouraged about the rest of this year. The picture as we go forward, which for us probably over a period of time here changes from being one of capital constraint to being one of, needing to generate bunches of ideas here again as a company. So that wraps it up for today. It has been a long conference. This may be one of our longest ones including our hiatus of somehow getting unplugged. So we appreciate you being with us. Thanks.

Operator

This concludes today's teleconference. We thank you for your participation. Have a great day.

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