Southwestern Energy (SWN) 8-K Southwestern Energy Company Q2 2008 Earnings Teleconference

Southwestern Energy Company Q2 2008 Earnings Teleconference

Thursday, July 31, 2008

10am EST

Officers

 Harold Korell; Southwestern Energy; Chairman and CEO

 Steve Mueller; Southwestern Energy; President

 Richard Lane; Southwestern Energy; President, Exploration & Production

 Greg Kerley; Southwestern Energy; CFO

Analysts

 Brian Singer; Goldman Sachs; Analyst  

 Gil Yang; Citi; Analyst

 Joe Allman; JPMorgan; Analyst

 David Tameron; Wachovia; Analyst

 Mike Scialla; Thomas Weisel Partners; Analyst

 Robert Christensen; Buckingham Research; Analyst

 Amir Arif; FBR Capital Markets; Analyst

 Brian Corales; Coker and Palmer; Analyst

 David Heikkinen; Tudor, Pickering, & Holt; Analyst

 Marshall Carver; Capital One; Analyst

 Tom Gardner; Simmons & Company; Analyst

 Scott Hanold; RBC Capital Markets; Analyst

Presentation

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's actually the President of Southwestern Energy now; Richard Lane, the President of our E&P company, and Greg Kerley, our Chief Financial Officer.

If you've not received a copy of the press release we announced yesterday regarding our second quarter results, you can call 281-618-4847 to have a copy faxed to you.

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more detail in the Risk Factors and Forward-Looking Statements section of our annual and quarterly filings with the Securities and Exchange Commission.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Well, 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 1, 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've now moved our full-year production guidance to 181 to 185 Bcfe for 2008, which is an increase of approximately 60% compared to our performance of 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 at midstream and then to Greg Kerley for an update on our financial results.  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 we produced in the second quarter of 2007.  

Production from East Texas was 7.9 Bcfe, 6 Bcfe from our Conventional Arkoma property, 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 and 49 Bcfe, and our fourth quarter will be between 50 and 52.  As Harold said, we expect our full-year 2008 production will range between 181 and 185 Bcfe.

In the first half of 2008, we invested 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 spud 262 wells.  

At July 1, 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 a re-entry to re-entry.  As you may remember, this compares to 16 days to drill a 25 hundred foot lateral just one year ago.

During the first half of 2008, we achieved positive results, testing closer perforation cluster space 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 a 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 costs 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 in the Bradford and Susquehanna counties located in the northeast part of the Commonwealth.  We expect to complete the test wells during the third quarter.  We also plan to drill at least two additional test wells, one of which will be a horizontal well on our acreage by the end of this 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 9 wells in our Midway Field.  We have also begun to drill horizontal wells both at Ranger and Midway, and early results 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 2007.

In the first half of 2008, we invested approximately $78 million in East Texas, where we participated in 23 wells, 12 of which were James Lime horizontal wells.  Production from East Texas was 16 Bcf for the first six months of 2008, up from the 15.1 in 2007.  We hold approximately 100,000 -- 102,000 gross acres in the Angelina River Trend, which consists of several separate development areas where we target the Pettit, Travis Peak, and James Lime formations.  We drilled 18 wells in this area through 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 was approximately 23 million cubic foot per day, including production from five outside operated wells.  

We also announced the signing of the 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale interval in Shelby and San Augustine Counties.  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 for 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 volume, as we reported earnings of $136.6 million, or $0.39 a share, up from $47.6 million, or $0.14 a share, for the same period in 2007.  Our operating cash flow increased to $288 million⁽¹⁾, 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 per Mcf, up from $6.90 in the prior-year period.  

Our lease operating expenses per unit of production were $0.95 per Mcf-equivalent in the quarter, up from $0.73 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 and $0.97 per Mcf-equivalent for 2008, which is up about $0.07 from our previous guidance.  

General and administrative expenses per unit of production were $0.41 per Mcf in the second quarter, down from $0.48 last year.  The decrease was primarily due to the effects of our increased production volumes, which more than offset increased incentive compensation and 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 per Mcf-equivalent for the full year.  

Taxes, other than income taxes, were $0.16 per Mcf in the second quarter, down from $0.21 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 and currently expect our rate to range between $0.15 and $0.20 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.  The 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.

Under full-cost accounting, no book gain is recorded as a result of our sales of oil and gas property.  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 through approximately 736 miles of gathering line.  

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 1, 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've 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've closed on the previously announced sale of our utility.  These proceeds have reduced our debt and will help fund our 2008 capital program.  

At June 30, 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 now we'll turn it back to the Operator, who will explain the procedure for asking questions.

Questions and Answers

Operator: Thank you.  [OPERATOR INSTRUCTIONS]

Our first question will come from Brian Singer from Goldman Sachs.

Brian Singer: Thank you very much.  Good morning.

Harold Korell:  Morning.

Brian Singer: When you think longer term over, let's say, 2009/2010, how do you see the balance sheet playing out?  You've obviously -- you just highlighted a number of the asset sales that you've 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 the Fayetteville gets into a position where you can continue to grow, maybe take up the net debt to 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's becoming less of a variable to us, we know our production volumes are growing substantially, as you can see from the information that we have been presenting over the last few quarters, in the Fayetteville Shale.  

And, of course, the other variable is what would be our investing -- we don't 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 have 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 have looked to annex it 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 in 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 re-deploy 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 a disclaimer and backdrop, the future will depend upon gas prices and will depend upon the idea generation activities we have internally, it will depend on how our Marcellus turns out, whether something develops on that acreage where someone's going to drill a couple wells for us in Haynesville.  There's just so many moving variables.

But 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.  And no small factor is the way our production volumes are growing.

Brian Singer: And I guess when you think about the activity level in Fayetteville, is there some high gas 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 kind of organically drilling more wells there by the fact that our wells are drilling in less time, and therefore, with the rigs that we currently operate we are drilling more wells there just with the same number of rigs.

We are looking at--we're looking at when should we put more drilling rigs out here.  And we're analyzing that continuously.  As I've talked about this in the past, one of our things that we've had to balance is to make sure that when and if we do put more drilling rigs in the Fayetteville, that we have 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 have the feeling of what it was like during '06 and early '07 when we put all of those rigs online and some of our results weren't as good because we just didn't have the people to be analyzing all of the information flow that was coming back at us.

And I would tell you that we're getting--we're a lot better positioned to add rigs now than we have been.  And with 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 something that would affect the 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.

But I think--should you expect us to add rigs there?  Yes.

Brian Singer: Thanks.  And if I could get one more, one very quick one.  It looked like in the second quarter your average IP in the Fayetteville was 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:Steve or Richard, would you like to--?

Steve Mueller: - --Brian, this is Steve Mueller.  I think it's really just statistics.  We've looked at those wells in a lot of detail and a lot of different ways.  And you're just not seeing all the wells.  And when I say statistics, these wells you've got to remember are drilled over several square miles, so they're not drilled--this isn't a development program.  And each area has got a little different characteristics to it and it's just how you drill the wells.  Those numbers will go up I think as you'll see next quarter.

Harold Korell: And I think the other thing to say, Steve, is that some of the wells--well, the wells that have a full 60 days, let's just stop and talk about how the numbers work.  We drilled--what is it--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're seeing--and when we looked back, as I--obviously, I--that didn't go without notice here either--is that some of the wells that we drilled early on in the quarter had--which now represent the wells that have 60 days of production, those wells when you go back and look at them had lower IP.  So there's a grouping of wells there that weren't as good and we drilled early in the quarter.

Brian Singer: Thank you.

Operator: We'll move on to our next question.  Our next question will come from Gil Yang from Citi.

Gil Yang: Hi.  Could you comment on--Greg, maybe, can you comment on the percent per Mcf effect of the asset sale on the DD&A in the quarter?

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

Gil Yang: And just following up on that, as you add new volumes to the full cost--what is the fair DD&A rate of the new reserves that you're adding to that pool?  Is it in the 2.50 sort of range?

Greg Kerley: It's lower than that, obviously, because besides the effect of the sale, the rate's hanging in there a little over $2 right now - $2.01.

Gil Yang: No, no, no.  That's what's on the income statement.  I just mean that as--okay, so as you drill new wells you're still adding them and sort of you take the $3 million divided by a little less than 2 Bcf per well.  Is that the right--?

Greg Kerley: - --That's correct.  I mean, correct right now.  It will depend on what we--ultimately our bookings are for the year for those wells, what our reserve revisions are from the prior year.  And it's--I think the $2 right now based on what we're hooking 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:But when 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--completed and hooked up, or are there additional pipeline costs in 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--it's not just the total drilling and completion costs on an individual well basis.

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

Harold Korell: Well, Gil, if you're just isolating the Fayetteville, then you can talk about those numbers.  But our finding costs, like what we reported last year and how it's looking this year, is kind of your best guidance towards any quarter what's happening.

Gil Yang: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 of that was for drilling--spudding wells and drilling.  So there was an incremental capital investment that would go into that DD&A pool on top of that.  And as Richard said, each of the areas has those kinds of investments besides [inaudible].

Harold Korell: But I think the interesting thing to stop and think about here on this is that our 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.  And 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're seeing now is a hell of a nice basis to be at as a company.  It has to be one of the lowest that's even out there.  And the change, which you're 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's just simply you back that out of the depreciable base and it had a $0.35 to $0.40 impact on the DD&A rate.  Now, you're going to--as you guys think about other companies, you need--you're going to be thinking about that happening to a bunch of other companies right now who have accumulated acreage at 100--like ours.  We're--the good fortune we have is that--and we've been saying this all along--is that our cost basis on this matters.  And we have a very low capital investment on the land we have in the Fayetteville Shale and now we've sold just 5% of it and actually--so that's been recovered and the depreciable basis down.  And so, it's going to affect our DD&A rate.  That's going to have a positive impact on earnings and on retained earnings and it just blows on through.

Gil Yang: Okay.  Fair enough, Harold.  And my second question, just wrapping up on the acreage, you say you're going to drill behind your 3D going forward.  What leasehold issues do you have to hold leases and does that--does the drilling behind the 3D sort of reflect that you held everything, or does it mean that you have enough of a [clock] that you don't need to worry about it for now?

Harold Korell: Oh, we have--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 don't intend to lose acreage that we want to hold.

Gil Yang: Okay.  So the 3D does cover some new areas?

Harold Korell:Oh, yes.  Yes.

Gil Yang: Okay.

Harold Korell: I think the good thing, Gil, is that we're not being led around by the lease exploration schedule.  We've gotten ahead of that.  We're managing it instead of it managing us, so--.

Gil Yang:--Great.  Okay.  Thank you very much.

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

Joe Allman: Yes.  Good morning, everybody.

Steve Mueller:Good morning, Joe.

Joe Allman: Hey, Greg, could you talk about what you're expecting for current taxes for the third quarter and the fourth quarter?  And then, what you're expecting--when do you expect to start?  And I'm assuming that the current taxes for the rest of the year are related to the asset sales.  And then, what do you expect in kind of--when would you expect to start paying current taxes on an ongoing basis?

Greg Kerley: Joe, that's one of those multi-variable points, too.  This year we do--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 min taxes for some of those sales.  Whether we pay current taxes or not will really be driven more by what gas prices are for now till 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.  But 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're aware, a large portion of our capital investments are deductible in the current year--the intangible drilling cost portions of them.

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

Joe Allman:Okay, that's helpful.  Thanks.  And then, the second question is either Steve or Harold or Richard.  Could you just describe that cluster--perforation cluster method that you're now using for your fracture stimulations?

Steve Mueller: I can start talking about it a little bit.  Thinking historically about fracture stimulation, there's kind of two issues that you always worry about.  It's how much energy you're going to put in the ground and how you're going to disburse that energy when you put it in the ground.  Historically, you put very few perforations and a lot of energy and you try to make a single frac wing go out a long distance.  What we're doing is trying to break up more rock than having--rather than just a single wing.  And the way you do that is spread your perforations out and distribute that energy that's going into the ground.  And that's the perf cluster part of it.  And then, [till you] encounter more rock, you need to do more of those clusters along the well bore.  And how much energy you put in the ground may take several times to do that.  So we'll have several stages.  

And we've increased the number of stages from 5 to 9 to 10, 12 range on stages.  That's how many times you actually frac.  And then, we've also put those clusters closer together.  And the whole concept there is just bust up more rock near the well bore.  Now, that also works back into your spacing.  If you're not making fracs [inaudible] and you're busting up more rock near the well bore, then you might need to have tighter spacing.  So we're working on both of those issues at the same time as we go through it.

Joe Allman:Okay.  Very helpful.  Thank you.

Operator: Our next question will come from David Tameron from Wachovia.

David Tameron:Good morning.  A couple of questions.  Can you give me--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's a number you've got to chase down and get back to me on.  That's fine.

Harold Korell:Well, the last 12 months would be, because we probably don't have that.

David Tameron:Okay.  And the number for this year is still targeted the same that you have in your presentation, that 1.--?

Harold Korell: - --Yes.

David Tameron:Okay.  And second question, have you guys--and it's 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 come--I realize it's 18 months down the road.  But any initial take on those changes?

Harold Korell:Well, I mean, in general, I think it's--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 [inaudible] 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 year-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 that most of the industry players have made.  Then the other one, of course is, if, in fact, they give you the option of reporting probable and possibles, then we’d have to look at all of those numbers and figure out what we can put there, and that’s going to create huge variability, I think, on most -- how companies deal with that.  But I think generally I think that what they’re proposing is generally really quite good because I think that it will make more transparency and clarity to what the real reserves are, strictly behind these resource plays, relative to the rules that have been kind of artificial in the past.

Steve Mueller:  The other thing I’d add, Harold, is that the question also asks the effect for the end of this year, and I don’t think it’s clear whether these things would be in -- these rules would be in place by then and whether they would affect year-end reserves or not.

David Tameron: And then from a borrowing basis, they’d loan on PDP, so it really shouldn’t have an impact on that, correct?

Greg Kerley: Well, this is Greg.  One of the benefits of Southwestern Energy, we don’t have a borrowing base.  Our credit facility is an unsecured facility, so it has no impact on what our borrowing is, our borrowing ability.

David Tameron: All right.  Thanks.  Nice quarter.

Greg Kerley: Thank you.

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

Mike Scialla: Hi, guys.

Harold Korell:  Hi, Mike.

Greg Kerley: Hi.

Mike Scialla:  It looks like the last 150 Fayetteville wells you’ve added online, you’ve 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’ve learned there that’s led to that kind of improvement?

Harold Korell:  Lots of things, Mike, and it’s nice to see that being noticed.  I’m sure our operational teams would appreciate that and our drilling guys in particular.  But we’ve smoothed out a lot of things and a lot of it has to do with our -- with our drilling practices.  We’re having a lot less trouble with some problematic intervals above the curve.  That’s 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’re using in both those parts of the hole, which kind of set the stage for the completion part of the hole running smoother, smoother holes, less dog legs, all those kind of problems, less sidetracks.  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’re staying in our zone much more -- most of the wells we’re able to stay in zone more consistently than without that data and also steer the wells better.  So all those things kind of coming into play and our completion methods as well, how we’re doing the wells, are all having a positive effect on that.

Mike Scialla:  Do you think that one out of 150 kind of number is sustainable or is it -- is that just an anomalous kind of situation?

Harold Korell: Well, I don't know what the exact number is.  But we just keep striving to smooth out our operations and learn from what we’ve done in the past.  And we have a high amount of our wells in areas that we’ve already drilled, so we have some benefit of that as well.

Mike Scialla:  And then just --

Harold Korell: But as we step out in new areas, I’m sure we’ll learn some things also.

Steve Mueller: Mike, we’re on a steep learning curve, as you can see with the base 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’re learning fast.  I’m very comfortable we can continue that learning curve.

Mike Scialla: And I just wanted to ask, on -- based on the current price and cost environment, can you give some sense, maybe 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: That’s a pretty good number.

Harold Korell:  We don’t know -- we don’t know enough to say we don’t want to drill on any of it, Mike.  But we also don’t know enough to say we want to drill on all of it.

Mike Scialla: Right.

Harold Korell:  That’s the way I have to answer that.

Steve Mueller: Yes, we certainly haven’t condemned any broad areas, Mike.  And back 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’s all -- it’s all up for development.

Harold Korell:  The question and the area that we probably know least about is on, if you guys remember our map, is that area that lobs off over and up and to the west, which a lot of it’s federal acreage that we’re beginning to put our plans together on.  It’s long-term leases.  And so we haven’t done very much over there.  We don’t know a lot about that.  But we know that the section is present.  That area we just haven’t done very much off that.

Mike Scialla: Okay.  Thank you very much.

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

Robert Christensen:  Hi, guys.  Overton field.  It seems to have been lost in the minds of many.  What’s the future there?  It was a big part of your company awhile back.  Are we experiencing a loss of output in the field or is there new technology that you apply up there?

Richard Lane: Bob, I --

Harold Korell: Go ahead.

Richard Lane: Sorry, Harold.  Certainly -- certainly isn’t lost by us.  It’s been a tremendous asset and continues to be a tremendous asset.  Some day when we’re done drilling there, it’s a huge cash cow for us, and - -- so we are -- we have one rig working over there right now.  Some of the things still left to do there are, we did do a horizontal well there that tested about eight million a day and producing pretty darn well.  Now looking at doing some more of those there in the second half of the year.  So perhaps there’s some more of that to do based on the performance of those wells.  

And also that our East Texas Team has been adding new assets and backfilling our opportunity set with new things and new production coming from them, so.

Robert Christensen: 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’m very encouraged to hear these kind of results.  More horizontals to do there?

Richard Lane:  Well, I think it’d be just what I said, it’s going to depend on how these next few go.  And there’s some more potential for there, but I’m not really prepared to quote you a number of how many we might could do.

Robert Christensen: My second question, coming back to the, I guess conventional above and below the Fayetteville.  I think I asked it last quarter, and you said it would be back-half loaded drilling for the Hale and the Ore and might it be maybe sometime Arbuckle.  What are your plans there, because that excites me.

Richard Lane: Yes, we -- 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 used -- 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’ll have a bigger push there for that.  There’s certainly good potential and proven potential in the token section.  We’ve seen some really nice producers there that we’ll keep pursuing, as well as the deeper section.

Robert Christensen: Thank you, Richard.

Richard Lane: You’re welcome.

Operator:  Thank you.  Our next question will come from Amir Arif from FBR Capital Markets.

Amir Arif: Morning, guys.  And, first of all, congratulations on a great quarter.  First question is, can you give us -- can you give us some more color on the results you’re seeing from your multi-well pad drilling?  I know you started talking about it last quarter.  I just want to see what you think of it today.

Harold Korell: Well, we’re seeing a -- we’re seeing a cost savings and a greater number or percent of the wells that we’re doing in 2008, because it is going well, that 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 a 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’ll keep pursuing that.

But we’re seeing some savings there.  I don't think we’re seeing all that ultimately we might see there.  But so far it’s going pretty well.

Amir Arif: So the primary benefit is -- has been the cost savings?  You’re not really seeing as much synergies between the wells?

Harold Korell:  Well, the synergies, what we’re seeing is centralization of lots of things.  And economies scale on the surface operations.  For example, we have less lease roads, miles of lease roads to get to the same amount of roads.  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’s all those things, Amir, that are coming into play.

Amir Arif: Okay.  Second question.  On the production numbers, you currently have 500 million a day gross.  Where do you see that being at the - -- by the end of the year?

Harold Korell: Yes.  I don’t think we’ve -- you’re -- I’m talking about the Fayetteville Shale there.  We  --

Amir Arif: Yes.

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

Amir Arif: Sounds great.  Thanks.

Operator: Our next question will come from Brian Corales from Coker and Palmer.

Brian Corales:  Hey, guys.  Just a couple quick ones.  Harold, you talked in the past about accelerating one of the big impediments was really people.  Is that still the case?  I mean, the balance sheet’s much better than it has been.  Just kind of curious on what the big hindrance is that could be for accelerating further in the Fayetteville?

Harold Korell: Well, I think we always have to look at the overall environment that we’re in.  One of the things, somebody asked a question about a few minutes ago was the lack of real serious problem mechanical wells in the Fayetteville Shale.  And I think what you’re seeing there is the result of being patient about getting our organization up and running right so that we have efficiency in what we’re doing, not just going faster and not gaining all that efficiency.  That’s what we’ve been looking for, being able to understand the information flow we’re getting back out of our wells about how we’re tracking them to know we’re doing that right.  I think get to the point where we’re 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’s not a capital issue for us right now, and we just want to do it in a workmanlike manner, I guess, and in the right way.

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

Brian Corales: And just one more on the asset sale 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?

Harold Korell: Well, we normally wouldn’t comment on something we hadn’t announced like that.  But so I guess maybe that’s the company line on that.  We don’t have anything pending right now.

Brian Corales: Okay.  Well, thanks so much.

Operator: Our next question will come from David Heikkinen from Tudor, Pickering, and Holt.

David Heikkinen: Good morning.  Just thinking about the Fayetteville development.  Wanted to hit first on the pilots for perf clusters and spacing assumptions.  What should we think about?  Can you walk us through out how that’s going to be oriented, number of wells per section, or what you’re thinking there?

Richard Lane: Well, on the perf clusters, as Steve reported, we’re watching the production from the first 38 that we’ve done.  We’re real encouraged what we’re seeing there.  And those rates are holding up, so it’s not just an early time phenomenon.  But we’ll keep -- we’ll keep watching those and pursue doing those on most or all the wells that we have left for the year.  

Additionally, I think we reported that we’re -- the other part of the equation that Steve did mention is that you can effect all this with two different geometries, one up and down the well bore and one how close the well bores are together.  So the perf cluster spacing is attacking the -- up and down the well bore.  And the second one we reported we’re going to start testing well bores being closer together.  So --

David Heikkinen:  So will those be still north-south oriented similar to the rainbow pilot where you’re then just filling in between those wells and still drilling an east-west well on kind of the northern and southern boundary?  That’s what I was trying to get to.

Richard Lane: Yes.  Yes, David, I think that that’s the general pattern we would have in mind right now.  And it’s 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 - --

David Heikkinen: Right.

Richard Lane:  -- going back --

David Heikkinen: -- and infilling.

Richard Lane:  -- and infilling.

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

Richard Lane: Well, most of our well bores right now are 1,000 feet apart or greater.  And then we have some regulatory -- we talked about this yesterday.  We have some regulatory limitations right now that with 560 feet between well bores, not that that would -- if some day a development warranted more than that, I think that’s something you could work with.  But right now, that’s kind of the sideboards on it.

David Heikkinen:  Okay.  That helps me visualize it.  And 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’ll turn this over to Steve and Richard.

Steve Mueller: Yes.  I will say part of the re-entry to re-entry is just how far the wells are apart that you’re going to.  Do I just get a well?  Do I have to move it several miles to get to the next location?  When you start talking about our demo area, we have 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 on a very -- just learning, as they were on a demo area.  So we know we can get it somewhat lower in the right conditions.  But across the entire play and what is actually going to average, there’s a -- there’s a lot that goes into that.  We’re still opening --

David Heikkinen:  Right.  No, just thinking about -- that’s 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’s going up a little bit from what our previous guidance was.  I think we’re -- obviously, we had our strong second quarter.  It’s going to be really dictated, obviously, by the Fayetteville Shale production volumes.  Right now we’re at 50 to 55 million is the guidance out there, but it could go up a little bit from that if we continue to kind of see the build that we’re seeing the first half of this year.

David Heikkinen:  Okay.  That’s helpful.  Thanks.  That was it.

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

Marshall Carver: 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’s the timing on those?  Hello?  Hello, hello?

Operator: And stand by.  It looks like we’re having some audio issues.  We’ll be back --

Marshall Carver: Hello?

Operator: -- momentarily.

Marshall Carver: Hello?

[Technical difficulty]

Operator: And this is the operator again.  If the last person that was asking a question could press star one on their telephone again to queue up for questions, we’ll move on -- back to our question from Marshall Carver from Capital One.

Marshall Carver: The Haynesville wells, are those going to be vertical or horizontal wells?

Richard Lane:  Marshall, I think we just caught part of your question, but I think we’ve got the crux of it.  I don't think it’s totally determined yet what those first wells will be.  We’re still kind of programming, programming that.  The -- ultimately we want to -- want to try the horizontals obviously.  But we’re still working on that program.

Marshall Carver: Then what was the logic behind doing a JV?  Did the private company have expertise in that or something?

Richard Lane:  There was -- there were several things.  They did bring some expertise and some regional work that kind of leap-frogged us forward in our -- in our understanding there on the play.   I will tell you it’s a pretty darn big step out from where the known activity and the well tests have been reported.  So certainly significant risk there, and we’ll get a look at it -- the leverage of the deal there, we’ll get a look at those wells.  And then if it -- if it works out, then we’ve got a real nice partner there in place to kind of pursue it.

Marshall Carver: Okay.  Thank you.  And 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?

Richard Lane: They were probably somewhere in the 90% on that, Marshall.

Marshall Carver: Okay.  That’s all.  Thank you.

Operator: Thank you.  We’ll move on to our next question.  Tom Gardner from Simmons and Company.

Tom Gardner: Good morning, everyone.

Harold Korell:  Hi, Tom.

Greg Kerley: Morning.

Tom Gardner: Hey, Harold, we’re hearing reports of pipeline and infrastructure constraints and these prolific resource plays.  With the stellar growth you’re having in the Fayetteville, can you discuss the pinch point for activity both in production as well as activity?

Harold Korell:  Well, that’s 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 doesn’t get completed as scheduled in their first leg of that.  We don’t see that as a huge restriction on us achieving our objectives, but there could be some period there if they don’t 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 of ’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’s kind of a bigger question than I can completely answer for you.

Tom Gardner: Well, jumping over to the East Texas James Lime.  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 sort of spacing reserves cost do you have going forward?

Richard Lane:  Well, Tom, this is Richard.  We, obviously, haven’t fully delineated it.  We can see really all the acreage we have there, I would feel good about saying, certainly, it’s perspective.  And but it’s another stretch to say proven.  We’re not there yet.  But there’s a -- there’s a lot of potential there, probably north of 100 wells, given our acreage base.  I don't think we know the spacing yet, so the -- that numbers going to move around with that.  We’ll probably try some of the same things that we’re talking about in the Fayetteville there as well, although we are -- we are dealing with a different reservoir.  

So a lot of potential.  We’ll stay busy there in the rest of the year.  The good news is, even in the areas that are the low rates that we have seen, we still look like we have a play to pursue there and then we’ve had -- we’ve had some areas with really, really high rates.  So a lot of potential there.  It’s kind of hard to quantify entirely right now.

Tom Gardner:  All right.  Well, thank you very much, guys.

Richard Lane: Thank you.

Operator: We’ll move on to our next question from Scott Hanold from RBC Capital Markets.

Scott Hanold: Yes.  Good afternoon, guys.  Question going back to sort of the closer perforation clusters, because this obviously looks pretty -- seems to be pretty significant for you guys is you can increase, obviously, the size of the wells with the 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 well bore versus reaching out as far?  And also, could you talk about is this done elsewhere to a great extent?  Or how did this sort of process come about?  Is it something that you’re just testing out and it sort of worked?

Richard Lane: I think when you think back, Steve kind of framed it really well, I think, early on there.  When you think back about the early times, you -- and terminology like limited entry, you can have a stage you wanted to -- you wanted to pump into, and so you’d have a small amount of perfs spaced out to a great degree, so that 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’re doing here is we’re saying, let’s take that same stage and let’s pump basically the same amounts of volumes, but let’s have the -- 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 those is yes and yes.  I don't know that we’ve micro-sized enough of those kind of wells to really say we can define a change in the -- in the half length of those fracs or not.  But that’s part of what needs to get done as well.

Scott Hanold:  Okay.  And how did -- how did it come about doing this?  Is this done like in a Barnett as well or is it something you were just sort of playing around with in the Fayetteville?

Richard Lane: No, there’s certainly some Barnett players, depending which part of the Barnett you’re in or trying to do this.  There’s also some work being done on the Woodford that’s used some of these clusters.  But really, from our perspective, it’s just trial and error.  We started it, looked like we’re 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’re at about 75 foot apart on that, those perforation spacings.  So you’re not going to see that go down too much more.  We’re pretty close together right now.

Scott Hanold:  Okay.  And how simul fracs, have you done enough testing on that where this clusters, closer clustering may be better than doing simul fracture?  Can you do that simultaneously?  You know, both of those in conjunction with each other?  And so what are your thoughts there?

Steve Mueller: We’re -- we have done a little --some simul fracs.  Jury’s still out on the benefit of what they’re going to do for us.  We will be doing some more of those along with this, as I said, it’s a series of things go with it, the spacing, how many wells you’re fracing at one time, the simul frac and that all goes together, and we’ll be trying that and just continuing to -- it’s a continuous improvement-type project.  And we’ll just continue to do that.  

We don’t expect for you to get a magical answer anytime soon.  It’s just one of those things we just keep improving.  If we run into some where it’s not improving, we’ll try something else.

Scott Hanold:  Okay.

Harold Korell: This question is -- I think Steve’s done a pretty good job here this morning of kind of opening up and trying to paint a verbal picture.  It’d be 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 well bore if you could.  And so placing perforation clusters closer together is about contacting more rock.  And Richard had said up and down laterally along that well bore, 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 well bore as you could.  

And 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.  And then by pumping the energy in, it’s only going to go out a certain distance from the well bore.  And under the old limited entry, you’re trying to create long, linear fractures.  That kind of goes back to conventional wisdom about how to fracture [stimulate] rocks.  You try to go out as far as you can.  But if, in fact, you think about it this way, we don’t probably have a lot of profit out there in those long fractures.  We may actually create a long fracture and not have much conductivity of it.

Scott Hanold:  Yes.

Harold Korell: And so what you -- a better answer may be clusters closer together along the lateral and then well bores that are spaced closer together.  And then the ultimate answer would be, if you could do it, you would take -- you would take two townships of land, drill all the wells, put all the world’s front trucks out there and probably pump energy into it and break it all up like one day.  But, of course, you can’t do that.

Scott Hanold: Right.

Harold Korell:  You have practical limits on how much horsepower you can put out, when the wells are drilled and all that.  And so the answer on simul fracs is -- you know, really the question on simul fracs, how many simul fracs to do at one time, if that was the way to do it.  But there are real world limitations on some of this.  Maybe the reason we don’t -- haven’t seen real improvement in simul fracs is we’ve got our wells spaced too far apart and they haven’t really impacted each other in a way that they would.  On the other hand, from some of our technical folks meeting with some other companies, we’re not hearing the 100% consensus that simul fracs are benefiting always either. 

So there’s a lot going on here and we’ll just continue to increment our way along.  Good news is we’re making progress on it.

Scott Hanold:  I appreciate that color.  And one quick one, going back to the Haynesville and to you gave a little bit of color there.  Is there anything in particular you saw on your acreage, like an older well log that may have touched it that got you interested or is this more of, hey, there’s a lot of industry activity there and we’re going to test it, but at this point that’s about all you know?

Harold Korell:  Well, reality for us is that most of that activity is several tens of miles away from us that’s been going on -- if you had to come right inside a Southwestern interview and say, “How do you feel about it?”  Our acreage is, and we’ve commented on this each time we’ve been asked, we -- the answer is we don’t know because we’re quite a ways away.  But if you had to ask our technical team, they’re not -- they’re not real high on our acreage.  As to the Haynesville potential, if we thought it was a lay-down 100% thing, we’d probably invest our own money in drilling.  And so here we have a chance of someone coming in and putting some of their dollars into it.  And if it works, that’s great, because we’ll have half of whatever it is on the acreage that we have committed to the deal, and they’ve brought some acreage.  And it’s with a quality group of people who can focus 100% on making it work.  So that’s kind of our thinking on it.

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

Harold Korell:  No, we’re being carried on the cost early on.

Scott Hanold: Okay.  All right.  Thank you.

Richard Lane: Let me just add that you asked about do we have any information nearby.  There are a couple 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 which well you’re looking at.  And as you’d expect, that far away, there’s some similarities, but there’s also a lot of differences.  So that’s why we say we just don’t know.

Harold Korell: As we would -- looked at our plan, we wouldn’t be drilling these wells right now with our money.  That doesn’t mean they shouldn’t be drilled.  Just one kind of interesting comment, and I think it goes back to the question Tom Gardner asked was, what about all this gas.  Well, if the Haynesville is good here, then we’ve got a heck of a lot of gas going to come online in this country.  And it’ll kind of be interesting for us to have one of those data points if it’s good all the way down here, for us to understand that early on.

Scott Hanold: Thank you.

Operator:  We have a follow-up question from Joe Allman from JP Morgan.

Joe Allman: Yes.  Thank you.  Hi again.  The -- in terms of that JV and the Haynesville and Bossier Shale, does that JV include just the deeper drilling or does it also include the shallower stuff that you’re producing on?  And then is my understanding correct that you’re being carried 100% for the first couple wells?

Richard Lane:  Yes, that’s right, Joe.  The farm-out block is restricted to the - -- just the deep Haynesville-Bossier interval.  And then we have a larger JV that we’re going to pursue all of the -- all of the targets there that we’ve been looking at, some Travis Peak, some James Lime, and the Bossier.

Joe Allman: Okay.  And you -- so you have a larger JV, with the same private company or?

Richard Lane: Right.

Joe Allman: Okay.  Got you.  And you’re being carried 100% on the first couple wells.

Richard Lane: On -- in the farm-out area.

Joe Allman: The farm-out, okay.  And 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: Could you confirm that?  And then do you have any defined plans at this point to add rigs and would they be kind of horizontal-capable rigs?  And also, could you comment on just what you’re seeing with drill and complete costs and your -- any concerns you have maybe about the availability of steel and issues like that?

Richard Lane: What was the last one?

Joe Allman:  Just issues related to availability of steel and things like that.

Richard Lane: Well, I can confirm that the incremental additional rigs are the spudder-type rigs, just working and managing our inventory of wells we need spudded and ready.  So that is what the additional rigs are.  I don't think we’ve committed to a date that we would add new rigs.  Like Harold said, we are -- we’re working that.  We’re much better positioned to do it now.  Steve mentioned a good point is we’re starting to get some more clarity on what the future rigs that you would want out there would look like, and some of that has to do with the type of operations we’re doing today and what we think they’ll be in the future.  So we don’t have a number there, but that’s coming and we can see our way towards doing that.  

And on the steel side, that market is tightening, obviously.  We have 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 have a pretty good inventory there that we’re working at it to actually to extend some.  

Joe Allman:  Okay.  And then just also on drill and complete cost, could you comment on what you’re seeing recently with drill and complete costs?

Richard Lane: Yes, there’s a lot of -- there’s a lot of factors there.  You saw it go down quarter-on-quarter.  And there’s some pluses driving it higher and there’s some minuses driving it lower.  Intuitively, you’d say, well, you’re drilling longer laterals and you’re completing more well bore, seems like it should be going up.  And that is true, except we have, counteracting that, we have, on the dry hole side of things, we have [props] going down because we’re getting more efficient and doing them quicker.  On the completed well side of things, we’re seeing some better pricing and better competition in our play there that are driving discounts higher and cost 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.  And then we think on the full-year basis and for the -- for the fourth quarter -- third and fourth quarters, we’ll see those numbers moving up slightly.

Harold Korell:  I think I said in mine about $3 million.  That’s what we’re using internally going forward.

Joe Allman:  Okay.  Very helpful.  Thank you.

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

Gil Yang: Hi, Harold.  I think you sort of touched on this a little bit earlier in talking about the frac density question.  But does the increased density on those fracs necessarily change the spacing?  In other words, could you do closer spacing just because you’re doing the tighter frac density, or not necessarily?

Harold Korell: Well, you could do -- you could do both.  But really the question of the spacing the perforation clusters along the well bore 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 have been, we’re leaving gas unrecovered in between those clusters, then it’s the right thing to do to, first of all, make the best use of that well bore and get as much gas as you can nearby it.  And then the question just then becomes does the extension of those fracs go far enough out and do you drain the gas that was between it -- be between that well bore and the next one, however far away it is.  And the idea would be to move that other one close enough to where you’ve got the economic case, the best economic case for recovery and the economics.  And that’s 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.  And some day you may have wells 10 acres apart or something if gas price is high enough.

Gil Yang:  Okay.  But the -- but the tighter frac density does not change the volumetric footprint of each well by itself?

Harold Korell: Well, yes, it could, because if, in fact, by having the perforations too far apart you don’t affect the gas in between those perforations along the well bore and if now you effect it, you have increased the amount of gas that you’re coming in contact with.  Now, you could have drilled -- you could have drawn the same box, but the point is, you may have not actually been affecting all --

Gil Yang:  Okay.  Okay.  Yes.

Richard Lane: And I think if you look at that chart that we published, you’re seeing the IPs go up and we said we’re seeing -- we think the EURs go up 15 to 20%.  We don’t think that’s because we’re getting farther out.  We think that’s because we’re getting better recovery from the rock right around the well bore.

Gil Yang: No.  What I was --

Greg Kerley: So what --

Gil Yang: -- actually getting more getting at is that -- yes, okay.  But the basic answer is the box size, if you draw it on a piece of paper is the same size, basing on what you’re doing?

Harold Korell:  Box size is an arbitrary drawing is what it amounts to.  But wherever you draw it, then if you do more perforations along there, you’re probably improving the recovery factor.

Gil Yang: Okay.  And but I guess then just to -- one point of clarification.  The box is actually not smaller than it used to be?  Whatever that arbitrary boundary was, you’re not drawing it smaller?

Harold Korell:  It could be, Gil.

Steve Mueller:  Could be.

Gil Yang: It could be, okay.

Steve Mueller: Again, going back to if I have single perforations and I’m trying to get a long frac wing, I really don’t have a box anymore, what I have is a serrated kind of scissor-looking thing that goes back and forth.

Gil Yang:  Yes.

Richard Lane: A hedge trimmer.

Steve Mueller: Yes, a hedge trimmer is what it kind of looks like.

Gil Yang:  Yes.

Steve Mueller: And we’re trying to smooth out the hedge trimmer and make it more box-like.

Gil Yang: Okay.

Steve Mueller:  And so we think from a volume standpoint we’re contacting better rock -- or more rock closer to the well bore.  But at the same time we’re making that hedge trimmer look more boxy.

Gil Yang: So it may actually -- the wings may be farther -- less far out than they --

Steve Mueller:  Right.

Gil Yang: -- used to be?

Steve Mueller:  Right.  

Greg Kerley:  It may be.

Gil Yang:  Okay.

Richard Lane:  It may be.

Harold Korell: It may be, yes.  It depends on the -- it actually depends on the hydraulics of what you’re pumping on each state.

Richard Lane:  But that’s the concept that we’re looking at.  And then we’ll figure out what the spacing is.

Gil Yang:  Right.  Right.  Has Micro Seismic told you anything about the wing length?

Harold Korell:  No.  I think we talked about that a little earlier, Gil.  We haven’t confirmed that.

Gil Yang:  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: Yes.  Just wanted to ask one on the Marcellus.  Seems the consensus there seems to be it’ll be a slow play to develop and I think EOG went so far as to say it’ll be 2012 before you see any real meaningful volumes from that play and given the lack and thickness of the shale, they don’t think it has a chance to be as good as the Barnett.  I wanted to see your thoughts on that.

Harold Korell: Well, everybody’s got a different standard for meaningful, I guess.  But I think we’ll see meaningful volumes before then.  If you’re talking about how it would compare in the buildup of production of the other plays, that’s not very clear.  We know there’s some infrastructure challenges there.  In terms of the rock itself, we’re pretty darn encouraged with what we’ve seen, what we’ve taken out of our vertical well, from a resource standpoint.

Richard Lane: I will add, though, that there are some other layers of complexity, especially with some of the water issues that are in Pennsylvania.  And we - -- our acreage is within those areas where there’s those complexities.  So the whole industry’s trying to figure that out right now.  

But so far the bodies that are involved, regulatory bodies, are working with us and want to work with us.  So we -- I think it’s a little too early to say that it’s 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:  Okay.  And then just one more on the James Lime.  You mentioned you might try completing them or use some of the things you’ve learned from the Fayetteville.  How are you completing those wells right now?  Is it single lateral with multi-stage fracs, or what are you doing there?

Harold Korell:  They’re single laterals.  They’re longer.  We’re routinely going out 5,000 feet.  They drill real well.  We’re using open-hole packer systems there, where the majority of what we’re doing in the Fayetteville is not.  So that’s our basic well design right now, and doing pretty well.  And we’ll just have to -- we’ll just have to look into the -- if anything we’ve been learning in the other areas is applicable there.

Mike Scialla: Okay.  Thank you.

Operator: And at this point, we have 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, or 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 -- 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 and actually growing in East Texas and our production’s growing in the Arkoma basin.  

Other just point of perspective to me, production growth, prices where they’ve 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.  And another outfall from the asset sales is we’re actually now having recovered some of the cost that we had invested in the Fayetteville Shale acreage, we’re set up now with a lower DD&A rate and that’s going to be good for a going-forward perspective on earnings.

So we really like where we are and are encouraged about the rest of this year and the picture as we go forward, which, for us, probably over a period of time here changes from being one of capital constrained to being one of needing to generate bunches of ideas here again as a company.

So that wraps it up for today.  It’s 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: And this concludes today’s teleconference.  We thank you for your participation.  Have a great day.

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

	3 Months Ended June 30,
	2008		2007
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	288,230	$	146,783
Add back (deduct):
Change in operating assets and liabilities		2,935		(16,976)
Net cash provided by operating activities	$	291,165	$	129,807