8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): October 24, 2006

SOUTHWESTERN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of incorporation)

1-08246	71-0205415
(Commission File Number)	(IRS Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)

(281) 618-4700

(Registrant's telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

       o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EXPLANATORY NOTE

The information in this Report, including the exhibit, is being furnished pursuant to Item 7.01 of Form 8-K and General Instruction B.2 thereunder.  Such information shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

SECTION 7.  REGULATION FD.

Item 7.01 Regulation FD Disclosure.

On October 24, 2006, Southwestern Energy Company hosted a telephone conference call for investors and analysts.  The teleconference transcript is furnished herewith as Exhibit 99.1.  With respect to the information provided during the call regarding the Hammerhead and Mako pilot areas, the Company is also clarifying that the depth for the Hammerhead and Mako pilot areas is approximately 3,000 ft true vertical depth and 6,000 ft measured depth.

Exhibits.  The following exhibit is being furnished as part of this Report.

Exhibit Number	Description
99.1	Teleconference transcripts for October 24, 2006 telephone conference call for investors and analysts.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SOUTHWESTERN ENERGY COMPANY
Dated: October 25, 2006	By:	/s/    GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Teleconference transcripts for October 24, 2006 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Company Third Quarter 2006 Earnings Teleconference Call

CORPORATE PARTICIPANTS

 Harold Korell

 Southwestern Energy - CEO, President, Chairman

 Richard Lane

 Southwestern Energy - President, E&P

 Greg Kerley

 Southwestern Energy - EVP, CFO

CONFERENCE CALL PARTICIPANTS

 Scott Hanold

 RBC Capital Markets - Analyst

 Brian Singer

 Goldman Sachs - Analyst

 Tom Gardner

 Simmons & Company - Analyst

 Robert Christensen

 Buckingham Research - Analyst

 David Heikkinen

 Pickering Energy - Analyst

 Gil Yang

 Citigroup - Analyst

 Ken Carroll

 Johnson Rice - Analyst

 Travis Anderson

 Gilder, Gagnon, Howe - Analyst

 Richard Moorman

 Capital One Southcoast - Analyst

 John Gerdes

 SunTrust - Analyst

 Joe Allman

 JPMorgan - Analyst

Operator

Good day, and welcome to the Southwestern Energy Company third quarter 2006 earnings conference. At this time I would like to the conference over to the Chairman, President and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Harold Korell - Southwestern Energy - CEO, President, Chairman

Good morning. With us is Richard Lane, President of our E&P segment and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced yesterday regarding our third quarter financial results, you can call Annie at 281-618-4784 and she will fax a copy to you. Also I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings. These forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. 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 had a very good third quarter. We again made progress in our development drilling programs in the Arkoma basin and in East Texas, and even more significantly, we have successfully expanded the known productive area of the Fayetteville shale to the east, with the Hefley well’s performance. In addition, wells to the north of the Hefley have been logged with significant pay sections. On the production front, the Fayetteville Shale volumes are increasing, now at about 70 million cubic feet a day gross.

In other plays, Richard will update our activity in just a moment on Moorefield shale in Arkansas and the Barnett activity in West Texas. Also worth mentioning is that we are participating in wells in the Woodford play in Oklahoma as a result of our land holdings from our conventional Arkoma activities.

I would now like to turn the teleconference over to Richard with more detail on the operational update and then to Greg Kerley for discussion of our financial results.

Richard Lane  - Southwestern Energy - President, E&P

Thank you and good morning. During the third quarter, we produced 19.3 Bcfe. This is 17% higher than the 16.4 we produced in the second quarter. Our Fayetteville Shale production alone was 3.8 Bcfe in the third quarter, up substantially from the 1.8 produced in the second quarter. Through the third quarter, we have spudded a total of 273 wells, including 142 wells in our Fayetteville Shale play, 61 wells in East Texas and 56 wells in our conventional Arkoma Basin program, 12 wells in the Permian basin and 2 in the Rockies. We invested a total of $578 million in the E&P program during the first nine months.

We currently have 25 rigs running. 14 in the Fayetteville Shale play, and five in East Texas, five in the conventional Arkoma basin, and one in the Permian Basin. In the Fayetteville Shale play we invested approximately $222 million, including $175 million for drilling completions, $22 million for leasehold in the first nine months, and we invested an additional $74 million in drilling rigs. As we announced yesterday, we have increased our 2006 capital plan by $95 million, all of which is allocated to our Fayetteville Shale project. This increase is due primarily to changes during the year in our fracture stimulation practices, higher service costs, increased activity on outside operating wells, costs related to our 2005 land drilling rig purchases that were paid in 2006 and the purchase of an 11th drilling rig.

Our total 2006 capital investment in the Fayetteville Shale project is now forecasted to be approximately $487 million, including investments associated with our drilling rigs. As of October 19th, we have now drilled and completed 128 wells, including 52 vertical wells and 76 horizontal wells and 25 pilot areas in eight counties. 49 of the horizontal wells have been completed with either slick water or cross link fracture stimulation treatments.

In yesterday's operational update, we included the update of the normalized average horizontal well production graphs for wells which we were stimulating using a slick water or cross link frac system, our current system. This graph continues to show early production performance from these wells. The average initial production rate for the 49 wells was 1.7 million cubic feet per day, 42 of which have been on production for more than one month. The average rate for these 42 wells after 30 days was 1.5 million cubic feet per day. The average rate of the 23 wells on production after 90 days was 1.4 million cubic feet per day.

A summary table of performance for the 49 slick water cross link wells is included in the operational update we released yesterday. In our operational update, we also included an updated graph of gross production volumes from our Fayetteville Shale play which shows the effects of improved well performance and project acceleration. Current total gross production from our Southwestern operated wells is approximately 70 million cubic feet per day, up from 50 million cubic feet per day in early August. We continue to expect our gross 2006 exit rate to be near 100 million cubic feet per day.

In our last teleconference, we reported that we had extended the Fayetteville Shale play approximately 20 miles to the east with the drilling of the Hefley 1-12 well located in our Sharkey pilot area in White County. The Hefley well was drilled and logged approximately 363 feet of gross Fayetteville Shale play, comparable to what we were seeing in our Cove Creek field. This well is currently producing 1.1 million cubic feet per day, after being on production for 53 days. In the third quarter, we further extended the play with new wells in our Mako and our Hammerhead pilot areas. The Johnson 1-16 located in our Mako pilot area, approximately six miles northwest of the Hefley well, encountered 486 feet of gross Fayetteville Shale play. This well was recently fracture stimulated and is currently flowing back. The Nicholson 1-16 in the Hammerhead pilot area, approximately 6 northeast of Hefley well, encountered 560 feet of gross Fayetteville S hale play. The Nicholson well is scheduled to be fracture stimulated next week. The shale in these two wells have been the thickest that we have penetrated to date.

We are currently completing the Carter 2-35 horizontal well in the Moorefield shale which underlies the Fayetteville Shale in some areas. This well is located in our east Cutthroat pilot area of Cleburne County. The Moorefield shale represents an additional unconventional resource target for which we control 130,000 prospective acres. As of September 30th, we held a total of approximately 887,000 net acres of the play. Of this approximately 762,000 net acres were in undeveloped play area and the remaining 125,000 net acres were in the traditional fairway area of the Arkoma basin that is held by our conventional production.

We currently have 14 rigs running in our Fayetteville Shale play. Of these 14, two are shallow rigs which we use to drill the vertical portion of our wells, prior to moving in one of the larger rigs capable of drilling the horizontal section. Eight of these are our company-owned built for purpose rigs, and we expect to have four shallow rigs and 15 deeper rigs into play at year end. We are we are currently in the process of formalizing our Fayetteville Shale plans for 2007. At this time, we expect to continue to utilizing these 19 rigs in the play throughout next year.

We currently have an inventory of 27 wells in the Fayetteville Shale play waiting on completion. This compares to 12 wells at the end of the second quarter. We are continuing to ramp up the resources dedicated to the play. We currently have two completion crews operating in the area and we expect to have five crews running by the end of the first quarter of 2007. By that time, we expect the short-term completion resource constraints will be resolved. We continue to anticipate that our net 2006 production from the Fayetteville Shale will be between 11 and 13 Bcf.

In our conventional Arkoma Basin properties, we invested approximately $69 million and spudded 56 wells in the first nine months. We currently have five rigs running at our Ranger Anticline play in Yale and Logan Counties, Arkansas. The area between our main Ranger Anticline and the eastern extension we started developing in 2005 is continuing to yield good producers. Our SKK 1-13 well is currently producing 1.1 million cubic feet per day after being on production for 141 days. And it offsets the Smith 1-12 well which we completed in the third quarter, which is producing 5.5 million cubic feet per day after being on production for 64 days. At our Midway prospect and Logan County, Arkansas, we have drilled a total of five wells to date. Of those, two wells are producing and three wells are being completed or waiting on a pipeline. We hold approximately 29,000 gross acres in the Midway exploration area.

In East Texas, we remain active in our Overton Field and our Angelina River Trend. If the first nine months of 2006, we invested approximately $151 million in East Texas and spudded 61 wells, 54 at Overton and 7 at the Angelina River Trend. We continue to have four rigs drilling in Overton with additional rig in our Angelina river play. We expect to bring two company-owned drilling rigs into the area by the end of 2006. These new rigs are expected to result in lower overall drilling costs, and higher returns on our investment.

We plan to drill approximately 85 wells in East Texas in 2006. In our Permian Basin Barnett Shale project, we are continuing completion operations on our first two vertical wells. The State Street 701 well and our Popeye prospect, which we drilled and completed in the second quarter, is currently shut in for pressure buildup test., after testing non-commercial quantities of gas. The Dela Minerals 3 State 701 in the Coronado prospect is currently being completed and preliminarily tested at an estimated rate of 2.1 million cubic feet per day over a shortened test period.

Finally, in early October, we signed a purchase and sale agreement to sell our remaining south Louisiana-producing properties for an estimated $14 million, subject to customary closing adjustments. At year end 2005, our south Louisiana properties had proven reserves of approximately 9 Bcfe, and these proceeds from the sale will be reinvested in higher PVI projects in our core area.

In summary we continue to be very encouraged by our success in our Fayetteville Shale projects. Our programs in the Arkoma basin in East Texas are yielding stronger results, plus we are delivering significant production growth while adhering to our strategy of creating value plus through our investments.

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

Greg Kerley  - Southwestern Energy - EVP, CFO

Thank you, Richard and good morning. As Harold indicated, we reported strong results for the third quarter. Earnings for the quarter were $33.5 million, or $0.20 per diluted share, compared to $39.5 million for the third quarter of 2005. Our 2005 earnings included the $8.7 million pretax gain related to future basis hedges and excluding that gain, our earnings were approximately level with the prior year period. Net cash flow provided by operating activities before changes in operating assets and liabilities set a new record for the quarter at $95.2 million, up 19% from the prior year as a result of our strong production growth.

Operating income for the E&P segment was $56.3 million for the quarter, compared to $68.9 million last year as the increase in revenues resulting from the growth in our production volumes was more than offset by increased operating costs and lower natural gas prices. We realize an average gas price of $6.23 per Mcf for the third quarter 2006, compared to $6.98 for the same period last year. Our hedging activities increased our average gas price realized in the quarter by $0.19 compared to a decrease of $0.91 for the same period last year.

Our current hedge position, which consists primarily of costless collars provides us with a solid level of cash flow protection, while still allowing us to retain considerable upside. We have hedged approximately 60 to 65% of our targeted fourth quarter gas production, and currently expect our average realized price during the quarter to be approximately $0.45 to $0.55 per Mcf lower than the NYMEX Henry Hub price. Additionally, we have hedged 55 Bcf of our future gas production for 2007, and 22 Bcf for 2008. Our detailed hedge position is included in our Form 10-Q.

Lease operating expenses per unit of production were $0.68 per Mcfe in the third quarter of 2006, up from $0.51 for the same period in 2005. The increase in our unit operating costs was primarily due to increases in our gathering and compression costs related to the development of the Fayetteville Shale play. Our general and administrative expenses per unit of production were $0.54 per Mcfe in the third quarter of 2006, up from $0.42 in 2005, primarily due to our increasing staffing levels.

Over the past year, we have made a significant investment of time and resources to meet the staffing needs of developing our Fayetteville Shale play. We added 389 new employees during 2006, most of which were higher than the E&P segment and expect to hire an additional 115 to 130 employees by year end. Approximately 300 to 325 of the total new hires during 2006 are expected to be employed by our drilling company. Our full cost full amortization rate was $1.97 for the third quarter, compared to $1.44 a year ago. The increase is primarily due to higher finding and development costs. Our finding and development costs during 2006 are expected to be heavily impacted by the timing and amount of reserve bookings in our Fayetteville Shale play. Operating income for our mid-stream services segment, which comprises of our gas marketing and gathering activities was $1.3 million during the quarter, compared to $1.5 million during the prior year pe riod.

Our utility systems realized the seasonal operating loss of $4.5 million in the third quarter, compared to a loss of $3.2 million for the same period in 2005. On September 25th, 2006, our utility filed a request for a $13.1 million annual increase in its general rates and tariffs with the Arkansas public service commission. The commission has ten months to review the filing and make a decision on the request. Any approved increase is expected to take effect in July of 2007.

Our capital investments for the quarter were $258.4 million and $632.1 million for the first nine months of 2006. As we reported yesterday, we have increased our projected capital investments for 2006 to $925 million, up approximately 11% from the $830 million capital program we announced in December of last year. As Richard indicated, the increased amount includes projected capital expenditure of $865 million for our E&P segment. Our balance sheet and financial condition remain extremely strong. As of September 30th, 2006, our balance sheet debt-to-total capitalization ratio was 9%, and we had access to $500 million under our revolving credit facility.

We lowered our production guidance for the fourth quarter of 2006 to a range of 20.4 Bcfe to 21.4 Bcfe and our full-year guidance to a range of 72 to 73 Bcf equivalent to reflect the current shortage of pressure pumping equipment and crews in our Fayetteville Shale play and the pending sale of our South Louisiana properties. That concludes my comments, and now I will turn back to the operator who will explain the procedure for asking questions.

QUESTION AND ANSWER SESSION

 Scott Hanold  - RBC Capital Markets - Analyst

 Good morning.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Good morning.

 Scott Hanold  - RBC Capital Markets - Analyst

 I was wondering, with regards to the Fayetteville Shale, and the 19 rigs you will have next year, could you talk about in terms of will those five crews be enough to keep up with that pace and if you brought in more rigs into the play, would you need additional crews?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, the -- we are trying to match the two. We haven't set on the number of rigs we will have in the play until we build that plan. But looking at what we'll have in place at year end, we'll be adding -- adding crews during the year, and we think that the resources that we'll have completing the wells will match that level of drilling activity with the current rig count.

 Scott Hanold  - RBC Capital Markets - Analyst

 Okay. Fair enough. And then, looking at sort of '07 it's probably early to start talk about CapEx budget but can you sort of talk about mix between operational areas, especially like with East Texas. Would you anticipate, continuing with -- it sounds like you will add two more rigs there. Seven rigs into '07?

 Richard Lane  - Southwestern Energy - President, E&P

 Well we are looking at that whole rig fleet that we have there. We haven't decided on the split there. We have wells that drill in Angelina River Trend as well. And I think the east -- we haven't set, obviously our East Texas capital number. That's part of what we are going through, and we will just have to see what -- how far the inventory we will go and how many wells we want to do with the Angelina River Trend.

 Scott Hanold  - RBC Capital Markets - Analyst

 And one more question and I will get back into the queue. At the Delaware basin, I guess it was some pretty interesting results. You obviously had one that appeared noncommercial and another one that was around 2 million a day on the short test. Could you provide us a little bit of color on the -- on some of that activity out there?

 Richard Lane  - Southwestern Energy - President, E&P

 Sure. The -- with he have two lease blocks there. Popeye is in the shallower part of the trend, and then Coronado is north and in the deeper part of the trend. The Popeye well, the shallower one, we fracture stimulated the vertical well, and flowed it back and it flowed back our load and some gas but not really good, measurable -- not good quantities of gas or commercial quantities of gas. And we're looking at how it was treated and wanting to understand more about the reservoir pressure there. So that's what we are doing there currently.

And then on the deeper well, the Coronado well, again, a vertical well that we fracture stimulated with a gel system, and flowed that back and it flowed back fairly strong. It gave back the load water there and gave the test rate that we reported. And now we're running tubing in the well and we'll put it in production and watch it. It was a very short test rate but encouraging to see out of the verticals.

 Scott Hanold  - RBC Capital Markets - Analyst

 Okay. And do you think the results are due to the stimulation technique and/or the location of the well? The deeper -- in the deeper section.

 Richard Lane  - Southwestern Energy - President, E&P

 Well, yeah, certainly, both of those things play in, how we treat it and the depth in the Coronado block, I think, our perforations are at about 12,600 feet there. So we have more pressure and more gas in place than the other block. So that has something to do with it.

Brian Singer  - Goldman Sachs - Analyst

 My first question is regard to the Moorefield and the Moorefield well. How should we look at the level of pay, both in Fayetteville and Moorefield zones, as compared to t are they compared to some of the other Fayetteville wells that you have drilled?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, the Carter well is East Cutthroat and the Fayetteville thickness is there. I don't have that exact number but it's been kind of our average thickness we have been seeing along the southern swath of development there. Nothing outstanding there. The Moorefield, we are -- we are trying to understand it, and we don't have as many penetrations so we see 90 or so feet of pay in the Moorefield. There's other -- other parts of the Moorefield shale that have little lower activity and some log characteristics that are -- we don't completely understand right now. So, we will just have to see when we -- when we get the well flowing back and what it does. We will see in the sections that are lower recesstivity, how much we communicate with that when we fracture stimulate it and how much impact that part of the zones will have.

 Brian Singer  - Goldman Sachs - Analyst

 Okay. Secondly, switching to costs, you had a little uptick to $2.2 million. Can you talk about to what extent should the Schlumberger contract and other service contracts provide cost mitigation. Does that mean that you can keep well costs flat going forward at $2.2 million? Does that mean that there's an ability to reduce costs or lower cost inflation?

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 You are talking about the arrangement with Schlumberger and how those would impact costs?

 Brian Singer  - Goldman Sachs - Analyst

 Yes.

 Richard Lane  - Southwestern Energy - President, E&P

 We have an agreement with them, as going forward over the next few years that -- that don't lock prices where they are flat, to where they are right now, but they provide for -- for very competitive pricing through a formula that I don't want to go through a lot of details on. I think they are subject to move with inflation, but in a very competitive way for us.

 Brian Singer  - Goldman Sachs - Analyst

 Great. Thank you.

 Tom Gardner  - Simmons & Company - Analyst

 Thank you. My question relates to both the Fayetteville Shale productive area and pro well reserves. What would you estimate the percentage of Southwestern's 887,000 acres, what percentage of that has been validated by successful pilot wells? And with the additional production data you are gathering, is it safe to assume that reserves will be increased?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, we -- I imagine we have seen the shaded area that we outlined in our investor relations material.

 Tom Gardner  - Simmons & Company - Analyst

 Yes.

 Richard Lane  - Southwestern Energy - President, E&P

 Kind of calling the drumstick.

 Tom Gardner  - Simmons & Company - Analyst

 Yes.

 Richard Lane  - Southwestern Energy - President, E&P

 And that's about 590,000 gross acres out of the total gross acres that we have been talking about. And then on the -- on the reserves per well question, we have got the range out there that we are comfortable with right now and we have to watch the production history going forward.

 Tom Gardner  - Simmons & Company - Analyst

 Can you give us a feel for a high and low and midcase reserve estimate?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, that would be the 1.3 to 1.5 Bcfe kind of average range that we are reporting. Individual wells we have seen again with early production issues, we have seen wells that are higher and out of that range, EUR-wise.

 Tom Gardner  - Simmons & Company - Analyst

 Okay. Thank you very much.

 Robert Christensen  - Buckingham Research - Analyst

 Can you talk about the Woodford in Oklahoma?

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Bob, can you speak up?

 Robert Christensen  - Buckingham Research - Analyst

 Can you hear me? Can you talk a little bit more about the Woodford in Oklahoma, how you are participating there and exposure, please?

 Richard Lane  - Southwestern Energy - President, E&P

 Yeah, Bob. We -- we have had acreage -- an acreage position in the Oklahoma side of the Arkoma Basin for a good while. Most of that was put together for our Pennsylvanian sands token section there that we pursued through the years. So we -- we hold a lot of that acreage by production and some of it is in its primary term. We have about, I think, 22,000 acres on the Oklahoma side of the basin.

Right now we are focused on a block that's the most southwesterly of that acreage where there's been -- there's been some good activity, some pretty promising activity in the horizontal drilling to Woodford. And, in fact, we are participating, non-operated position, we are participating with other companies there, and -- and so we have seen -- I think we have seen five or six proposals and we have signed up on I think three wells so far. And we think that activity is going to continue, and so it's -- it's nice to have it come to you once in a while.

 Robert Christensen  - Buckingham Research - Analyst

 And my second question relates to the recent success of a few horizontal wells in the Carthage area and the permitting of several more. I know you have East Texas. Are you at all potentially exposed to drilling some horizontals to tailor sand as a company? What are you doing on that? Thank you.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Yeah, we -- we have seen that activity. Of course, we are not involved with it or really close to it. Our East Texas team is looking at that activity and really trying to understand what is happening there for the additional costs. Is there incremental economic benefit, or not. And I think the jury is out in our shop, and I couldn't be comment on whether we'll doing some of it or not.

David Heikkinen  - Pickering Energy - Analyst

 Good morning. In the Hammerhead Mako areas what were the well depths did you drill to and what were the costs there, and thinking about the thicker shales, would you do vertical completions?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, the actual depths have off the top of my head. I would say, we are probably in the 6500-foot range, something like that. And the second part of your question, I'm sorry?

 David Heikkinen  - Pickering Energy - Analyst

 The cost and then given the relative shale thickness, would you consider a vertical completion?

 Richard Lane  - Southwestern Energy - President, E&P

 No, I don't think so, given the -- we are seeing the incremental benefit from horizontal wells in the thinner stuff so it -- I think we would still probably pursue it horizontally. I don't are have the absolute cost for each of those wells. The stepout wells we do incur a little bit more costs for coring and testing. They would have been a base cost of $2.1 to $2.2 million by the time they are completed and the dry hole costs we probably have some additional dollars in there because they are step out wells that we are trying to understand.

 David Heikkinen  - Pickering Energy - Analyst

 And just making sure that whenever we talked well depths, the 6500 feet, that was not measured depth, right?

 Richard Lane  - Southwestern Energy - President, E&P

 Right.

 David Heikkinen  - Pickering Energy - Analyst

 I think I got my two questions in with that and I will go back in queue.

Gil Yang  - Citigroup - Analyst

 My two questions. First one is, at this point, what is the most important thing to look at in terms of the success of a particular phase of wells? I mean you talked about the depths of the pay zones. Is that the most important thing to key on or are there other metrics that will affect the performance more importantly?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, I think the thing to key on is the production of the wells that we are charting in that average graph and how much a new well -- how a new well compares to that. And there's a myriad of factors that go in to determining what that performance is. I would not signal out depth because we would have -- we haven't seen a real depth dependant function relative to what we are forecasting in EURs yet.

 Gil Yang  - Citigroup - Analyst

 Is there a dependant on EURs for thickness.

 Richard Lane  - Southwestern Energy - President, E&P

 There should be. There should be one for thickness, there should be one for depth. Empirically, there should be but we haven't really seen that distribution yet.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Yeah, and I -- I think -- you asked an interesting question. It's a good question but if you think about this from the most simplistic of view which is there's a certain amount of gas in place down there, that's determined by thickness and depth and -- and ability of the rock to store gas, which we normally describe as porosity or gas that's absorbed into shales, for example. And so all of those things make the original target that's there. What could be -- what we could be seeing at this point in time, though, is in terms of the production performance, could be not rather related to those but rather the effectiveness of the fracture stimulation and how much of the rock that we are communicating with.

So, at this point in time, it may be the fracture stimulation, and we know, based upon our history of doing the nitrogen foam fracs early on and not having as good of performance as we are seeing with the slick water or cross link gelled systems, we know for sure that it wasn't depth or thickness or, porosity or absorbed gas that was making a difference. We know it was the fracture treatment. I think as we go forward in this play and not only this play but other plays. I think Barnett, we settled on one way of doing the fracture stimulations.

But I think in the unconventional plays, all the gain that's remaining to be made lies in the fracture stimulation. And in any event there are other questions about that out there, we have changed from the nitrogen foam fracs to slick water and now we are doing some cross link gel in areas where we were having trouble pumping various stages away. So we -- on the fracture stimulation front, there's the area of fluid systems that we are dealing with, and that's one change, and then the second area that we are continuing to experiment with is the mechanical aspect of fracturing, whether you are using the conventional cement and then perforate, and set bridge plugs to do successive stages or whether you are doing the Packers Plus or the Peak system or the Baker Oil Tool system, there are various systems to do things differently mechanically, which might, at the end of the day, give you different and better results.

We have been experimenting with some of those. It affects our costs when we experiment, but at the end of the day, a lot -- there's a lot -- I mean there's a lot of gas in place here that's affected by thickness, depth and porosity and absorbed gas. But I don't think we are reaching all of it in probably very many of these plays. That's why you have people downspacing in Barnett, now. Of course, we're way early in the game. But the real money to be made and the improvements to be made here, I think are in figuring out how to frac these wells the most optimum way. So we are still experimenting with that. It's not as easy to answer the question as your question about depth. I don't personally think it's depth or thickness, but ultimately those will be the end points of the game, but I think it's in the fracture stimulation today.

 Gil Yang  - Citigroup - Analyst

 Okay. Fair enough. My second question is inventory of wells that are waiting on completion. Is your intent to keep that fairly steady? And was there any effort intentionally to build that inventory, just given the low gas prices recently, to take advantage of completing them later and taking advantage of higher gas prices in the future?

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 No, we weren't doing the latter. Simply as we increased the number of rigs out here, the available frac equipment here in the area, is not up to the point where our drilling pace is. And to some extent, we were caught a little bit in this shape because in our planning that we were doing for a time, we were doing nitrogen foam fracs and then when we shifted to the slick water fracs, it changes the equipment used for pumping. So it's kind of a change in midstream during '06 in regard to that. And on top of that, there's never been a lot of frac stimulation equipment in the Arkoma Basin. So the companies are building their positions there.

 Gil Yang  - Citigroup - Analyst

 Okay. Thank you.

 Ken Carroll  - Johnson Rice - Analyst

 Oh, I apologize. My question has been answered. Thank you.

 Travis Anderson  - Gilder, Gagnon, Howe - Analyst

 I was wondering, eyeballing the maps you have been putting on lately versus one of the maps that you showed earlier this year with all the potential pilots for this year, has there been any change in where you are planning to do the pilots or how many? Because I recall that earlier map had a lot more pilots up in the north and northeast of the of the box that you haven't gotten around to yet.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 We are gradually moving in that direction, Travis, as you look at the -- at the drum stick now, and that shaded drum stick area, and then you also see in our materials that there are three locations that we have now drilled north of those, and those aren't fracture stimulated at this point in time. Richard may be able to answer the extent to which we have wells north of that, but I don't have a specific plan in front of me.

 Richard Lane  - Southwestern Energy - President, E&P

 It hasn't -- I don't think it's materially changed from some of those earlier maps. I don't know what your reference point is but we have moved a few out of the fairway area, into the -- into the eastern area. And then there's that lake area to the north. Of course, that doesn't show up on that map that we'll -- we can't drill there. But there are additional pilots in the final quarter. I think something like seven or eight that will be also in-filling.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 And if you do those that we have concentrated on, still as we are moving along, trying to be as near those pipelines as we can because we can sell the gas instead of just drilling and leaving it shut in.

 Travis Anderson  - Gilder, Gagnon, Howe - Analyst

 Right, that's painful economically, I understand. So how many more pilots do you think will spill over into next year, if any?

Richard Lane  - Southwestern Energy - President, E&P

 How many for next year?

 Travis Anderson  - Gilder, Gagnon, Howe - Analyst

 Right, in other words, I think you were originally planning on about 28 or 30 pilot areas.

 Richard Lane  - Southwestern Energy - President, E&P

Right. Well, we haven't determined what next year's levels will be.

Harold Korell  - Southwestern Energy - CEO, President, Chairman

 What we can say about the plan is what we have been doing to this date, if you look at where our pilots are located, they are about 10 miles apart. And so, the name of the game will be to -- to position pilots across the remaining part of the area that's farther away from the pipelines, because we are just -- it's -- we have kind of opposing objectives here. One is we want to know what the acreage, whether it's productive out there, but at the same time, it's not efficient in terms of using the capital, because the wells are going to sit there and not equal production. But, I think you can expect to see us do is fill in the acreage and work away and then we'll start going through higher density and developing right, in areas where we already have infrastructure for gathering.

 Travis Anderson  - Gilder, Gagnon, Howe - Analyst

 And on the gathering side, where does that stand? I know you were looking to find a pipeline partner. Anything you can talk about?

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Well, on the gathering side, we are pretty much doing the gathering, which just means putting the laterals and the compression in to get it into the currently existing pipelines. But on the more -- the bigger question about transmission out of the area, which I think is what you are really asking about is, sometime this year, we intend to make a decision on that. We have proposals from various quality pipeline companies of which the intent is to be able to meet our -- our needs to transport gas out of this area somewhere in the future, when our producing rates would exceed the 225 million a day that we have for term capacity for on Ozark.

So what we are looking at is options for down the road so that we have the ability to take away and we're not prepared -- we aren't making that decision today. I can tell you that at one time, we talked about doing it -- maybe doing it ourselves but there's plenty of interest out there in building a transmission system that would get this gas not just to the markets to go to the Midwest, but potentially we would get this gas not just to the markets as we go to the midwest, but potentially we'd get this gas to the markets that go to the east, which have a -- which have a lesser basis differential associated with them, that would be in our favor.

 Travis Anderson  - Gilder, Gagnon, Howe - Analyst

 Great. Okay. Thanks.

Richard Moorman  - Capital One Southcoast - Analyst

 Good morning, gentlemen. Congratulations on a good quarter, especially in Fayetteville Shale. I just wanted to ask a couple of questions. First, you have done some stepping out to the east in the new pilots and reported a couple of wells. It looks to me, okay, now with the Sharkey prospect, you have gone basically I think about halfway from where your core area was to what was thought to be kind of the eastern edge maybe out in Woodruff county and you are getting wells in the 400 to 500 thick range. Can you comment on how the geology in the area, are we going to consistently see 400 to 500 feet and is the quality of the rock holding up as you go east here?

Richard Lane  - Southwestern Energy - President, E&P

 I can comment as to where we drilled and our lease block, Richard.

 Richard Moorman  - Capital One Southcoast - Analyst

 Yes.

Richard Lane  - Southwestern Energy - President, E&P

 The log quality where we just have logs is comparable, and then the Hefley, is kind of an average type of well. That's holding up. in general, the thickness, there's -- you are getting thicker east and south and so I think that general trend is there. You might have -- you might have variations that, locally to that but in general, that would be the trend.

 Richard Moorman  - Capital One Southcoast - Analyst

 Okay. Super. Thank you. And then in West Texas you mentioned, of course, the first well, the first attempt there not commercial right now. The second attempt in the 2 million a day range. What would your development plan be going forward? Are you keeping a rig, say, in there from here on?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, we haven't determined that completely. The rig that's drilling the -- that we use to drill the Coronado well is not going to stay out there right now. And the -- based on how the testing goes, the rest of this year, will kind of determine the activity level for next year.

 Richard Moorman  - Capital One Southcoast - Analyst

 Fair enough. Thank you. I appreciate the answers and look forward to hearing about your future pipeline. Thanks.

John Gerdes  - SunTrust - Analyst

 Richard on this fracture stimulation front, recently what have you been doing just the last couple of months, just evolving this way you are approaching stimulating these Fayetteville wells?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, we have -- we have gone entirely to slick water or cross linked gels, away from nitrogen. You know that.

 John Gerdes  - SunTrust - Analyst

 Right.

 Richard Lane  - Southwestern Energy - President, E&P

 Where we are using gel fluids versus slick water depends on the area and it seems to be that we -- we are choosing to use the gel fluids in areas where maybe we had a little higher initial treating pressures and early -- early time issues. That seems to be addressing those. And so helping on the early time pumping of those. And we think maybe generating a little bit more fracture width and overcoming that. That's how we are deciding which system we are using. Mechanically, Harold mentioned, we have been experimenting with the Packers Plus system. We have been experimenting with the Peak system, and then also Baker system. And the Packers Plus and the Baker system are, on your production string, you have Packers.

 John Gerdes  - SunTrust - Analyst

 Yes.

 Richard Lane  - Southwestern Energy - President, E&P

 And it's a non-cemented system.

 John Gerdes  - SunTrust - Analyst

 Yes.

 Richard Lane  - Southwestern Energy - President, E&P

 And on the other system, it's a cemented system where you are use -- cemented system where you are using sliding sleeves. So totally different. One cemented, one uncemented. We are experimenting with that. And there's -- we are seeing some good things there. We have also seen some mechanical issues on some of the jobs that we are trying to iron out and determine what is the best way to go. I will tell that you it has a dramatic impact on the number of wells you can complete with the crew in a given week or month or whatever your time frame is.

 John Gerdes  - SunTrust - Analyst

 You can basically do multi stages in a 24-hour cycle versus days, is that right?

 Richard Lane  - Southwestern Energy - President, E&P

 Yes, generally that's right. So you can see the impact there.

 John Gerdes  - SunTrust - Analyst

 What type of costs.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Incentive for us and the companies to move this forward for unconventional plays.

 John Gerdes  - SunTrust - Analyst

 Where do you see that shaking out technology wise. It sounds like it's a little too early to tell in terms of the mechanical, the uncemented mechanism, versus the cemented mechanism?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, I think there's some -- like Harold says, the technology is evolving and there's a lot of impetus from the operators and the service companies to -- to perfect it. But there's -- there's still some issues there. With a program this size, this enormous magnitude, you want to have a predictable -- you want to have a predictable system and you don't want to have mechanical issues when you are going to be doing so many of them. There are a few things on how the packers seat and then on the other systems, how reliable are those sleeves and how good is the isolation per stage and things like that.

 John Gerdes  - SunTrust - Analyst

 And out of that $2.2 million, Richard, what is the fracture stimulation component of that capital cost?

 Richard Lane  - Southwestern Energy - President, E&P

 It's about $900,000; $800,000 to $900,000.

 John Gerdes  - SunTrust - Analyst

 Okay. And then -- and then as far as the -- the gross numbers that you all are producing, generally, what are you running as a net revenue, if you remind me of that, please.

 Richard Lane  - Southwestern Energy - President, E&P

 Oh, I think the last time I looked, it was about 87%.

 John Gerdes  - SunTrust - Analyst

 Yeah, you are running pretty hot. Okay.

 Richard Lane  - Southwestern Energy - President, E&P

 Now you are talking -- are you talking net revenue on a lease basis or net to gross on the production?

 John Gerdes  - SunTrust - Analyst

 Net to gross on the production.

 Richard Lane  - Southwestern Energy - President, E&P

 Yeah, net to gross on the production, I think, we're 79% or 80%.

 Greg Kerley  - Southwestern Energy - EVP, CFO

 Close to 80%.

 John Gerdes  - SunTrust - Analyst

 Okay. Okay. Good. And one follow-up, if I may. On Ranger Anticline, you talked about identifying some 138 drilling locations in that area what spacing is that? I believe you got regulatory approval to downspace that area about, 560 feet or 16.5 acres per well.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Yeah, I think that the -- you must be referring, John, to 138 wells that are in our investors relations material.

 John Gerdes  - SunTrust - Analyst

 Exactly.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Which is a number that is kind of like a possible number.

 John Gerdes  - SunTrust - Analyst

 Got you.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 The reality there is that I think our data would show that we are draining somewhere on the order of 40 acres or less, at least with those wells. So if you had a section that had -- that was productive entirely, then I could imagine 16 wells in a section. But I -- I think the number that's actually there to be drilled is still kind of an unknown.

 John Gerdes  - SunTrust - Analyst

 Okay.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 We average -- 138 is a number. That's not like taking it and doing science on it.

 John Gerdes  - SunTrust - Analyst

 Right.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 That was like saying potentially this, and so the numbers could be different.

 John Gerdes  - SunTrust - Analyst

 What are you drilling these on right now? It sounds like you are drilling these at 80 acres at this point, roughly.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Well, some of the sections have 12 or 13 wells in them already.

 John Gerdes  - SunTrust - Analyst

 Okay.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 And so I would say we are more spacing them on 40-acre spacing.

 John Gerdes  - SunTrust - Analyst

 Thank you very much.

 Joe Allman  - JPMorgan - Analyst

 Good morning, everybody.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Good morning.

 Joe Allman  - JPMorgan - Analyst

 In West Texas, the two wells you discussed in this press release and in the call, are they true Barnett Shale wells or are they Woodford Shale completions?

 Richard Lane  - Southwestern Energy - President, E&P

 They are indeed Barnett.

 Joe Allman  - JPMorgan - Analyst

 Okay. Are you giving any optimism about any woodford shale out there?

 Richard Lane  - Southwestern Energy - President, E&P

 Well, the Woodford is a big target, a big resource out there in the basin. It reaches some very high thicknesses. I think where we are, we are not specifically targeting it because it's, not as thick as it reaches in the maximum.

 Joe Allman  - JPMorgan - Analyst

 Okay. And Richard, are you -- do you have the same optimism level as the playoff there as you did a few months ago?

 Richard Lane  - Southwestern Energy - President, E&P

 I would say, yes. we are flowing gas up a well bore. So I would say the same or better.

 Joe Allman  - JPMorgan - Analyst

 Okay. All right. Thank you.

 David Heikkinen  - Pickering Energy - Analyst

 I have a question on completion crews and number of wells that can be completed by crew per quarter by month. Just trying to get a feel for how fast a crew can run in the Fayetteville.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Well, in general, it will depend on the type of completion that we do and so it's a little bit hard question to answer. And, if we are doing the conventional cement and then do fracture stimulations versus pumping one of these in the day then then it depends if we are pumping one of them in a day at the present time, I think the situation is that the crew has got to go home because they are past their DOT work hours. So it depends whether the service company gets ramped up with more people to come on and use the equipment that's there the next day. It's a little bit hard. Richard may have a specific answer but I think that it's a hard one to answer.

 Richard Lane  - Southwestern Energy - President, E&P

 It is. There's a big wild card there in the process there, obviously, David. But, we could -- it was somewhere around 1.5 to 2 fracs per crew per week.

 David Heikkinen  - Pickering Energy - Analyst

 Okay.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 And then we need to look at -- given the appropriate risking of that, when you have operational issues that are going to crop up and so we don't get too overstated there. But something on the order of that. And that's going to put you 80 plus or so for a year.

 David Heikkinen  - Pickering Energy - Analyst

 Okay.

 Richard Lane  - Southwestern Energy - President, E&P

 But then like Harold said, boy, we change that process and all bets are off.

 David Heikkinen  - Pickering Energy - Analyst

 Yeah.

 Richard Lane  - Southwestern Energy - President, E&P

 Packers plus comes in or you get two crews where you can keep 24 hour operation.

 David Heikkinen  - Pickering Energy - Analyst

 Right.

 Richard Lane  - Southwestern Energy - President, E&P

 But looking at third quarter rates of basically had two crews running through the third quarter, is that --

 David Heikkinen  - Pickering Energy - Analyst

 Right.

 Richard Lane  - Southwestern Energy - President, E&P

 One and a half to two.

 David Heikkinen  - Pickering Energy - Analyst

 Okay. And you completed around 23, 25 wells in the quarter with that one and a half to two crews running.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 I think that's right.

 David Heikkinen  - Pickering Energy - Analyst

 And that would be without Packers Plus or without the additional crew or manpower?

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Mostly. That's correct.

 David Heikkinen  - Pickering Energy - Analyst

 Okay. So that would be the low end and then kind of a midpoint target, one and a half to two fracs per crew per week. That's very helpful.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 I think with the inventory, we are just trying to point out where we are, because it's important. The completed wells waiting on completion has grown. We are trying to point that out. We look forward in how we are securing resources and the plan coming together. We will get an awful lot done and the resources are going to be there. And we are still saying, we are -- given all that, we are doubling the production from the Fayetteville Shale play we were the previous quarter and we still say we will be close to 100 million cubic feet at year end.

 David Heikkinen  - Pickering Energy - Analyst

 I think the optics of quarterly measurement, whenever you are talking about a 10, 15 year development program, it's the spin-up of activity level. Any sort of delays like that should be expected but you will get there and you will attract the activity with 7,000 wells planned potentially. That was it. Thanks, guys.

 Harold Korell  - Southwestern Energy - CEO, President, Chairman

 Well, I think each of you for being on the call today and I think we have wrapped it up in about an hour. And, we have an exciting year still ahead of us in '06, and we are at the point of building our 2007 plans, so we haven't addressed a lot of your questions about that. I know each of you are trying to get that to go. We will be doing that as we go through the next couple of months. Thanks for being here today and that concludes our conference.