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): February 29, 2008

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 125, 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 February 29, 2008, Southwestern Energy Company hosted a telephone conference call for investors and analysts.  The teleconference transcript is furnished herewith as Exhibit 99.1.

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

Exhibit Number	Description
99.1	Teleconference transcript for February 29, 2008 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: March 3, 2008	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 transcript for February 29, 2008 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Company Fourth Quarter and Year-End 2007 Results Teleconference

Friday, February 29, 2008, 10:00 a.m. ET

Officers

 Harold Korell; Southwestern Energy; President, Chairman and CEO

 Richard Lane; Southwestern Energy; President, Energy and Production

 Greg Kerley; Southwestern Energy; CFO

Analysts

 Richard Tullis; Capital One; Analyst

 Unidentified Participant; Macquarie Capital; Analyst

 David Snow; Energy Equities; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Tom Gardner; Simmons & Co.; Analyst

 Jeff Hayden; Pritchard Capital Partners; Analyst

 Robert Christensen; Buckingham Research; Analyst

 Scott Hanold; RBC Capital Markets; Analyst

 Gil Yang; Citi; Analyst

 Joe Allman; J.P. Morgan Securities, Inc.; Analyst

 David Heikkinen; Tudor, Pickering and Co.; Analyst

 Robert Christensen; The Buckingham Research Group; Analyst

 Jeff Hayden; Pritchard Capital; Analyst

 David Snow; Energy Equities; Analyst

Presentation

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

Harold Korell: Good morning, and thank you for joining us. With me today are Richard Lane, the President of our E&P segment, and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced yesterday regarding our fourth quarter and year-end 2007 financial results, you can call 281-618-4784 to have a copy faxed to you.

Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and Forward-Looking Statement sections 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, 2007 was an outstanding year for Southwestern Energy. Looking at our achievements, we grew our production volumes by 57%, which is over the 2006 levels, and our reserves grew by 41% to 1.45 cubic trillion cubic feet equivalents, which represents a reserve replacement ratio of 474%.

While these results are important, the key accomplishment for us in 2007 was the progress we made in our Fayetteville shale play. During the year we made advancements in our completion techniques for the Fayetteville shale, significantly increased our 3-D seismic database, thereby improving our ability to reduce risk in our drilling program, and began drilling and completing longer laterals, all of which is leading to higher productivity in our horizontal wells.

Our progress in the Fayetteville Shale during '07 has set the stage for another year of substantial growth in our production and reserves in 2008. We believe our production will grow again this year somewhere around 30 to 35% and we're looking forward to some new things, which include the results from our development project testing we're doing in the Fayetteville, our drilling results into the James Lime in East Texas, and future opportunities that we've seeded in the Marcellus Shale in Pennsylvania.

I'd like to now turn the teleconference over to Richard for more details on our E&P activities, to Greg for an update on our financial results, and then we'll take questions.

Richard Lane: Good morning. In 2007, gas and oil production totaled 113.6 Bcfe. Our Fayetteville Shale production was 53.5 Bcf in 2007, up substantially from the 11.8 produced in 2006. We produced 29.9 Bcfe from East Texas in 2007, 23.8 from our traditional Arkoma Basin area, 6.4 from our Gulf Coast Permian Basin and new ventures areas combined.

Production for the fourth quarter of 2007 was 34.9 Bcfe, up 68% from the fourth quarter of 2006. Our production from the Fayetteville Shale increased to 19.9 Bcf during the fourth quarter, up from 5.5 in the fourth quarter of '06. As a result of our continued strong performance, we have increased our first quarter production guidance range by 1 Bcf, to 35 to 36 Bcf. Our full guidance remains at 148 to 152 Bcfe.

In 2007, we increased our year-end proved reserves by 41%, to 1.45 trillion cubic feet. The 1.45 of proved reserves were located approximately 49% in the Fayetteville Shale, 24% in East Texas, 21% in the conventional Arkoma Basin, and 6% in other areas.

In 2007, we added 507.9 Bcfe of proved reserves and had net upward revisions of 31 Bcfe. Both the additions and the revisions were primarily driven by the performance of our wells in the Fayetteville Shale play. Including both our additions and revisions, we replaced 474% of our 2007 production at a finding and development cost of $2.55 per Mcfe. Excluding revisions that cost is $2.71 per Mcfe. Proved developed reserves accounted for approximately 64% of our total reserves at year-end 2007.

In 2007, we invested $1.38 billion in our exploration and production business activities and participated in drilling 653 wells. Of those wells, 439 were successful, 17 were dry and 197 were in progress at year-end, for an overall success rate of 96%. Of the $1.38 billion invested in 2007, approximately $1.13 million or 82% was for drilling wells, $166 million was for leasehold acquisition and seismic, and $84 million in other costs.

In our Fayetteville Shale play in 2007, we invested approximately $960 million, including $789 million to spud 415 wells, $97 million on seismic, $25 million on land, and $49 million on other capitalized costs. We added 401.6 Bcf and had 67.9 Bcf of upward reserve revisions, primarily due to improved well performance, resulting in an all-in finding and development cost of $2.05 per Mcf. 3-D seismic costs alone represent approximately $0.20 per Mcfe of the total finding costs.

At the end of 2007, we held a total of approximately 907,000 net acres in the play, of which 143,000 net acres are held by Fayetteville Shale production, and approximately 125,000 net acres are held by conventional production in our traditional Arkoma Basin areas. Excluding areas held by production, our year-end acreage position has an average lease term of 6 years, an average royalty interest of 15%, and our cumulative all-in average acreage cost is $116 per acre.

Gross production from our operated wells in the Fayetteville Shale play increased from approximately 100 million cubic feet per day at the beginning of 2007, to approximately 325 million cubic feet per day by year-end. And that could approach 450 million cubic feet per day by the end of 2008. As of mid-February, our gross production rate has increased to approximately 350 million cubic feet per day.

We expect our total 2008 net production from the Fayetteville Shale to range from 90 to 95 Bcf, as compared to 53.5 during 2007. Our total proved gas reserves in the Fayetteville at year-end 2007, were 716 Bcf compared to 300 Bcf at the end of '06. Gross proved developed reserves from our horizontal wells ranged from 0.1 to 4.7 Bcf per well, and the average gross proved undeveloped reserves per well, including our year-end reserves, was approximately 1.5 Bcf per well, up from 1.15 Bcf per well at the end of 2006.

During this past year, we have transitioned to drilling longer laterals, completing almost all our wells with slickwater stimulations and we began to see the benefit of our 3-D seismic program. At year-end we had acquired approximately 525 square miles of 3-D data in the Shale area and expect to have acquired or purchased another 370 square miles of 3-D seismic data by the end of 2008.

As of February 19th, we have drilled and completed 116 wells with lateral lengths over 3,000 feet. Our average initial production rate for these wells has been 2.1 million cubic feet per day and average well cost has been $3 million. We currently expect average ultimate gross recovery from wells drilled with greater than 3,000-foot laterals to range from 2 to 2.5 Bcf per well.

During 2007, our average completed well cost for our operated horizontal wells was approximately $2.9 million. During the fourth quarter, the typical horizontal well had an average lateral length of 3,120 feet and an average time to drill to total depth of 15 days from reentry to reentry. We are seeing meaningful improvements in early-time well production and in our drilling and completion costs per foot of well. And this trend has continued into the first quarter. We're currently forecasting an average drill and complete cost of $3 million per horizontal well in 2008.

In late 2007, we began a project to demonstrate the benefits of a full-scale development strategy in a four-section area of our Southeast Rainbow pilot area in Conway County. We plan to drill 22 wells in total there, of which 21 will be developed on multi-well pads and able to be simultaneously fracture stimulated. Results here will provide key information regarding potential cost savings, well spacing, benefits of longer laterals, simultaneous completions and other centralized operations. While we're still very early in the project and have only drilled a portion of the total wells, we can see the potential for cost reductions, independent of service cost variations.

In our conventional Arkoma activities in 2007, we invested approximately $148 million in our conventional play, drilling 114 wells, of which 81 were successful, 23 were in progress at year-end, and resulting in adds of 60.6 Bcfe. Our 2007 production from the Arkoma Basin was 23.8 Bcfe, an 18% increase when compared to 2006 production, and proved reserves there totaled 304 Bcf at year-end.

At our Ranger Anticline area, located in the southern part of the Basin, we successfully completed 52 out of 67 wells during 2007, excluding 12 wells that were still in progress at year-end. Our net production at Ranger increased to 9.5 Bcf from 5.7 in '06, an increase of 67%. Since drilling our first successful well at Ranger in 1997, we have successfully drilled 156 out of 185 wells, adding 114 net Bcf of reserves at a finding cost of about $2.00 per Mcf, including reserves provisions.

During 2007, we accelerated our drilling at our Midway prospect located just 11 miles north of the Ranger project. We drilled 26 wells, all of which were productive or still in progress at year-end. We operate these wells with an average working interest of 60%.  At year-end '07, we held approximately 31,000 gross acres in our Midway project area and depending on the performance of the wells drilled, there may be significant drilling potential on our acreage going forward.

In 2008, we plan to invest approximately $132 million in our conventional Arkoma program and drill approximately 100 to 110 wells, including 40 wells at the Ranger project and 45 wells at Midway.

In East Texas, for the year, we drilled 80 wells, primarily in our Overton field and our Angelina River trend area. Net production from East Texas was 29.9 Bcfe during 2007, compared to 32 Bcfe in 2006. Our drilling program at Overton during 2007, focused on drilling mostly our proved undeveloped locations. We invested $96 million during the year to drill 45 wells, all of which were completed.

Our Angelina River trend properties are concentrated in several separate development areas located in four counties in East Texas. Our primary drilling targets are the Travis Peak and the James Lime formations. During 2007, we invested $88 million to drill 31 wells in our Angelina trend, all but 1 of which were successful or in progress at year-end. Our drilling results included a new discovery at the Jebel prospect area in Shelby County in the James Lime formation.

The Timberstar-Mills on 1H horizontal discovery well was completed in December, with an initial production rate of 12.1 million cubic feet per day and is producing approximately 4 million cubic feet per day after 44 days of production. Earlier this month we placed our second James Lime horizontal well on production, the Sessions Heirs No. 16 well, located in Angelina County, approximately 35 miles west of our first discovery well, at an initial production rate of 6.7 million cubic feet per day. We are currently completing our third operated James Lime horizontal well and drilling our fourth and fifth wells. At December 31st, 2007, Southwestern held approximately 87,000 gross acres at Angelina, with an average working interest of approximately 73%.

Also in 2007, we invested approximately $42 million in our New Ventures program, including $17.5 million to purchase acreage in the Pennsylvania, Marcellus Shale play. We currently hold approximately 98,000 net undeveloped acres in the play we believe to be perspective and we plan to spud our first vertical well on the acreage during the first quarter.

We also invested approximately $10 million in 2007 and drilled 25 wells in our Riverton coalbed methane project in Caldwell Parish, Louisiana, of which 18 were successful and 7 in progress. We have approximately 32,000 net acres in this project area that targets the Tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet.

In summary, we're very pleased with our record results in 2007. We continue to be very encouraged by our success in our Fayetteville Shale project, and our programs in the Arkoma Basin and East Texas are performing well also. We're looking forward to continued strong results in 2008, including meeting or exceeding our PVI target of 30 to 35% production growth and very significant increases in proved reserves.

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

Harold Korell: Before Greg starts, Richard, I think you misstated one thing early on that we should probably correct for the record, and that was that our guidance for the year remains at 148 to 152 Bcfe. I think when you said it, you said 142. I know the number is 152.

Richard Lane: That's correct.

Greg Kerley: Thank you, Richard, and good morning. We reported net income of $221.2 million in 2007, or $1.27 per share, up 36% from the prior year. While our operating cash flow, defined as cash flow from operating activities before changes in our operating assets and liabilities, increased 57% to $651.2 million⁽¹⁾. These increases were largely driven by the significant growth in our production volumes from the Fayetteville Shale.

Our earnings for the fourth quarter were $71.6 million or $0.41 a share, more than double the $33.8 million we earned in the fourth quarter of 2006. Our operating cash flow also increased significantly to $204.3 million⁽¹⁾, up from $108.7 million⁽¹⁾ in the prior year, again, driven by the significant growth in our production volumes.

Operating income for our E&P segment was $358.1 million in 2007, up from $237.3 million in 2006. We produced 113.6 Bcf equivalent in 2007, and realized an average gas price of $6.80 per Mcf. Our commodity hedging program increased our average gas price during the year by $0.64 an Mcf.

Our current hedge position, which consists of fixed price swaps and collars, provides us with support for a strong level of cash flow, and for 2008, we have close to 80% of our projected natural gas production hedged. We have 70 Bcf hedged with fixed price swaps at an average price of $8.43 an Mcf and we have 48 Bcf hedged through price collars with an average floor price of $7.92 and an average ceiling price of $11.60. Our detailed hedge position is included in our Form 10-K filed yesterday.

Our lease operating expenses per unit of production were $0.73 per Mcf in 2007, up from $0.66. The increase was due primarily to increases in gathering and compression costs related to our operations in the Fayetteville Shale. We expect our per-unit lease operating cost to range between $0.85 and $0.90 per Mcf in 2008, due to the increased production volumes from the Fayetteville Shale.

General and administrative expenses per unit of production were $0.48 per Mcf in 2007, compared to $0.58 in 2006. The decrease was primarily due to the effects of our increased production volumes, which more than offset increased compensation and related costs, primarily associated with the expansion of our E&P operations. We added a total of 243 new employees during 2007, most of which were in our E&P segment. We expect our general and administrative expenses per unit of production to range between $0.42 and $0.47 per Mcf in 2008.

Taxes, other than income taxes, were $0.16 per Mcf equivalent 2007, down from $0.30 in the prior year, due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes and severance tax refunds related to our East Texas production during the year. In 2008, we expect our rate to range between $0.20 and $0.25 per unit of production.

Our full-cost pool amortization rate averaged $2.41 per Mcf in 2007, compared to $1.90 for 2006. Our amortization rate is primarily impacted by the timing and amount of reserve additions and the cost associated with those additions.

Operating income for our midstream services segment was $13.2 million in 2007, up from $4.1 million in 2006. The increase was primarily due to higher gathering revenues related to our Fayetteville Shale play, partially offset by increased operating costs and expenses. In 2007, we had gathering revenues of $37.7 million on volumes of 78.7 Bcf, compared to $7.9 million of gathering revenues in 2006 on volumes of 14.6 Bcf. We are currently gathering about 400 million cubic feet of gas per day in the Fayetteville Shale play area, through approximately 590-miles of gathering lines. We expect our operating income from our midstream activities to more than double in 2008, and range between $27 and $30 million, as reserves related to the Fayetteville Shale continue to be developed and production increases.

Operating income in our utilities segment was $10 million in 2007, up from $4.5 million in 2006. The increase in operating income was due to the implementation of a rate increase, which became effective August 1 of last year, along with colder weather and a decrease in operating cost and expenses. In November, we signed a stock sale and purchase agreement for the sale of our utilities subsidiary for $224 million plus working capital. The transaction is subject to certain closing conditions and regulatory approvals and is expected to close approximately midyear 2008.

At December 31st, 2007, we had total indebtedness of approximately $979 million, including $842 million borrowed on our revolving credit facility, resulting in a capital structure of 37% debt and 63% equity. In January, we issued $600 million of 7.5% senior notes due 2018. The proceeds from the notes were used to pay down our revolving credit facility. At December 25th, we had about $280 million borrowed under our facility, which has a current capacity of $1 billion. The combination of our growing cash flow, planned asset sales and available borrowing capacity provides a significant flexibility in executing our planned capital investment program in 2008.

Finally, we announced a 2-for-1 stock split yesterday. The split will be effective for holders of record on March 14th, and payable on March 25th, 2008.

That concludes my comments, so now we'll turn back to the operator who'll explain the procedure for asking questions.

Questions and Answers

Richard Tullis: Nice quarter. Just two quick questions. One, what's your current outlook on potential severance tax changes in Arkansas?

Harold Korell: It's a good question. The playing field is running in various directions. For those of you who follow it, I'm sure that you've seen that there is a proposal to have an initiated act up there by an individual that has put that forth. I think that the outcome of all this will be pretty much dependent upon factors that somewhat are within our control, some outside our control.

Our position on this is that we are continuing to work with the leadership of the state to propose a plan that would not unduly burden our operations.  And so, that's our effort.  And as far as what might eventually come, it's a little bit difficult to say as there are continuing conversations on a daily basis.

Richard Tullis: Do you think some of the wells that you're drilling could actually be exempt similar to what's done in say Oklahoma and Texas?

Harold Korell: The potential for that would certainly be in line with what the governor has stated up there is that he wants a severance tax that is fair relative to other states, and those parameters are definitely included in nearby states.

Operator: And moving on, our next question will come from Jason Gammel with Macquarie Capital.

Unidentified Participant: Hi.  This is actually his associate.  I have a question on the East Texas.  Based on preliminary reserve, there are no net reserve bookings in East Texas.  What about--you would have thought that with 80 wells in the Angelina River Trend we would have seen some reserve booking.  Can you comment on that, please?

Richard Lane: Well, the--yes, we had the drilling in the Overton Field and drilling in our Angelina River Trend.  What's affecting some of that is we developed mostly pre-existing locations, proven undeveloped locations at Overton, and then also we had some performance revisions in the area that affect that number.

Unidentified Participant: Okay. Thanks.

David Snow: Yes.  I'm trying to get an idea of what--the amount of acres you would tap into with these 3,000-foot lateral lengths.  I'm just trying to get an idea as to what Bcfs per unit of acreage you are looking at recovering as you go into longer laterals.

Harold Korell: Well, the--our materials--recent materials here provide some guidance on that and also give some--a look at some of the production histories of the wells that are longer than 3,000 feet, so I would guide you to referencing that.  But I can tell you that it's early in our history in the 3,000-foot or longer wells, but we think that it's reasonable for those to ultimately recover 2 to 2.5 Bcf per well.

David Snow: Well, would you be able to put those--how many of those could you put into a 640-acre spacing, or is that something you've got to determine with your down spacing and simul frac pilot?

Harold Korell: It will depend on the ultimate spacing that you've mentioned there.  If you look at 80-acre spacing, which we're not certain that's ultimately where we'll be, but it's kind of our nominal development plan right now.  That's about eight wells per 640.

On the other hand, where we are currently carrying on this--we call it development project area in the four sections in the Southeast Rainbow area or whatever we call that area is we actually are drilling--the plan there is to drill six wells per section.  If you laid it out--and I've tried to describe this and maybe I'd refer you, if you weren't on the last teleconference, back to that description so I--maybe I don't have to do that completely again.  But we would be drilling north/south wells spaced 1,000 feet apart.  And that would--if you lay out a section that would mean there would be six wells per section if you repeated that.

Now, what we don't know yet is we don't know whether the wells being spaced 1,000 feet apart is the appropriate spacing to develop all the economically recoverable reserves out of those sections.  And the only way for us to know that in fact is to do one thing and then test another thing.  So right now, we're at the point of drilling in that one development area wells spaced 1,000 feet apart, which would result in six wells per section, fewer wells than eight--two wells less than eight, and that would repeat across.  But our intention certainly is that at some point we need to also do a test drilling wells closer than 1,000 feet apart possibly.  And it will depend upon the results and performance of what we're doing in the development area.

One of the things that they clearly--I know some of the people who follow us have trouble with this--the concept that we're still very sparsely spaced everywhere because we have so much acreage that we're drilling on.  And we're doing this one test area, so that we can try to begin to answer these questions.  But we can't answer the questions about is it 80-acre of 40-acre or some other thing in between.  Some of the other companies have been drilling wells on tighter spacing already. They may have some views on it.  I don't know that their views and ours will be the same, but we'll have to test this on our own.

Brian Singer: Can you talk more about the James Lime?  I guess, what do you think based on the drilling that you've done so far, how many--how far this play extends within your acreage?  And when you look at the rates of return that you're seeing, how would you stack up the James Lime versus some of your other I guess non-Fayetteville opportunities?

Richard Lane: Well, Brian.  We're really just starting into that.  We do have a pretty nice size acreage block there.  Of interest is that we've--where we've drilled is kind of the far east part of our block at Jebel.  And then, the other well I referred to, the Sessions well, would be the most westerly part of our acreage.  So it's nice to see something 30-some miles apart still be present and productive.  It certainly doesn't prove up every acre in between, but there's a lot--a lot of the story left to be told there as we go this year.  We said we have drilled maybe 10 to 15 wells in that program this year and that will certainly give us a lot more look at how much of that acreage could be prospective.  But early on--in terms of returns, early on we see good potential for a nice return that exceeds our PVI threshold or we wouldn't be doing it, so that's encouraging.  We don't have tha t much production history yet though, so I wouldn't want to compare it to other projects yet.  But it definitely has the potential to exceed our return thresholds.

Brian Singer: Thanks.  My second question is just looking at natural gas prices that have moved up recently, what capacity and interest do you have in ramping up activity if gas prices do stay strong and where would that be if so?

Harold Korell: Brian, that's a good question for us not just with gas prices moving up some, because I guess when gas prices are moving around my normal answer to that is the current months we aren't a whole lot affected by how we think generally and we're looking at the out prices and we've done a fair amount of hedging.  So that all--that statement still is kind of--is the overarching statement on gas prices.  But our job as we go forward here in the--in 2008, we have a plan right at this point in time for a $1.45 or $1.46 billion capital plan.  And the guidance that we have out there, depending upon what gas prices are, but if you look at $7 or $8, generally we would have cash flows of the $850 to $900 million range.  And I guess slightly--maybe slightly above that.

But the point is we're still short on cash flow to fill the capital needs. As Greg mentioned earlier, we have the utility we're selling this year.  We're considering some other sales of assets and--in order to fill that gap, along with our increasing cash flow.  So we have to constantly keep an eye on all of the variables.  Gas price is one of the variables, but potential asset sales is another.  We need to conclude the sale of the utility and monitor all of those things.  

There is no doubt that we have pressure internally in Southwestern Energy to do more.  We have pressure to--would like to at some point when we get our organization fully fleshed out do more drilling in the Fayetteville Shale.  We would like to accelerate drilling there.  If this East Texas--if these wells hold up and additional wells we drill look good, we're going to have a desire, as I put it, to drill more wells in East Texas.  We haven't begun drilling in the Marcellus yet.  And then, those projects that Richard described in the conventional play in the Arkoma are also looking quite good.

So the good thing is we are flush with opportunities, but we want to be good managers of our balance sheet at the same time.  So all of those things have to come together.  And it's too early for us to talk about increasing our CapEx right now.

Tom Gardner: Let's see.  Well, Brian asked some good questions, but let me just follow-up on his James Lime question.  I'm looking for more color with respect to how you're going about identifying prospects and how big could this play be?  And perhaps any idea of the relationship between initial rates and ultimate recoveries you might have would be helpful as well.

Richard Lane: Well, I mean, the size of the play as an industry could be very large.  I would tell you that our acreage position we've talked about is over 95,000 gross acres, so that gives you a sense of the magnitude internally here for Southwestern Energy.  I probably wouldn't speculate a lot more about what these wells ultimately will do as in other plays like this.  The initial rate tends to give you some indication of the ultimate recovery, but not always.  We think they'll exceed our threshold as I mentioned, but we're going to have to see some more production history.

Tom Gardner: Okay.  And of the wells you plan to drill in 2008 company-wide, what fraction are not booked as proved as of year-end '07?

Richard Lane: Well, the biggest factor there--the area obviously would be in the Fayetteville Shale.  Really what you're asking there I guess is how many wells in the Fayetteville Shale program are--in '08 we'll be drilling undeveloped locations.  I can tell you that percentage in '08 is pretty low, because we are still--we're still needing to step out and hold acreage.  So it might not be as high as you might think.  And then, that would probably go up as time goes on.  So because so many of our wells are moving only a second or third well in a section and moving into new sections and part of the strategy to hold land, it's not that great of a percent in 2008.

Jeff Hayden: Morning, guys.  A little bit of a follow-up question.  I believe it was to what David was asking.  When you guys are looking at the Rainbow pilot, given kind of the spacing pattern you guys are initially thinking, about what kind of recovery factor would that imply?  And then, second question, you guys have built up a pretty good inventory of 3-D seismic, you've drilled a lot of wells across your acreage, you're building up more.  Can you give a sense--you've had that sort of 50% of your acreage number out there in your presentation for a while.  Can you give any sort of an update on how much of your acreage position you really think is going to be economical right now?

Richard Lane: Well, the recovery--Jeff, the recovery--ultimate recovery percent there is still not totally defined.  We think that something in the 20% range or possibly higher is reasonable from what we've seen so far.  And on the 3-D seismic, we didn't get a lot of utilization of that in 2007 because the data was being acquired and being processed as we were going through the year.  And then, late in the year we started to get it in-house and be a tool for us and starting to see some help from that.  In 2008, a much greater percent of drilling will be utilizing our 3-D seismic.  I think we've--our look at that when we put our plan together was somewhere around 75% of our wells would be covered by that.

The guidance towards the percent of the acreage that will ultimately be developed, probably your best thing to refer to there is some of the materials we've put out.  We have public materials.  We have a map that shows the distribution of all the pilot areas that we have drilled and you can see the--how much that's been delineated there.  I'm not trying to avoid an exact number, but that's the best thing to look at.

Jeff Hayden: All right.  Thanks a lot, guys.

Robert Christensen: Good morning.  How is the conventional exploration going in the Fayetteville Shale leasehold, if you will?  It seems like it might be backend loaded in the year.  Is that because of the seismic just arriving in-house or what's going on there, Richard, please?

Richard Lane: Well, it's going very well from my perspective.  We've encountered conventional pay zones through a pretty broad area in the play.   We're seeing really nice rates from the majority of those wells and strong economics given the relatively low cost to drill and complete those wells.  I think your assessment is right in terms of the timing for '08.  We saw the activity really by virtue of our plan and when we would dedicate a rig to that program really starting to kick in about now.  So I think you'll--we'll have more to report on that in the second quarter, but are very encouraged.

Robert Christensen: And a follow-up.  How much horsepower in the way of compression would you estimate has been put into the Fayetteville Shale as of this moment?

Harold Korell: We don't have our Midstream guy here.  It's over 100,000 somewhere.  But I--John, do you have--?  So 105,000, 106,000 horsepower.

Robert Christensen: How does that work?  I mean, when you install it I take it, it would be centralized.  And does it run all out the day you install it, or do you start out with a 1,200 horsepower machine and do you start life out with 700 horsepower, then it ramps and ramps and ramps as the field--as individual wells decline--pressures decline?  How--just some just basic laymen's terms how that's all unfolding.

Harold Korell: Yes, well, when you look--Bob, when you look at our map and look at the areas that we're drilling across, as Richard said earlier, it's spread out.  It's a very broad area that we've drilled in.  And in order to get production tests and establish well decline curves and all, we have to produce.  So that means we have to lay lines to those wells and that means we have to have compression anyplace that we are reporting a production curve.  So the compression is--in general is spread out, but it's also--the other way of saying it is it's centralized, because off the main gas transmission lines we'll lay laterals - we call them laterals - out into the field area to a central gathering point location.  And then, multiple wells eventually will come to that central gathering point.  We have many central gathering points though.  There's not just one.  There are many because of being such a broad area.

So in the beginning, let's say, take the boundary condition case of one well, meaning one well only say drilled out there all by itself, then you'll have one compressor. Depending upon the volume that would come out of that one well, it may only partially load that compressor, or over time you have to change that compressor as you drill more wells in order to effectively load it.  So one of the things that actually--I don't know if you're touching on it, but efficiency of compression is one of the matters here because the compressors run and they use fuel and they are running 24 hours a day.  So if they're not fully loaded, you'll have higher operating costs than you would like.  So one of the things that over time we have to try to optimize on, and we're by no means there.  Our guys are doing a great job, but when we're drilling wells over such a broad area, it doesn't afford you the complete efficiency that you would want to have, which ultimately is you go into an area, along with laying out the geological parameters and the well spacing, you would also think through how you drill that relative to the compressor that you size for it.  You don't want to--in other words, you don't want to drill so much in an area where you have to install way more horsepower than you eventually need over the life of that.  So there's a lot of optimization that will come along.  The good thing is having DeSoto Gathering that's doing this for us, it gives us a lot more flexibility along those lines.

Scott Hanold: On the James Lime play, just one other question.  I know that you've talked quite a bit about this play, but it looks pretty exciting.  And looking at your position and what others are doing there, how much acreage do you think is there left to pick up?  Is there more?  Are you guys sort of actively looking at picking up some more in this play?

Harold Korell: There is more from our perspective and our opinion where we see the play to have potential.  And we're still active doing some of those things, Scott.  Obviously, we don't want to pinpoint that, but we don't want to call the Chesapeake jets in on our troops.

Scott Hanold: Fair enough.  And then, a second question.  You--it looks like you sold your assets in Culberson County. And I guess you hinted towards looking at other opportunities to monetize some assets potentially.  Can you just talk in a general sense of what kind of efforts you're doing or what kind of assets could be up for sale in the company yet?

Harold Korell: We generally don't talk a whole lot about that, but we have mentioned the Permian and Gulf Coast areas that we would consider selling this year.  And they're a potential for other things that we're thinking about.

Gil Yang: Hi.  I have I guess some pretty routine questions that maybe were partially answered before.  You made a comment in the press release that LOE would go up in '08 because of higher volumes.  And that seems a little bit counterintuitive, because I would think that you would get some kind of cost leverage synergies.  Could you, Harold and Richard, maybe explain that a little bit?

Richard Lane: I think the effect there, Gil, is where the weighting of the production is.  DeSoto, the Fayetteville Shale play, as we--as it becomes more and more a higher percent of our total company production - and we've just discussed a lot of the reasons why those lifting costs are what they are, that's really the effect you're seeing is the--not so much the throughput driving that.  It's where the throughput is.

Gil Yang: Okay.  So the Fayetteville is higher cost because you're still ramping and so you are somewhat inefficient in terms of capital usage.

Harold Korell: Well, there's a couple of things.  The Fayetteville, for example, is higher operating cost than our old conventional Arkoma Basin production.  So as we--as a company, as we have more of the Fayetteville coming online relative to our old base, that's going to be higher.  Our operating costs per unit aren't--I think the way you said it in the beginning was it seemed strange to you that we would say that our operating costs are going to be higher with higher volumes.

It's not -- higher volumes should always generally drive down, as you would think, operating costs per unit.  But because a greater proportion of our production will be from the Fayetteville relative to our old lower-cost operating cost per unit of production, it will, therefore, drive our average up.  And some of the reasons that the Fayetteville would be higher are the Fayetteville requires compression.  I've just answered questions from Bob Christensen about that.  We are not at the most efficient time period in the life of the Fayetteville either in regard to operating costs regarding compression.

Do you have something else?

Richard Lane:  You'd mentioned we're looking at the Gulf Coast Permian.  If that ultimately happened, it's one of our highest areas in terms of LOE, so that would be a positive effect on the total company.

Joe Allman:  Hey, Richard, could you tell us what the fourth quarter average cost was for the wells in the Fayetteville Shale, the longer lateral wells?  And I know your expectation for 2008 is an average of 3 million a day, but it seems that you're probably looking to drive that down.  What would be the big driver to getting the cost below the 3 million a day?

Richard Lane:  Well, our full-year '07 number, I think, was $2.9 million.  Our fourth quarter number was $3.0 million.  We've generally guided -- or we have guided the 2008 program to be about $3 million, and worth noting is that that absolute dollar amount is kind of holding while the size of the well we are engineering and producing is bigger.  So we've talked about it in the past; we're watching cost per foot, as well, and that's going the right way.  

So what kinds of things can affect it in 2008 are just more efficiencies.  As we get better and drill a higher percentage of development wells, we could get some help from service costs.  We got help in the second half of '07 there, and there's still some pressure on that.  And then the things that we've been talking about related to our demo project, we will, in fact, be drilling more wells even outside of that demo project, multi-well pad locations, so we'll get some effect -- some positive effects of that independent of service costs.

So a lot of things that we have to work at, some that we're starting to identify, and we'll see how that all comes together.

Joe Allman:  That's helpful.  And then just outside of the Fayetteville Shale, what are the trends these days in terms of drilling and completion costs?

Richard Lane:  In our active areas?  I would -- you know, I'd say that we've basically set a plan that is not too different than what we saw an average well be in '07, and to the extent we do better than that on service costs, we'll have a lower average well, I would think.  

Another factor in the Fayetteville Shale is we are still trying some new things on the completions, and as you know, the completion part of the well cost is the bigger of the drilling and completing, the bigger piece, and we're doing some things that we're seeing some good results from in terms of how we're perforating and how we're spacing all that.  That may give us some better well results.  If that's the case and we keep doing more of that, those actually would cost a little more, so a lot of moving parts there.  We're looking for the best economics.

Gil Yang:  Hi, yes, thanks.  Can you comment on your hedging activity for -- into '09?  Are you starting to think about layering on more hedges more aggressively for '09 yet?

Greg Kerley:  We have laid on some hedges in '09 over the last few months.  We've got a little over 100 Bcf hedged in '09, about a third of that, or 30% or so, with collars and some -- about -- bulk of it more in swaps, probably averaging $8.30 or so on the swaps, and we've got collars from $8 to over $10.50, kind of floor and ceiling.  And we've done some swaps in 2010.  Starting to look at that.  

So we are looking at that.  We've been watching it, obviously.  The market's run up here recently, too, and I expect that we will continue to be pretty active hedging, as we have done in the past, kind of little layers at a time.

Gil Yang:  Are you ahead of -- for '09, are you ahead of where you were for '08 at this time last year?

Greg Kerley:  Percent -- I don't -- we are volumetric-wise, yes.

Gil Yang:  Percent-wise?

Harold Korell:  You'd have to go look at that.  

Greg Kerley:  I don't know percent-wise.  We haven't provided guidance for 2009, so we really can't talk percentages of what we've got hedged.

Gil Yang:  Right.  Okay, thanks.

David Heikkinen:  Good morning.  I wanted to dig into the Southeast Rainbow project area to try to get a look at what the Fayetteville development can look like in the future.  What are your AFEs for wells in that area running now?

Richard Lane:  Let's see.  They're -- we have some longer laterals there that we're trying, David, so I think they're ranging from $3 to $3.5 million --

David Heikkinen:  Okay.

Richard Lane:  -- in that range.

David Heikkinen:  And then thinking about operating expenses, whenever you have centralized compression and basically a full development, where would that be for a concentrated development like this?

Richard Lane:  Well, we've attacked that part of it in this demo project.  Harold described the challenges with compression, and what he pointed to there is that the more certain you can be about volumes and ultimate needs, the better you can size those resources and load them more optimally.  And so that's -- that's what we're doing there.  We can -- we're modeling the rates in those wells.  Obviously, that's --

Harold Korell:  You know, and our intention on that is not to put out a model for it but rather to do it, and then we'll know what those numbers are, David.

David Heikkinen:  Okay.  Yes, I just see that as the -- a case study for your long-term development as that -- as we go through the year.

Harold Korell:  That's pretty much right.

David Heikkinen:  Just one additional quick question and just wanted to get an update as far as gathering and -- or kind of basin-wide pipeline capacity expansions, timing, as you look through '08 and '09.  Can you just give us an update on that?

Greg Kerley:  Sure, David.  This is Greg.  We've -- we think we're in real good shape for moving our gas in 2008 and 2009, but 2009 is dependent clearly on the Boardwalk pipeline, and its in-service date is scheduled for January 1 for all -- for both phases.  Phase one and phase two would be in service then, but actually phase one, the first phase, is a 65-mile lateral that will cross the lower portion of the play and tie in to the interstate pipelines on the east of Arkansas.  We'd actually be in service this fall, so --

David Heikkinen:  Okay.

Greg Kerley:  That would provide us effectively the entire 1.1 or 1.2 Bcf a day.  Capacity on that pipeline will be available in that first section, but it won't reach the other markets until both laterals are completed.

David Heikkinen:  Okay.

Greg Kerley:  And that schedule is -- we've reaffirmed recently with Boardwalk management that our project is on schedule, but its construction has not started.  It's scheduled to start sometime middle of this year, so -- but the -- I think 98% of the right-of-way for the production lateral has been acquired, quite a bit of the pipe has already been produced, and quite a bit of it has already been coated, so we're on schedule.  

David Snow:  Yes, hi.  I was wondering, I think the thickness goes thicker going to the east, and Southeast Rainbow is in the west, and I think you'd indicated you'd just done a lot of there as a reason for starting your pilot work in that area.  But could you -- is it still -- I mean is it essentially true that you get better results going east, on average?  I was looking for the latest slide.  And what's the average thickness there in the Southeast Rainbow area?

Richard Lane:  Well, the -- a lot of questions there.  I would say, generally, the thicker areas you would think if everything else was held constant would provide better wells, but, in fact, we've seen variability across the play, and we have not -- we've not seen systematically better wells associated with the thicker parts of the play.  The demo area, the South Rainbow area, is more of an average thickness-type area for us.  

David Snow:  Okay.  And I'm wondering if you could tell me just what is the more important consideration and constraint on ramping up capital constraints or labor -- personnel in the Fayetteville?

Richard Lane:  Well, I think that we have to consider all of those things, and for the past couple of quarters, I've been saying or would say that the people side of things and having the capacity there to manage, not just to carry on the operations.  But you've got to understand that when you're drilling so many wells, you need to be looking at what they're -- how they're performing in order to know you're doing the right things.  So I would say the last couple of quarters, that would be it.  

I think the question about capital is dependent upon how you'd want to fund the program, and we want to be efficient with our capital, so I would say it's a combination of both things at this point in time.  Clearly, we have a deficit in cash flow relative to our capital, but we have the ability to borrow, and we're selling some things.  

But there will be some point in time that I would imagine we would want to put more drilling rigs out here, and that will be driven by having the capacity to operate them efficiently; in other words, that means the people side of things, and the organization carried on effectively, and then layered on with the capital side.  And so it's a continuously moving target.  I don't think it's really possible to say one or the other.  If I had to, I guess I would say people right now, and the organization and drilling rigs and that side of it.  

Jeff Hayden:  Hey, guys.  Real quick question, jumping over to the Marsellus.  You mentioned in the release one vertical well, at least a vertical well in Q1.  What are kind of the drilling plans beyond that, and are you looking at potentially any horizontal wells this year?

Harold Korell:  Yes, Jeff, I think we're -- you know, we're looking at four or five wells, something in the nature of that size program for '08.  That's partially dictated by how fast we can get the important data back from the early wells, which we'll be doing a lot of extensive testing there, quarrying, sending that rock to the appropriate places to get things measured, so that partly dictates how fast you really want to go the first year.  We want to get our hands on some of the rock and see that the resource can be measured.  And then possibly we would -- maybe in an area we've already drilled a vertical, we would try a horizontal.

Jeff Hayden:  Okay.  Appreciate it.

Joe Allman:  Hi, again.  For 2008 in the Fayetteville Shale, is the focus of the drilling going to be on just developing the known areas, or do you still have a lot of delineation in the play to do?

Richard Lane:  Well, the development -- it depends how you define that, Joe, but generally, the development in '08 as a percent of our wells is quite a bit higher than in 2007.  

There will be less of reaching out and single-section wells, although there will be a lot of areas that we're appending on to where we've already drilled, and those may only have a well or two in them.  But as a percent, we're more in the development phase in 2008 than '07, certainly.

Joe Allman:  And what would be kind of a rough percentage there, like 80/20, development versus kind of reaching out?

Richard Lane:  Yes, I would say that's probably pretty close, maybe 75/25.

Joe Allman:  Got you.  Okay.  And then just a follow-up to my previous question.  So I didn't understand your answer.  So in your other active areas outside of Fayetteville, or even including the Fayetteville, are you seeing costs decline?  Are you seeing rig rates decline?  Are you seeing like stimulation cost declines?

Harold Korell:  We are -- right now, we're actually bidding some of those packages in certain areas, and I don't want to divulge those numbers, obviously, but we're seeing some more pressure on the pumping and cementing and completion side that could give us a little more relief this year.  Broad based, I would say there's not a lot of movement on the rig rates, at least where we're active.

Joe Allman:  Okay, got you.  Thank you very much.  Very helpful.

Robert Christensen:  Yes, how do you view the rent or purchase decision for compression?

Greg Kerley:  Well, right -- Bob, this is Greg -- right now, on compression we are really leasing the bulk of that because there's -- as Harold indicated, I mean where we're at in the project -- a lot of these projects are changing things out quite a bit as we drill some packed levels of wells, and then we'll increase the size either of compressors or compressor stations and add on.  So where we're at right now, we think that is what makes the most sense to us.  

Richard Lane:  Yes, I think another big factor there is our arrangements.  The terms of that have allowed us to have some flexibility in what we're providing.

Robert Christensen:  Well, thank you very much, guys.

Gil Yang:  Hi.  It looks like you bought, I guess, about 6,000 acres for -- or 4,000 acres for $25 million in the Fayetteville.  Is that right?

Richard Lane:  Can you repeat that?

Gil Yang:  Sounds like you bought about, I think, 4,000 acres for about $25 million in the Fayetteville?  Is that about right?

Richard Lane:  Maybe you're referring to the -- to integrations, where we're consolidating acreage.  When we get ready to drill a well, our all-in costs there in the play, I think what we said, is about $116 per acre.  There will be -- there are small amounts of acreage when we are doing the final roll-up of the section to get the final pieces of leases put together to drill a well, and those -- right now, those are going to run at higher costs.

Gil Yang:  Okay.

Richard Lane:  -- because there is a pretty intensive brokerage cost piece to that.

Harold Korell:  Greg, do you have something to add to that?

Greg Kerley:  No.

Gil Yang:  Is that what the $25 million land spend was in the Fayetteville in '07?  Or was that '07 or --

Harold Korell:  We're sitting here frowning at the moment because we're not sure.  Maybe we need --

Harold Korell:  I just told him -- I know the number --

Greg Kerley:  We need to do some checking to make sure what number you're specifically talking about.

Harold Korell:  I think Richard's -- my understanding is he's -- the integrations, the other pieces that we're doing to get land and the notifications to get land ready to be drilled on is being captured that -- at that --

Richard Lane:  But his number, $25 million for 4,000 acres, would say we bought some land for $6,250 an acre.

Harold Korell:  And we did not.

Richard Lane:  That doesn't sound -- there's something other in that number.

Harold Korell:  A lot of brokerage costs and things like that.  It's what earlier that related to.

Greg Kerley:  Maybe you -- maybe we could get a chance to research whatever it is you're talking about.

Gil Yang:  Okay.  All right.  Well, I'll follow up, but I think that maybe -- I may have done the calculation wrong, but you did say you spent 25 million in the year -- and I'm not sure how many acres you added in the year, but that's what I was getting at.

Richard Lane:  No, that's correct, and the part unsaid there is that a big piece of those costs are ongoing, getting land ready to drill wells, so you can't think of it as purely as bonus.

Gil Yang:  All right.  All right.  Thanks.

David Snow:  When might a midstream MLP make sense?  Is it too early in the growth of the midstream?

Harold Korell:  Yes.

David Snow:  A couple of years out maybe?

Harold Korell:  I really couldn't tell right now, David.  That wouldn't be something we'd be prepared to answer.

David Snow:  Okay, great.  Thanks.

David Heikkinen:  I hate to have the last question.  What's your pretax SEC PV-10?

Greg Kerley:  In the K -- we saw it the other day -- it's -- hold on just a second.  We've got one here that we can give you the number.

David Heikkinen:  Thanks.  I could get it from the K, or we could do it offline.

Greg Kerley:  $2.6 billion.

David Heikkinen:  Okay.  Thanks, guys.

Operator:  Okay, gentlemen, it appears there are no further questions, and Mr. Korell, I'd like to turn the call back to you for any additional or closing remarks.

Harold Korell:  Okay, well, not much more to say, just thank you for joining us today, and we look forward to a really good year again in '08.  Have a good weekend.

Operator:  And that concludes today's conference.  We'd like to thank you all for your participation.

(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 liabi lities with net cash provided by operating activities as derived from the company's financial information.

	3 Months Ended December 31,				12 Months Ended December 31,
	2007		2006		2007		2006
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	204,264	$	108,661	$	651,170	$	413,508
Add back (deduct):
Change in operating assets and liabilities		(16,547)		(9,860)		(28,435)		16,429
Net cash provided by operating activities	$	187,717	$	98,801	$	622,735	$	429,937