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, at 10:00am Eastern, Southwestern Energy Company will host a telephone conference call for investors and analysts.  The prepared teleconference comments are furnished herewith as Exhibit 99.1.

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

Exhibit Number	Description
99.1	Prepared teleconference comments 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: February 29, 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	Prepared teleconference comments for February 29, 2008 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Fourth Quarter and Year-End 2007 Earnings Teleconference

Speakers:

Harold Korell; President, Chairman and Chief Executive Officer

Richard Lane; Executive Vice President and President of the company’s Exploration and Production business

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell - CEO, President, Chairman

Good morning, and thank you for joining us.  With me today are Richard Lane, the President of our Exploration and Production 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 statements 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.

2007 was an outstanding year for Southwestern Energy.  Looking at our achievements, we grew our production volumes by 57% over 2006 levels and our reserves grew by 41% to 1.45 Tcfe, which represents a reserve replacement ratio of 474%. Our finding and development cost was $2.55 per Mcfe, which includes considerable front-end costs associated with developing a new play like the Fayetteville Shale.  

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 data base 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 2007 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 percent.  We are also looking forward to some new things we are developing, which include the results from our “development project” in the Fayetteville, our drilling results in the James Lime in East Texas and future opportunities we have 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 and then to Greg for an update on our financial results.

Richard Lane – EVP and President of E&P Operations

Good morning. In 2007, gas and oil production totaled 113.6 Bcfe, up 57% from 2006. 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, and 6.4 from our Gulf Coast, Permian Basin, and New Ventures areas combined.

Production for the 4th quarter of 2007 was 34.9 Bcfe, up 68% from the 4th quarter of 2006.  Our production from the Fayetteville Shale increased to 19.9 Bcf during the 4th quarter, up from 5.5 in the 4th quarter of 2006.  As a result of our continued strong performance, we have increased our 1st quarter production guidance range by 1.0 Bcfe, to 35 to 36 Bcfe.  Our full year guidance remains at 148 to 152 Bcfe.

In 2007, we increased our year-end proved reserves by 41% to 1.45 Tcfe.  The 1.45 Tcfe 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 31.0 Bcfe.  Both the additions and revisions were primarily driven by the performance of wells in our 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, our finding and development cost was $2.71 per Mcfe.  Proved developed reserves accounted for approximately 64% of our total reserves at year-end 2007.  

In 2007, we invested $1,380 MM in our exploration and production business activities and participated in drilling 653 wells.  Of the 653 wells, 439 were successful, 17 were dry, and 197 were in-progress at year-end for an overall success rate of 96%.  Of the $1,380 MM invested in 2007, approximately $1,130 MM, or 82%, was for drilling wells, $166 MM was for leasehold acquisition and seismic, and $84 MM was in other costs.

Fayetteville Shale Play

In our Fayetteville Shale Play in 2007, we invested approximately $960 MM, including $789 MM to spud 415 wells, $97 MM on seismic, $25 MM on land, and $49 MM 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 represent approximately $0.20/Mcfe of the total finding costs.

At the end of 2007, we held a total of approximately 907,000 net acres in the play area of which 143,740 net acres are held by Fayetteville Shale production and approximately 125,000 net acres are held by conventional production in the traditional Arkoma Basin Fairway.  Excluding areas held by production, our year-end acreage position has an average lease term of 6 years, and an average royalty interest of 15%.  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 MMcf per day at the beginning of 2007 to approximately 325 MMcf per day by year-end, and could approach 450 MMcf per day by the end of 2008.  As of mid-February, our gross production rate has increased to approximately 350 MMcf 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 Bcf 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 2006.  Gross proved developed reserves from our horizontal wells range from 0.1 Bcf to 4.7 Bcf per well and the average gross proved undeveloped reserves per well included in our year-end reserves was approximately 1.5 Bcf per well, up approximately 30% 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 of our wells with slickwater stimulations and 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 Fayetteville 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 MMcf/d and average well cost has been $3.0 million. We currently expect average ultimate gross recovery from wells drilled with greater than 3,000 foot laterals to range from 2.0 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 4th 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 re-entry to re-entry.  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 1st quarter of this year.  We are currently forecasting an average drill and complete cost of $3.0 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 4-section area of our Southeast Rainbow pilot area in Conway County. We plan to drill 22 wells in total, of which 21 will be developed on multi-well pads and 8 will be simultaneously fracture stimulated (simul-fracs).  Results will provide key information regarding potential cost savings, well spacing, benefits of longer laterals, simultaneous completions and centralized operations.  While we are still very early in this project and have only drilled a portion of the total wells, we can see the potential for cost reductions independent of service cost variations. We estimate that we could realize $100 thousand in cost savings per well related to rig moves and pad construction.

Conventional Arkoma

In 2007, we invested approximately $148 million in our conventional Arkoma Basin, drilling 114 wells, of which 81 were successful and 23 were in progress at year-end resulting in reserve adds of 60.6 Bcfe.  Our 2007 production from the Arkoma Basin was 23.8 Bcfe, an 18% increase when compared to 2006’s production of 20.1 Bcfe, and proved reserves 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 in progress at year-end.  Our net production at Ranger increased to 9.5 Bcf from 5.7 Bcf in 2006, 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 $2.00 per Mcf, including reserve revisions.

During 2007, we accelerated our drilling at our Midway prospect, located just eleven miles north of our Ranger Anticline area, by drilling 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 December 31, 2007, we held approximately 31,000 gross acres in our Midway prospect 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 the conventional Arkoma program and drill approximately 100 to 110 wells, including 40 wells at Ranger and 45 wells at Midway.

East Texas Field

For the year, we drilled 80 wells in East Texas, primarily in our Overton Field and our Angelina River Trend area. Net production from East Texas was 29.9 Bcfe during 2007, compared to 32.0 Bcfe in 2006.  Our drilling program at Overton during 2007 focused on drilling 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 primarily in four counties in East Texas. Our primary drilling targets are the Travis Peak and James Lime formations. During 2007, we invested $88 million to drill 31 wells at Angelina, all but one of which were successful or in progress at year-end. Our drilling results included a new discovery at the Jebel prospect area located in Shelby County, in the James Lime formation. The Timberstar-Mills 1H horizontal discovery well was completed in December 2007 with an initial production rate of 12.1 MMcf per day and was producing approximately 4.0 MMcf per day after 44 days on production. Earlier this month, we placed our second James Lime horizontal well on production. The Sessions Heirs #16H well located in Angelina County, approximately 35 miles west of our first operated discovery well, had an initial production rate of 6.7 MMcf/d.  We are currently completing our th ird operated James Lime horizontal well, and drilling our fourth and fifth operated wells.  

At December 31, 2007, Southwestern held approximately 87,000 gross acres at Angelina with an average working interest of approximately 73%.

New Ventures

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 of which we believe to be prospective. We plan to spud our first vertical well on the acreage during the first quarter.

We also invested approximately $10.5 million in 2007 to drill 25 wells in our Riverton coalbed methane project in Caldwell Parish, Louisiana, of which 18 were successful, and 7 were in progress at year-end. We have approximately 32,000 net acres in this project area targeting the Tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet.

Summary

In summary, we are 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.  We are looking forward to continued strong results in 2008 including meeting or exceeding our PVI target, 30 to 35% production growth, and significant increases in proved reserves.

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

Greg Kerley – EVP and CFO

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 operating assets and liabilities) increased 57% to $651.2 million.  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 $.41 per 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, up from $108.7 million 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 Bcfe 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 per Mcf.

Our current hedge position, which consists of fixed price swaps and collars, provides us with support for a strong level of cash flow.  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 per 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.  We also have hedged 107 Bcf in 2009 at attractive prices.  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 Mcfe in 2007, up from $0.66 in 2006.  The increase was due primarily to increases in gathering and compression costs related to our operations in the Fayetteville Shale play.  We expect our per unit lease operating cost to range between $0.85 and $0.90 per Mcfe in 2008 due to increased production volumes from the Fayetteville Shale.

General and administrative expenses per unit of production were $0.48 per Mcfe 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 Mcfe in 2008.

Taxes other than income taxes were $0.16 per Mcfe in 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.  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 Mcfe in 2007 compared to $1.90 for 2006.  Our amortization rate is primarily impacted by the timing and amount of reserve additions and the costs associated with those additions.

Operating income from 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 to $30 million, as reserves related to the Fayetteville Shale continue to be developed and production increases.

Operating income for our utility was $10.0 million in 2007, up from $4.5 million last year.  The increase in operating income was due to the implementation of a rate increase which became effective August 1, 2007, along with colder weather and a decrease in operating costs and expenses.  In November, we signed a Stock Sale and Purchase Agreement for the sale of our utility subsidiary for $224 million plus working capital.  The transaction is subject to certain closing conditions and regulatory approvals and is expected to close approximately mid-year 2008.  

At December 31, 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 February 25, we had about $280 million borrowed under our credit facility which has a current capacity of $1.0 billion.  The combination of our growing cash flow, planned asset sales and available borrowing capacity, provides us significant flexibility in executing our planned capital investment program in 2008.  

Finally, we announced a two-for-one stock split yesterday.  The split will be effective for holders of record on March 14 and payable on March 25, 2008.  That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.