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 27, 2009

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 27, 2009, 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 27, 2009 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 27, 2009	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 27, 2009 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Fourth Quarter and Year-End 2008 Earnings Teleconference

Speakers:

Harold Korell; Chairman and Chief Executive Officer

Steve Mueller; President and Chief Operating Officer

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell – Chairman and Chief Executive Officer

Good morning, and thank you for joining us.  With me today are Steve Mueller, President of Southwestern, and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of yesterday’s press release regarding our fourth quarter and year-end 2008 results, you can call (281) 618-4847 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.

2008 was a tremendous year for Southwestern Energy. We recorded exceptional production and reserve growth as we continued to move up the learning curve in the Fayetteville Shale. We also reported record results in earnings and cash flow and the pro-active management of our balance sheet has placed us in great financial condition, with a debt–to–total capitalization ratio of 23% and nearly $200 million of cash on hand at year-end, and nothing borrowed on our $1 billion unsecured credit facility. However, the key accomplishment for us in 2008 was clearly the progress we made in our Fayetteville Shale play. Steve will give more details on all of our operating areas in a moment but, overall, I could not be any more pleased with our accomplishments in 2008.

As we enter 2009, we will continue to focus on organic growth and the value added for each dollar we invest. As a result of the low commodity price environment, we currently have a planned capital program of $1.9 billion for 2009, compared to the $2.0 billion plan we announced in December. Our current plan includes releasing four rigs during 2009. We will actively manage our capital program and have the flexibility to make further reductions if we find ourselves in this low natural gas price environment for an extended period of time. So, while there is a lot of uncertainty in today’s markets, we feel confident that when our industry comes out the other side of this commodity price cycle, Southwestern Energy will be extremely well-positioned—financially healthy and growing significantly at low cost levels.

On a more personal note, yesterday we announced my planned retirement and the planned promotion of Steve Mueller to CEO. We are extremely fortunate to have Steve and our strong management team to guide Southwestern Energy Company into the future. Being here at Southwestern has been a fabulous experience for me over the last 12 years. I have been so fortunate to be a part of this value creation story.

I will now turn the teleconference over to Steve for more details on our E&P and Midstream activities and then to Greg for an update on our financial results. Then we will be available for questions afterward.

Steve Mueller – President and Chief Operating Officer

Good morning.

In 2008, our gas and oil production totaled 194.6 Bcfe, up 71% from 2007, primarily as a result of increased production from our Fayetteville Shale Play where our production was 134.5 Bcf in 2008.  This is more than double the 53.5 we produced from the Shale in 2007.  We produced 31.6 Bcfe from East Texas and 24.4 Bcf from our traditional Arkoma Basin area in 2008.  Production from both of these areas was also higher than in 2007, up from 29.9 Bcfe in East Texas and 23.8 Bcf in the Arkoma Basin.  We produced an additional 4.1 Bcfe in 2008 from our other areas combined, including from our Gulf Coast and Permian Basin properties that we sold in 2008.

In 2008, we increased our year-end proved reserves by 51% to 2.2 Tcfe.  The 2.2 Tcfe of proved reserves were located approximately 71% in the Fayetteville Shale, 16% in East Texas, and 13% in the conventional Arkoma Basin.   

In 2008, we added 920 Bcfe of proved reserves and had net upward revisions of 98 Bcfe.  Both the additions and revisions were primarily driven by the performance of wells in our Fayetteville Shale play.  During 2008, we sold all of our remaining assets in the Gulf Coast and Permian Basin areas and approximately 55,600 acres in our Fayetteville Shale Play.  In aggregate, these divestitures had proved reserves of approximately 90 Bcfe.

Including both our additions and revisions, we replaced 523% of our 2008 production at a finding and development cost of $1.53 per Mcfe⁽¹⁾.  Excluding revisions, we replaced 473% of our 2008 production at a finding and development cost was $1.70 per Mcfe⁽¹⁾.  Proved developed reserves accounted for approximately 62% of our total reserves at year-end 2008.  

In 2008, we invested a total of $1.6 billion in our E&P business and participated in drilling 750 wells, 479 of which were successful, 11 were dry and 260 were in progress at year-end. Of the $1.6 billion invested, approximately 81% or $1.3 billion was in exploratory and development drilling and workovers, $83 million for leasehold acquisition, $66 million for seismic expenditures and $118 million in capitalized interest and expenses and other technology-related expenditures.  

Fayetteville Shale Play

Gross production from our operated wells in the Fayetteville Shale play increased from approximately 325 MMcf per day at the beginning of 2008 to approximately 720 MMcf per day at year-end to its current level of approximately 750 MMcf per day. We estimate that our 2009 production from the Fayetteville Shale will range between 229.0 to 232.0 Bcf, up approximately 70% from 2008.

We invested approximately $1.2 billion in our Fayetteville Shale drilling program during 2008, adding 984 Bcf in new reserves at a finding and development cost of $1.21 per Mcf⁽¹⁾.  This includes upward reserve revisions of approximately 159 Bcf due primarily to improved well performance. The finding and development cost, excluding these revisions, was $1.44 per Mcf⁽¹⁾.  Total proved net gas reserves booked in the Fayetteville Shale play at year-end 2008 were 1.5 Tcf, compared to 716 Bcf of reserves booked at the end of 2007. The average gross proved reserves for each of the proved undeveloped wells is approximately 1.9 Bcf, up from 1.5 Bcf per well at the end of 2007. Our gross proved reserves for wells that were placed on production in the second half of 2008 averaged 2.2 Bcf per well.

During 2008, we continued to improve our drilling practices in the Fayetteville Shale play. Our horizontal wells had an average completed well cost of $3.0 million per well, average horizontal lateral length of 3,619 feet and average time to drill to total depth of 14 days from re-entry to re-entry. This compares to an average completed well cost of $2.9 million per well, average horizontal lateral length of 2,657 feet and average time to drill to total depth of 17 days from re-entry to re-entry during 2007. Our initial producing rates also continued to improve, as wells placed on production during 2008 averaged initial production rates of 2,777 Mcf per day, compared to average initial production rates of 1,687 Mcf per day in 2007.  

During the fourth quarter of 2008, our horizontal wells had an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,850 feet and average time to drill to total depth of 13 days from re-entry to re-entry. This compares to an average completed well cost of $3.0 million per well, average horizontal lateral length of 3,736 feet and average time to drill to total depth of 12 days from re-entry to re-entry in the third quarter of 2008. We currently are running 22 drilling rigs in the Fayetteville Shale play area, 15 that are capable of drilling horizontal wells and 7 smaller rigs that are used to drill the vertical section of the wells.  Expected lateral length should average approximately 4,000 feet in 2009 and completed well costs are expected to decline slightly in 2009 to approximately $2.9 million per well.  This lower cost is a result of lower oilfield service costs that are projected to more than offset higher costs associated with the evolving completion techniques and longer laterals.

Since 2007, the continuous improvement of the company’s completion practices have consistently resulted in quarter-over-quarter improvements in average initial production rates of operated wells placed on production. The significant increase in the average initial production rate for the fourth quarter of 2008 also reflected the impact of the delay in the Boardwalk Pipeline. Initial rates were higher in all of the delayed wells because wells were shut-in for a longer period of time before being placed on production. In addition, the company generally placed wells with the highest initial rates on production first throughout the quarter. As a result, the remaining backlog of shut-in wells that were placed on production in the first quarter of 2009 generally had lower rates. These lower-rate wells are expected to result in a lower average initial production rate for the first quarter of 2009 as compared to the fourth quarter of 2008. Results through the first six weeks of 2009 indicate that the company’s operated wells have an average initial production rate of approximately 2.9 MMcf per day.

At year-end, we held approximately 875,000 net acres in the play area down from approximately 906,700 net acres at year-end 2007 due to the sale of acreage in May 2008 to XTO Energy, Inc. Approximately 26% of our leasehold acreage is held by production, excluding 125,000 acres in the traditional Fairway portion of the Arkoma Basin and 35 to 40% of the total 2009 wells are planned to hold acreage.  We have approximately 961 square miles of 3-D seismic data in the Play and plan to acquire approximately 139 square miles more in 2009.  This will bring our total seismic coverage to approximately 41% of our net position in the Fayetteville Shale, excluding our Fairway acreage.

Conventional Arkoma

We have approximately 281 Bcf of reserves in our conventional Arkoma properties compared to 304 Bcf at year-end 2007. In 2008, we invested approximately $133 million here and participated in 81 wells, 67 were successful and 8 were in progress at year-end, resulting in a 92% success rate.  Net production from the conventional Arkoma properties was 24.4 Bcf in 2008, compared to 23.8 Bcf in 2007.

In 2009, we plan to invest approximately $60 million in the conventional Arkoma program and drill approximately 25 wells.

East Texas Field

We have approximately 351 Bcfe of reserves in East Texas compared to 353 Bcfe at year-end 2007. In 2008, we invested approximately $160 million and participated in 50 wells in East Texas, of which 42 were successful and 8 were in progress at year-end, resulting in a 100% success rate. Net production from East Texas was 31.6 Bcfe in 2008, compared to 29.9 Bcfe in 2007.

Our 2008 drilling program was primarily focused on developing the James Lime formation in our Angelina River Trend area located in Angelina, Nacogdoches, San Augustine and Shelby Counties in Texas. During 2008, we participated in a total of 32 operated and non-operated James Lime horizontal wells.  The average gross initial rate for the 15 operated wells we placed on production in 2008 was 9.1 MMcfe per day.  At year-end 2008, we held approximately 86,000 gross undeveloped acres and approximately 17,000 gross developed acres at Angelina.

In the second quarter of 2008, we signed a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale intervals in Shelby, and San Augustine Counties, Texas. The first horizontal well, the Red River 877 #1 located in Shelby County, reached total measured depth of 16,144 feet in the fourth quarter of 2008 with a 2,718 feet lateral length.  It was completed in the first quarter of 2009 and is currently being tested. We expect to start drilling the horizontal lateral of the second well, the Red River 164 #1, within one week.  It is expected to be completed and tested in the second quarter of 2009. We are encouraged by our results to date and may invest more capital in 2009 than currently planned in the Haynesville/Bossier Shale play.

In 2009, the current plan is to invest up to $110 million in East Texas to drill approximately 40 wells, 34 of which are planned to be horizontal wells targeting the James Lime formation at Angelina.

New Ventures

At year-end 2008, we held approximately 138,600 net undeveloped acres in the United States outside of our core operating areas. We invested approximately $73 million in our New Ventures program in 2008, including $58 million in the Marcellus Shale play in Pennsylvania. At year-end 2008, we had approximately 115,000 net acres in Pennsylvania under which we believe the Marcellus Shale is prospective at a total cost of $530 per acre. During 2008, we drilled our first four wells, including our first horizontal well, on our acreage in Bradford and Susquehanna Counties, three of which have been production tested.  

In the first quarter of 2009, we increased our acreage position in the Marcellus Shale with the purchase of approximately 22,000 net acres in Lycoming County, Pennsylvania, for approximately $8.2 million. As a result, we currently have approximately 137,000 net undeveloped acres in Pennsylvania.

We plan to invest approximately $80 million in various New Ventures projects in 2009 including the Marcellus Shale Play.

Summary

In summary, as Harold mentioned, we are very pleased with our results in 2008. Our planned capital investment plan for 2009 of approximately $1.9 billion continues to build on that success.  It includes approximately 86% or $1.6 billion for E&P and $220 million for Midstream Services.  Managing through any significant drop in product prices is always challenging but with our focused approach and concentration on adding value we are looking forward to continued strong results in 2009.  We expect to meet or exceed our PVI target, have approximately 45% 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 – Executive Vice President and Chief Financial Officer

Thank you, Steve, and good morning.  

As you have seen from our press release, our production growth drove significant increases during 2008 in both our earnings and cash flow, and we ended the year with one of the strongest balance sheets in our history.  

For the calendar year, we reported net income of $568 million, or $1.64 per share, more than double our prior year record results and our cash flow from operating activities (before changes in operating assets and liabilities) increased over $500 million to total almost $1.2 billion for the year⁽²⁾.  

For the 4th quarter, we reported earnings of $104 million, or $0.30 per share, a 46% increase over the prior year period, as the significant growth in our production volumes substantially outweighed a 14% decline in our average realized gas price and higher operating costs and expenses.  Our commodity hedge position increased our average realized gas price by $0.79 in the 4th quarter, which helped us offset some of the effects of lower spot market prices and widening locational market differentials (or “basis”) that occurred during the quarter primarily as a result of the delay in the construction of the Fayetteville Lateral portion of the Boardwalk pipeline. Phase 1 of the Fayetteville Lateral was placed in service on December 24th and we are currently moving a little over 400,000 MMcf per day of our gas through the pipeline.  

We currently have close to 48% of our 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.48 per Mcf.  Our detailed hedge position is included in our Form 10-K filed yesterday.

Our annual results for our E&P segment were truly exceptional. Operating income for the segment was $814 million in 2008, up from $358 million in 2007.  We grew our production by 71% to 194.6 Bcfe and realized an average gas price of $7.52 per Mcf, which was up approximately 11% from the prior year.  

Our lease operating expenses per unit of production were $0.89 per Mcfe in 2008, up from $0.73 in 2007.  The increase was due primarily to increases in gathering and compression costs related to our operations in the Fayetteville Shale play, including the impact of higher natural gas prices on the cost of compression fuel.  

General and administrative expenses per unit of production were $0.41 per Mcfe in 2008, compared to $0.48 in 2007.  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 219 new employees during 2008, most of which were in our E&P segment.  

Taxes other than income taxes were $0.13 per Mcfe in 2008, down from $0.16 in the prior year, due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes.  

Our full cost pool amortization rate dropped to $1.87 in the 4th quarter and averaged $1.99 per Mcfe in 2008, down from $2.41 in the prior year.  The decline was due to the combined effects of our sales of oil and gas properties during the year, (the proceeds of which were credited to the full cost pool) and our low 2008 finding and development cost of $1.53 per Mcfe⁽¹⁾.

Operating income from our Midstream Services segment also grew significantly in 2008 to $62.3 million, up from $13.2 million in 2007.  The increase was primarily due to higher gathering revenues and an increase in the margin from our marketing activities, partially offset by increased operating costs and expenses.  At February 15, 2009, we were gathering approximately 830 MMcf per day through 864 miles of gathering lines in the Fayetteville Shale play area, up from approximately 405 MMcf per day a year ago.  

We worked hard during 2008 on strengthening our balance sheet and improving our liquidity. In early 2008, we issued $600 million of 10-year 7.5% Senior Notes and used the proceeds to pay down our $1 billion revolving credit facility.  We believe our credit facility will provide us with a significant source of liquidity through its maturity in October of 2012, and it is not secured by any assets and our ability to borrow is not tied to our reserves.

We ended the year with almost $200 million of cash on hand, nothing borrowed on our $1 billion revolving credit facility and had reduced our debt to capitalization ratio during the year from 37% down to 23% and had total debt outstanding of $735 million at year end.

We are well positioned to weather the current low commodity price environment with a strong balance sheet, excellent liquidity and one of the industry’s lowest cost structures.  That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

Explanation and Reconciliation of Non-GAAP Measures

(1) Finding and development costs - Finding and development (F&D) costs are computed by dividing acquisition, exploration and development capital costs incurred for the indicated period by reserve additions, including reserves acquired, for that same period. The following reconciles F&D costs to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69.

	For the 12 Months Ending December 31, 2008	For the 12 Months Ending December 31, 2007	Fayetteville Shale Play 2008
Total exploration, development and acquisition costs incurred ($ in thousands)	$ 1,559,995	$ 1,370,876	$ 1,191,558
Reserve extensions, discoveries and acquisitions (MMcfe)	920,181	507,855	824,706
Finding & development costs, excluding revisions ($/Mcfe)	$ 1.70	$ 2.70	$ 1.44
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe)	1,018,281	538,830	983,635
Finding & development costs, including revisions ($/Mcfe)	$ 1.53	$ 2.54	$ 1.21

The company believes that providing a measure of F&D costs is useful for investors as a means of evaluating a company’s cost to add proved reserves, on a per thousand cubic feet of natural gas equivalent basis. These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in Southwestern’s financial statements prepared in accordance with GAAP (including the notes thereto). Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods prior to the periods in which related increases in reserves are recorded and development costs, including future development costs for proved undeveloped reserve additions, may be recorded in periods subsequent to the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in Southwestern’s filings with the Securities and Exchange Commission, future F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern’s F&D costs may not be comparable to similar measures provided by other companies.

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

	12 Months Ended December 31,
	2008	2007
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 1,167,494	$ 651,170
Add back (deduct):
Change in operating assets and liabilities	(6,685)	(28,435)
Net cash provided by operating activities	$ 1,160,809	$ 622,735

Southwestern Energy Company Fourth Quarter and Year-end 2008 Earnings Teleconference Transcript

February 27, 2009