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): July 31, 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 July 31, 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 July 31, 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: July 31, 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 July 31, 2009 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Second Quarter 2009 Earnings Teleconference

Speakers:

Harold Korell; Executive Chairman

Steve Mueller; President and Chief Executive Officer

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell – Executive Chairman

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

If you have not received a copy of yesterday’s press release regarding our second quarter 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.

Well, we are here to report another very good quarter, despite the low commodity price environment. Our gross operated production from the Fayetteville Shale reached a significant milestone of 1 Bcf per day in July, compared to approximately 500 MMcf per day this time a year ago. It is truly amazing to think that it was only 5 years ago when we told the world about the Fayetteville Shale play and our gross production from the play alone is now 1 Bcf per day. We have learned so much during that time and continue to do so, as the productivity of our wells continues to improve with each quarter. While current gas prices remain low, we believe lower industry drilling activity will result in higher prices over the next 18 months. With our focus on value creation and a world-class resource to develop in the Fayetteville Shale, we are well-positioned not only to weather the current low commodity price environment with our strong balance sheet and financial flexibility, but also to benefit greatly when prices return to more normalized levels.

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 Executive Officer

Good morning.

During the 2nd quarter of 2009, we produced 74.3 Bcfe, up 65% from the 2nd quarter of 2008.  Our Fayetteville Shale production was 60.6 Bcf, double the 29.6 we produced in the 2nd quarter of 2008.  Our remaining 2nd quarter production came from East Texas where we produced 7.8 Bcfe, and 5.8 Bcf from our conventional Arkoma properties.  

In the first six months of 2009, we invested approximately $852.5 million in our exploration and production activities and participated in drilling 338 wells.  Of this amount, approximately $695.4 million, or 82%, was for drilling wells.  Additionally, we invested $102.5 million in our midstream segment, almost entirely in the Fayetteville Shale.

Fayetteville Shale Play

In the first half of 2009, we invested approximately $793.0 million in our Fayetteville Shale play including both our E&P and midstream activities.  At June 30th, our gross operated production rate was approximately 990 Mmcf per day up from 850 Mmcf per day at the end of March.  We currently have 17 drilling rigs running in the Fayetteville, 13 that are capable of drilling horizontal wells and 4 smaller rigs that are used to drill the vertical portion of the wells.  We expect to participate in approximately 575 gross wells in 2009.

As we discussed in our last teleconference, during 2008, the majority of our gas production from the Arkoma Basin was moved to markets in the Midwest.  This included the Fayetteville Lateral Phase 1 portion of the Texas Gas Transmission, or Boardwalk, Pipeline which was placed in-service on December 24th. On April 1st, the Fayetteville Lateral Phase 2 and Greenville Lateral portions of the Boardwalk Pipeline were placed in-service and we began transporting a portion of our gas to Eastern markets.

As a result of recent inspections, repairs and maintenance on the Fayetteville Lateral, we have experienced curtailments that have impacted our ability to transport our production from the Fayetteville Shale. Beginning in April 2009, Boardwalk reduced the capacity on, or shut down, the Fayetteville Lateral on several occasions due to various activities, including maintenance and pipeline inspection. These activities, as well as similar repairs to the Greenville Lateral, are expected to continue, resulting in future curtailments.  As an example, the total Southwestern-operated gross production exceeded 1 Bcf per day on Monday and Tuesday of this week.  A line inspection was started on Wednesday and total production was reduced to 825 Mmcf per day.  This morning production is now restored to over 1 Bcf per day.

Currently, our transport capacity is sufficient for us to produce our operated wells at a rate of approximately 1,050 Mmcf per day gross.  Our net share of this plus our outside operated production is approximately 750 Mmcf per day.  Once repairs are started on the Fayetteville Lateral Phase 1 facilities on the Boardwalk pipeline, transport out of the producing areas will be limited to the existing Ozark and Centerpoint systems.  We estimate that our total operated production will be curtailed to approximately 650 Mmcf per day gross, or 450 Mmcf per day net.  In anticipation of these continued pipeline curtailments, we have revised and widened our previous gas and oil production guidance range for 2009.  Previously, it was 289 to 292 Bcfe and now is 278 to 288 Bcfe.  This revised production guidance is based on portions of the Fayetteville Lateral Phase 1 facilities being out of service for 45 to 60 days starting in September and assumes total curtailed volumes will be approximately 15 Bcf.  Even at this lower production guidance, we still expect to have production growth of approximately 45% over 2008 levels.

Since 2007, the continuous improvement of our completion practices has resulted in quarter-over-quarter improvements in average initial production rates.  The average initial production rate for wells put on production in the 2nd quarter of 2009 was 3.6 MMcf per day per well.  This is the highest average rate for any quarter since project inception, up 261 Mcf per day from our previous high in the 4th quarter of last year.

During the 2nd quarter of 2009, our horizontal wells had an average completed well cost of $2.9 million per well, average horizontal lateral length of 4,123 feet and average time to drill to total depth of 11 days from re-entry to re-entry. This compares to an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,874 feet and average time to drill to total depth of 12 days from re-entry to re-entry in the 1st quarter of 2009.

Haynesville

I’ll now move on to our Haynesville Shale activity where we are seeing encouraging results.  

The first horizontal well in our 50/50 joint venture targeting the Haynesville/Bossier Shale in Shelby and San Augustine Counties, Texas, the Red River 877 #1, reached total depth in the 4th quarter of 2008.  This well, which had a completed horizontal lateral of 2,718 feet, was production tested at a rate of 7.2 Mmcf per day in the 1st quarter of 2009 and is currently producing approximately 1.8 Mmcf per day. The second horizontal well, the Red River 164 #1, was drilled approximately 5 miles to the southeast and reached a total measured depth of 17,124 feet with a 3,800 foot horizontal lateral.  It was production tested at 13.4 Mmcf per day in the 2nd quarter and is currently producing approximately 7.8 Mmcf per day. We have completed drilling a third well, the Red River 619 #1 well, located in San Augustine County, with a measured depth of 17,244 feet with a 4,000 foot horizontal lateral.  Our fourth well, the Burrows Gas Unit #1-H was recently spud.  These wells are being monitored very closely and Southwestern Energy may participate in four additional Haynesville/Bossier Shale wells this year.  The capital for this drilling is included in our total 2009 capital guidance of $1.8 billion.

Conventional Arkoma & East Texas

Finally, we participated in drilling 13 wells in the conventional Arkoma Basin and 23 wells in East Texas during the first six months of 2009.  Twenty-one of the East Texas wells were James Lime horizontal wells. Production from our Arkoma and East Texas properties was 11.6 and 15.6 Bcfe, respectively, for the first half of 2009, compared to 11.9 and 16.0 Bcfe for the first six months of 2008.   We currently have two operated rigs operating in East Texas and none in the Conventional Arkoma.

Summary

In summary, our E&P and Midstream businesses are expected to have continued strong results in the remainder of 2009 and beyond.  We continue our focus on adding value.  Significant value is created as we improve the operational and production performance of each well drilled in our world-class Fayetteville Shale resource. In addition, we are also excited about our future opportunities in the Haynesville Shale, James Lime, and Marcellus Shales.    

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 Harold and Steve have indicated, we had a very solid second quarter.  

We reported net income of $121.1 million, or $0.35 per share, for the quarter, down approximately 11% from a year ago, as our production growth almost completely offset the effects of significantly lower realized natural gas prices.  While our cash flow from operations before changes in operating assets and liabilities (a non-GAAP measure reconciled below) was actually up 13% over the prior year to $325.3 million.

Our average realized gas price during the second quarter was $5.01 per Mcf, which was more than $3 per Mcf lower than our average realized price a year ago.  Our commodity hedge position increased our average realized gas price by $2.11 in the second quarter, and our locational market differentials (or “basis”) improved from first quarter levels to approximately $0.60 per Mcf.  

We currently have approximately 66 Bcf of our remaining 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.43 per Mcf.  We also have basis protected on approximately 50 Bcf in the third quarter and 30 Bcf in the fourth quarter of our expected gas production through hedging activities and sales arrangements at an average differential to NYMEX gas price of approximately $0.35 per Mcf.  Our detailed hedge position is included in our Form 10-Q that was filed yesterday.

Operating income for our E&P segment was $174.4 million in the second quarter of 2009, compared to $215.1 million in the second quarter of 2008.  The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses, which was partially offset by the 65% increase in our production volumes.  

Our total cash operating costs continue to be some of the lowest in the industry.  Our lease operating expenses per unit of production were $0.73 per Mcfe in the second quarter of 2009, compared to $0.95 for the same period in 2008.  The decrease primarily resulted from the impact that lower natural gas prices had on the cost of compressor fuel.

General and administrative expenses per unit of production were $0.34 per Mcfe in the second quarter of 2009, compared to $0.41 for the same period in 2008.  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.  

Taxes other than income taxes were $0.08 per Mcfe in the second quarter of 2009, down from $0.16 for the same period in 2008, primarily due to lower commodity prices.  

Our full cost pool amortization rate dropped to $1.46 per Mcfe in the second quarter, down from $1.82 per Mcfe in the first quarter of 2009 and down from $2.01 in the prior year.  The decline was primarily due to the non-cash ceiling test impairment we recorded in the first quarter of 2009.

Operating income from our Midstream Services segment grew to $27.8 million in the second quarter of 2009, up from $15.0 million for the same period in 2008.  The increase was primarily due to higher gathering revenues resulting from the significant increase in our gathered volumes, partially offset by increased operating costs and expenses.  

As of June 30th, we had $196 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.2%.  Our revolver balance included borrowings to pay off $60 million of senior notes (7.625%) during the second quarter.  For the first six months of the year, our debt outstanding increased by $135 million resulting in total debt outstanding of approximately $871 million at June 30th and a debt to capitalization ratio of 28%.  We have a strong balance sheet with significant financial flexibility and are well positioned to weather the current low commodity price environment.  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 Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted 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, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

See the reconciliation below of GAAP financial measures to non-GAAP financial measures for the three months ended June 30, 2009 and 2008.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.

	3 Months Ended June 30,
	2009	2008
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$     266,436	$     291,165
Add back (deduct):
Change in operating assets and liabilities	58,860	(2,935)
Net cash provided by operating activities before changes   in operating assets and liabilities	$     325,296	$     288,230

Southwestern Energy Company Second Quarter 2009 Earnings Teleconference Transcript

July 31, 2009