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): April 30, 2010

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 April 30, 2010, 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 April 30, 2010 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: April 30, 2010	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 April 30, 2010 telephone conference call for investors and analysts.

EX-99

Southwestern Energy First Quarter 2010 Earnings Teleconference

Speakers:

Steve Mueller; President and Chief Executive Officer

Greg Kerley; Executive Vice President and Chief Financial Officer

Steve Mueller; President and Chief Executive Officer

Good morning, and thank you for joining us.  If you have not received a copy of yesterday’s press release regarding our first 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.

We had a very good quarter financially. Our earnings and cash flow growth were outstanding, which highlight the value of our industry-leading low cost structure. However, while our production grew by 41% during the first quarter, we experienced operational and weather-related field issues in our Fayetteville Shale play which impacted our production volumes. As a result, 26 fewer wells were placed on production than originally scheduled at March 31, impacting our production for the first quarter by approximately 3 Bcf. We have adjusted our production guidance for the 2nd and 3rd quarters, and remain optimistic that our 4th quarter production guidance is still achievable at this time.

Fayetteville Shale Play

Now, to talk a bit about each of our operating areas.  Earlier this week, our gross operated production from the Fayetteville Shale reached approximately 1.3 Bcf per day, up from about 850 MMcf per day a year ago.  While it now seems that most of the issues are now behind us, we did have operational and weather-related field issues which affected our results during the quarter.  

Approximately 47% of the wells placed on production during the quarter were the very first well in a section and 65% of the wells were along the shallower northern and far eastern borders of the project.  Both the first section wells and shallow well locations were the highest of any quarter in the company’s history by at least 13% and 20%, respectively. As might be expected, the initial rates from the wells along the edges of our producing areas are less than the central and deeper areas, but we continue to improve and achieved initial production results that were better than previous quarter averages for these border areas.  

Weather and challenges encountered in the more remote locations with first wells in new sections resulted in placing a total of 26 fewer wells on production than what we had originally anticipated, impacting our production by 3 Bcf during the quarter.  As a result, we have added two additional horizontal drilling rigs during the first quarter and expect to catch up to our original operated well count by the third quarter of 2010.  We currently are running 24 drilling rigs in the Fayetteville Shale play area, 16 that are capable of drilling horizontal wells and 8 smaller rigs that are used to drill the vertical section of the wells.  

During the first quarter, our horizontal wells had an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,348 feet and average time to drill to total depth of 12 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 4,303 feet and average time to drill to total depth of 12 days from re-entry to re-entry in the fourth quarter of 2009.  Wells placed on production during the first quarter of 2010 averaged initial production rates of 3,197 Mcf per day, down 14% from average initial production rates of 3,727 Mcf per day in the fourth quarter of 2009.  Factors contributing to the decrease in average initial production rates were the shift of all our operated wells to “green completions” and the large number of first wells in new sections and wells located in the shallower northern and far eastern borders of our acreage that I discussed earlier.  When looking at our results through April, we have already placed nearly 50 wells on production at an average initial production rate of approximately 3.6 MMcf per day.  

Beginning in late 2009, we began what sometimes is called “green completions,” whereby wells are placed directly on production very early in the flowback period so that incremental gas volumes are captured.  As a result of the wells being placed on production earlier, the initial pressure the well is flowing against is higher and the recovery of the completion fluids is slower.  This will capture more gas but we estimate initial production rates could be reduced by approximately 5% to 10%.

We continue to test tighter well spacing and, at March 31, we had placed over 375 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less and have previously concluded that 10 to 12 wells per section is the minimum number of wells needed to efficiently drain the reserves. The most recent information from this larger group of wells indicates interference of less than 10% compared to earlier estimates of 10% to 15% from a smaller well set.  We continue to focus on optimizing the well spacing for the play and plan to test over 44 different pilots with well spacings that will range from 200 to 450 feet apart as part of our 2010 drilling program.

To wrap up our discussion on the Fayetteville, we are now providing new production data on our zero-time production plot of wells with drilled lateral lengths over 5,000 feet as shown in our press release.  With over 60 wells included in the sample, we are encouraged by what we are seeing thus far.

East Texas Field

In our East Texas operating areas, production was 9.6 Bcfe, up from 7.8 Bcfe a year ago.  We participated in drilling 11 wells in East Texas during the first quarter, 6 of which were James Lime horizontal wells, 3 of which were Haynesville horizontal wells and 2 of which were Pettet horizontal oil wells.  Initial production rates from James Lime wells that were placed on production during the quarter averaged 6.6 MMcfe per day and we placed one well on production from the Haynesville Shale during the quarter at an initial production rate of 22.1 MMcf per day. Initial production rates from 4 Pettet oil wells that were placed on production during the quarter averaged 292 barrels oil per day, with 2.6 MMcf per day of associated gas.

Conventional Arkoma

In our conventional Arkoma Basin program, we participated in 3 wells and production from the area was 4.9 Bcf, compared to 5.8 Bcf last year.

Appalachia

In Pennsylvania, we have approximately 151,000 net acres in Pennsylvania prospective for the Marcellus Shale.  We are currently drilling our second well for 2010, the FERGUSON-KEISLING #1-H in Bradford County.  We plan to complete both wells during the second quarter and they could be placed on production as early as June.  At least 15 wells are expected to be drilled by Southwestern in 2010.      

New Ventures

In our New Ventures program, we announced in March that we had been granted exclusive licenses to search and conduct an exploration program covering over 2.5 million acres in the province of New Brunswick, Canada to test new hydrocarbon basins.  As the winner of the bids, our financial commitment over the next three years is approximately $47 million.  More than 80% of the work commitment is gathering and processing of geochemical, gravity, magnetic and seismic data.  The initial phase of the data gathering is planned to start before the end of 2010.

In closing, natural gas continues to underperform the rest of the commodities and like all of you, we are carefully watching both the imbalance of supply and demand and the industry’s reaction to that imbalance.  We have already made some adjustments to our capital allocations to emphasize our best projects.  We also remain confidant that our low cost operations, financial strength and flexibility to pursue our drilling program in the Fayetteville give us staying power through the tough times and the ability to add significant value for our shareholders even in the current low gas price environment.  

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

Greg Kerley – Executive Vice President and Chief Financial Officer

Thank you, Steve, and good morning.  

As Steve noted, our financial results for the quarter were excellent, with earnings up 37% and cash flow up 12%. Our improved results were driven by our strong production growth, and continue to highlight the high quality of our assets and our industry-leading low cost structure.

We reported earnings for the first quarter of $172 million, or $0.49 per share, compared to adjusted earnings in the first quarter of 2009 of $125 million, or $0.36 per share, (which for comparative purposes exclude a non-cash ceiling test impairment recorded in 2009).

We also reported discretionary cash flow of $418 million, up 12% from last year and we were nearly cash flow neutral for the period as our cash generated from our operating activities funded 94% of the cash requirements for our capital investments.

Our production totaled 90 Bcfe in the first quarter, up 41% from the prior year period, and we realized an average gas price of $5.42 per Mcf, down over $0.50 per Mcf from the same period last year.  

Operating income for our E&P segment was $250 million during the quarter, up 39% from the same period last year, excluding the non-cash ceiling test impairment, as the significant growth in our production volumes more than offset the decline in our average realized gas price.   

Our commodity hedge position increased our average realized gas price by approximately $0.55 per Mcf in the first quarter.  We have approximately 48 Bcf of our remaining 2010 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.01 per Mcf.

We recently increased our hedge position in 2011 and also added some hedges in 2012.  We hedged an additional approximately 55 Bcf of our 2011 forecasted gas production through costless-collars at a floor price of $5.00 per Mcf and an average ceiling price of $6.42 per Mcf and approximately 29 Bcf of our 2012 forecasted gas production at a floor price of $5.50 per Mcf and an average ceiling price of $6.54 per Mcf.

Our lease operating expenses per unit of production were $0.78 per Mcfe during the quarter, unchanged from last year.  

Our general and administrative expenses per unit of production declined to $0.29 per Mcfe in the first quarter, down from $0.31 last year, due to our increased production volumes.  

Taxes other than income taxes were $0.14 per Mcfe in the quarter, compared to $0.13 in the prior year.

Our full cost pool amortization rate also declined, dropping to $1.41 per Mcfe in the quarter, from $1.82 in the prior year.  The decline was due to a combination of the ceiling test impairment recorded in the first quarter of 2009 and our lower finding and development costs.

Operating income from our Midstream Services segment increased by 38% in the first quarter to $38 million.  The increase was primarily due to increased gathering revenues related to production growth in the Fayetteville Shale play, partially offset by increased operating costs and expenses.  At April 25th, our Midstream segment was gathering almost 1.5 billion cubic feet of natural gas per day through 1,217 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 900 million cubic feet per day a year ago.  

We invested $474 million during the first quarter of 2010, compared to $503 million in the first quarter of 2009, and drew down our revolver by only $20 million during the quarter.  At March 31, we had $345 million borrowed on our $1 billion credit facility at an average interest rate of 1.3%, and had total debt outstanding of a little more than $1 billion.  This leaves us with a debt to book capital ratio of 29% and a debt to market capitalization ratio of only 7%.  

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.

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy, diluted earnings per share attributable to Southwestern Energy stockholders and our E&P segment operating income, all which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2010 and March 31, 2009.  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 Mar. 31,
	2010	2009
	(in thousands)
Net income (loss) attributable to Southwestern Energy:
Net income (loss) attributable to Southwestern Energy	$     171,797	$    (432,830)
Add back:
Impairment of natural gas and oil properties (net of taxes)	--	558,305
Net income attributable to Southwestern Energy,   excluding impairment of natural gas and oil properties	$     171,797	$     125,475

	3 Months Ended Mar. 31,
	2010	2009
Diluted earnings per share:
Net income (loss) per share attributable to   Southwestern Energy stockholders	$          0.49	$        (1.26)
Add back:
Impairment of natural gas and oil properties (net of taxes)	--	1.62
Net income per share attributable to Southwestern Energy stockholders,   excluding impairment of natural gas and oil properties	$          0.49	$          0.36

	3 Months Ended Mar. 31,
	2010	2009
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$     417,579	$     407,295
Add back (deduct):
Change in operating assets and liabilities	186	(34,740)
Net cash provided by operating activities before changes   in operating assets and liabilities	$     417,765	$     372,555

	3 Months Ended Mar. 31,
	2010	2009
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$     250,431	$    (727,893)
Add back:
Impairment of natural gas and oil properties	--	907,812
E&P segment operating income, excluding impairment   of natural gas and oil properties	$     250,431	$     179,919