Exhibit 99.1

Southwestern Energy Fourth Quarter and Year-End 2011 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. With me today are Greg Kerley, our Chief Financial Officer, and Brad Sylvester, our VP of Investor Relations.

If you have not received a copy of yesterday’s press release regarding our fourth quarter and year-end 2011 results, you can find a copy on our website at www.swn.com. 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 the 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.

To begin, 2011 was another record year for Southwestern Energy. We set new records in production and reserves and as a result of our 24% production growth we achieved the highest earnings and cash flow in our company’s history. We produced 500 Bcfe driven largely by our Fayetteville Shale play, where our production grew 25% to 437 Bcf. Our production from the Marcellus Shale also grew from 1 Bcf in 2010 to 23 Bcf in 2011, while our Ark-La-Tex production declined from 54 Bcfe in 2010 to 40 Bcfe in 2011.

Our year-end proved reserves also increased by 19% to a record 5.9 Tcfe. Approximately 100% of our reserves were natural gas and 45% were classified as proved undeveloped. We replaced 299% of our 2011 production at a finding and development cost of $1.31 per Mcfe, including revisions. This, along with our all-in cash costs of $1.27 per Mcfe, give us one of the lowest cost structures in the industry. The year is already challenging, but our goal is not to survive; it is to thrive.

Fayetteville Shale

Now, to talk about our operating areas. In the Fayetteville Shale we added 1.2 Tcf of new reserves at a finding and development cost of $1.13 per Mcf. Total proved reserves booked in the Fayetteville Shale play at year-end 2011 were 5.1 Tcf, up 17% from reserves booked at the end of 2010.

We spud 580 operated wells in the Fayetteville Shale during 2011 and placed a record 560 operated wells on production, resulting in gross production from our operated wells to increase from 1.6 Bcf per day at the first of the year to 1.9 Bcf per day at the end of the year.

We saw continued improvement in our drilling practices in the Fayetteville Shale play in 2011, as our operated horizontal wells had an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,836 feet and average time to drill to total depth of 8 days from re-entry to re-entry. This compared to approximately the same well cost in 2010 with a shorter lateral. We also placed 73 wells on production during 2011 that were drilled in 5 days or less. In total, we have drilled 104 wells to date in 5 days or less.

After seven years since first production, the drilling program turned from establishing first wells in section to drilling multiple wells from a pad. Our average initial producing rates were approximately 3.3 million cubic feet per day compared to last year’s 3.4 million cubic feet average rate, and in the fourth quarter of 2011 this average rate was over 3.6 million cubic feet of gas per day.

Marcellus Shale

Switching to Pennsylvania, we added 327 Bcf of new reserves at a finding and development cost of $1.02 per Mcf. Total proved reserves booked in our Marcellus Shale area at year-end 2011 were 342 Bcf, up from 38 Bcf booked at the end of 2010.

As of year-end 2011, we had spud 70 wells, 23 of which were on production and 67 of which were horizontal wells. Total daily gross operated production from the area was approximately 133 MMcf per day at December 31 and limited by high line pressures.

Our operated horizontal wells had an average completed well cost of $6.4 million per well, average horizontal lateral length of 4,007 feet and an average of 12 fracture stimulation stages. The average gross proved reserves for the undeveloped wells included in our year-end reserves was approximately 7.5 Bcf per well and approximately 8.6 Bcf per well for our proved developed wells in 2011.

New Ventures

As for New Ventures, at December 31, 2011, we held 3.6 million net undeveloped acres, of which 2.5 million net acres were located in New Brunswick, Canada and the remaining approximately 1.1 million net acres were located in the U.S.

In New Brunswick, we have invested approximately $24 million through December 31, 2011 and have acquired 248 miles of 2-D seismic data. In 2012, we intend to acquire approximately 130 additional miles of 2-D seismic data and our current plan includes drilling two stratigraphic well tests in the fourth quarter of 2012.

In our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana, we hold leases on 520,000 net acres at an average cost of $375 per acre. Earlier this month, we began flowing back our first well in the area, the Roberson 18-19 #1-15H located in Columbia County, Arkansas. This well had a vertical depth of approximately 9,369 feet and a horizontal lateral length of approximately 3,600 feet and was completed in 11 stages. The lateral was landed in the lower third of this zone and subsequent core analysis indicated this section had some of the lowest permeability in the entire interval. The well has been producing from 8 of 11 stages fractured stimulated for 20 days of an expected 20 to 30 day cleanup period. Oil production began on day 8 with the highest 24-hour rates to date of 103 barrels of oil per day, 200 Mcf per day and 1,009 barrels of load water per day. 45% of load has been recovered to date.

Our second well, the Garrett 7-23-5H #1 located in Claiborne Parish, Louisiana, was drilled to a total depth in February 2012 at approximately 10,863 feet with a 6,536-foot horizontal lateral and that well will begin fracture stimulation operations on March 1. Knowledge gained from the first well allowed us to drill this well with no troubles and led us to target the Upper Brown Dense. Drilling in the lateral was not only faster but oil shows and cuttings indicated better quality rock.

We have also spud our third well located in Union Parish, Louisiana and it is drilling at 7,900 feet. We are looking forward to learning more about this play and our activity could increase dramatically if it is successful.

We also disclosed that we hold 238,000 net acres located in the DJ Basin in eastern Colorado where we will begin testing a new unconventional oil play targeting middle and late Permian to Pennsylvanian carbonates and shales. The play objectives range in vertical depth from 8,000 to 10,500 feet and are within the oil window. Our primary Atoka-Marmaton objectives are alternating low permeable, 20 to 100 foot thick carbonates separated by 10 to 75 feet thick organic rich, carbonate mudstones with total organic carbon estimates ranging from 2% to 27%. Total thickness of the objective section ranges from 300 feet to 750 feet. This acreage was obtained for approximately $176 per acre and the company’s leases currently have an 85% average net revenue interest and an average primary lease term of 5 years which may be extended for an additional 3 years.

To date, no production has been established in the immediate area. However, there have been mud log oil and gas shows, oil saturated cores, and free oil on drill stem tests in the objective section. We have measured 36^o API oil in fluid inclusions, microporosity in both the limes and shale in thin sections, and microporosity in SEM analysis. The closest oil production from the objective formations is in the Great Plains Field which is located 65 miles to the southeast in Lincoln County. The field, discovered in 2009 has 12 wells and has produced nearly 1 MMBO of 36^o API oil from conventional carbonate porosity zones.  

Earlier this month, we submitted a drilling plan to the Colorado Oil and Gas Conservation Commission for approval to spud our first well in Adams County in the second quarter of 2012. This well is planned as a 9,500 foot vertical pilot well to the Lower Pennsylvanian Morrow Formation. The pilot well will be cored and then a 2,000’ lateral will be drilled in the Marmaton objective. A second 9,500’ vertical test well is planned to the south which will also drill to the Morrow Formation and will core the objective section. Again, if this drilling program yields positive results, activity in the area could increase significantly over the next several years.

2012 Capital Program and Production Guidance

You’ve probably noticed that I haven’t mentioned gas prices. We are preparing for low gas prices throughout this year and possibly for 2013. We will continue to be flexible with our capital investments and be sure we are doing the Right Things with every dollar we invest. As a result, we have decreased our 2012 capital investment program from our previous guidance in December. Currently, we plan to invest approximately $2.1 billion in 2012, compared to the $2.3 billion plan we announced back in December. The decrease is primarily from our Fayetteville Shale program and the associated decrease in production is approximately 10 Bcf, or down 2% from the midpoint of our previous guidance. Gas production is now expected to grow at 13%. We will remain focused on keeping our costs as low as possible during this time and will remain vigilant in upholding our commitment to creating value for every dollar we invest.

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 earnings and cash flow set new records in 2011 - as our strong production growth combined with our low cost structure and more than offset the impact of lower gas prices.  For the calendar year, we reported net income of $638 million, or $1.82 per share, up 6% from the prior year.  While our cash flow from operations (before changes in operating assets and liabilities) was up 12% to $1.8 billion.    

Operating income for our Exploration & Production segment was $825 million, compared to $829 million in 2010. For the year, we grew our production to 500 Bcfe and realized an average gas price of $4.19 per Mcf, which was down 10% from 2010.  

We currently have 266 Bcf, or approximately 47%, of our 2012 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $5.16 per Mcf. Our hedge position, combined with the cash flow generated by our Midstream gathering business, provides protection on approximately 65% of our total expected cash flow for 2012. Our detailed hedge position is included in our Form 10-K filed earlier this morning.

We continue to have one of the lowest cost structures in our industry, with all-in cash operating costs of approximately $1.27 per Mcf in 2011. That includes our LOE, G&A, interest and taxes. When you include our finding and development costs, our full-cycle costs for 2011 were $2.58 per Mcf.  

Our lease operating expenses per unit of production were $0.84 per Mcfe in 2011, compared to $0.83 in 2010. The slight increase was primarily due to increased gathering costs in our Fayetteville Shale play.

Our general and administrative expenses per unit of production declined to $0.27 per Mcfe in 2011, down from $0.30 in 2010. The decrease was primarily due to the effects of our increased production volumes.   

Taxes other than income taxes were $0.11 per Mcfe in both 2011 and 2010.

Our full cost pool amortization rate also declined during 2011 to $1.30 per Mcfe, down from $1.34 in the prior year.  The decline was due to a combination of our low finding and development costs and the sale of natural gas and oil properties in East Texas.

Operating income from our Midstream Services segment rose 29% to $248 million in 2011 and EBITDA for the segment was $285 million. The increase was primarily due to increased gathering revenues related to our Fayetteville and Marcellus Shale areas and an increase in the margin from our gas marketing activities. At December 31, 2011, our Midstream segment was gathering approximately 2.1 Bcf of natural gas per day through approximately 1,800 miles of gathering lines in the Fayetteville Shale play, compared to gathering 1.8 Bcf per day a year ago.  

Our debt-to-total book capitalization ratio declined to 25% at the end of 2011, down from 27% at the end of 2010. At December 31, 2011, we had approximately $1.3 billion in long-term debt, including $672 million borrowed on our revolving credit facility.

In summary, our financial and operating results in 2011 were some of the best in the company’s history. We have the ability to weather the low gas price environment and can not only survive, but thrive, in these times due to our 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 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 with 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 reconciliations below of GAAP financial measures to non-GAAP financial measures for the twelve months ended December 31, 2011.  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.

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 computes F&D costs using information required by GAAP for the twelve months ending December 31, 2011.

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 and the SEC’s 2009 adoption of a number of revisions to its oil and gas reporting disclosure requirements, 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 SEC, 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.