NEWS RELEASE    

SOUTHWESTERN ENERGY ANNOUNCES SECOND QUARTER 2012

FINANCIAL AND OPERATING RESULTS 

Houston, Texas – August 2, 2012...Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the second quarter of 2012. Highlights include:

For the second quarter of 2012, Southwestern reported a  net loss of $488.1 million, or $1.40 per diluted share. The net loss for the three months ended June 30, 2012 included a $935.9 million non-cash ceiling test impairment ($578.9 million net of taxes) of the company’s natural gas and oil properties resulting from lower natural gas prices. Excluding the non-cash impairment, Southwestern reported net income for the second quarter of 2012 of $90.8 million (reconciled below), or $0.26 per diluted share, compared to net income of $167.5 million, or $0.48 per diluted share, for the prior year period.

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $354.5 million for the second quarter of 2012,  down compared to  $448.2 million for the same period in 2011 primarily due to lower realized gas prices.

“The second quarter was challenging for any company drilling for natural gas. Southwestern Energy has embraced those challenges and our results show we had a very strong quarter,” remarked Steve Mueller, President and Chief Executive Officer of Southwestern Energy. “Our costs continue to be low, with all-in cash operating costs of $1.20 per Mcfe for the second quarter of 2012 and our Fayetteville and Marcellus drilling programs continue to provide a meaningful drilling inventory at the prices we see going forward. Finally, our New Ventures activities in the Brown Dense play are providing encouraging results and we are excited about the other ideas we are pursuing. We see many challenges as we look toward the second half of 2012, but those challenges also bring opportunities that have the potential to make 2012 one of the most exciting years in our history.”

Second Quarter 2012 Financial Results

E&P Segment – Excluding the non-cash impairment, operating income from the company’s E&P segment (reconciled below) was $76.0 million for the three months ended June 30, 2012,  compared to $222.5 million for the same period in 2011. The decrease was primarily due to 

lower realized natural gas prices and increased operating costs and expenses from higher activity levels, partially offset by higher production.

Southwestern accounts for its natural gas and oil properties using the full-cost method of accounting, which requires the company to perform a ceiling test that limits the amount of its capitalized gas and oil properties less accumulated amortization and related deferred income taxes to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves, net of taxes, discounted at 10 percent plus the lower of cost or market value of unproved properties. The company’s non-cash ceiling test impairment used the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.15 per MMBtu and $92.17 per barrel for West Texas Intermediate oil, adjusted for market differentials, compared to $4.12 per MMBtu and $92.71 per barrel for West Texas Intermediate oil, adjusted for market differentials, at December 31, 2011.

Gas and oil production totaled 137.4 Bcfe in the second quarter of 2012,  up 12%  from 122.8 Bcfe in the second quarter of 2011, and included 121.0 Bcf from the company’s Fayetteville Shale play, up from 107.4 Bcf in the second quarter of 2011.  Production from the Marcellus Shale was 9.9 Bcf in the second quarter of 2012, compared to 5.1 Bcf in the second quarter of 2011.

Including the effect of hedges, Southwestern’s average realized gas price in the second quarter of 2012 was $3.12 per Mcf, down 27%  from $4.30 per Mcf in the second quarter of 2011. The company’s commodity hedging activities increased its average gas price by $1.36 per Mcf during the second quarter of 2012, compared to an increase of $0.46 per Mcf during the same period in 2011.  As of June 30, 2012, Southwestern had NYMEX price hedges in place on notional volumes of approximately 134 Bcf of its remaining 2012 forecasted gas production hedged at an average floor price of $5.16 per Mcf and approximately 185 Bcf of its 2013 forecasted gas production hedged at an average floor price of $5.06 per Mcf. As of June 30, 2012, the company had protected approximately 131 Bcf of its remaining 2012 expected gas production from the potential of widening basis differentials through hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately ($0.03) per Mcf.

The company typically sells its natural gas at a discount to NYMEX settlement prices. This discount includes a basis differential, third-party transportation charges and fuel charges. Disregarding the impact of commodity price hedges, the company’s average price received for its gas production during the second quarter of 2012 was approximately $0.46 per Mcf lower than average NYMEX settlement prices, compared to approximately $0.47 per Mcf lower during the second quarter of 2011.  

In 2012, the company expects its total gas sales discount to NYMEX to be $0.45 to $0.55 per Mcf.

Lease operating expenses per unit of production for the company’s E&P segment were $0.79 per Mcfe in the second quarter of 2012, compared to $0.80 per Mcfe in the second quarter of 2011.  The decrease was primarily due to decreased compression costs, offset slightly by an increase in salt water disposal costs.

General and administrative expenses per unit of production were $0.27 per Mcfe in the second quarter of 2012,  flat compared to the second quarter of 2011.  

Taxes other than income taxes per unit of production were $0.08 per Mcfe in the second quarter of 2012, compared to $0.11 per Mcfe in the second quarter of 2011. Taxes other than income taxes vary due to changes in severance and ad valorem taxes that result from the mix of the company’s volumes and fluctuations in commodity prices.

The company’s full cost pool amortization rate was  $1.38 per Mcfe in the second quarter of 2012, compared to $1.28 per Mcfe in the second quarter of 2011. The amortization rate is impacted by the timing and amount of reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. The company cannot predict its future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors.

Midstream Services – Operating income for the company’s Midstream Services segment, which is comprised of natural gas gathering and marketing activities, was $71.8 million for the three months ended June 30, 2012, up 20% from $59.6 million in the same period in 2011.  The increase in operating income was primarily due to increased gathering revenues related to the company’s Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses. At June 30, 2012, the company’s midstream segment was gathering approximately 2.1 Bcf per day through 1,829 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 2.0 Bcf per day a year ago. Gathering volumes, revenues and expenses for this segment are expected to grow over the next few years largely as a result of increased development of the company’s acreage in the Fayetteville Shale and Marcellus Shale and the increased development activity undertaken by other operators in those areas.

First Six Months of 2012 Financial Results

For the first six months of 2012, Southwestern reported a  net loss of $380.4 million, or $1.09 per diluted share. Excluding the non-cash ceiling test impairment, the company reported adjusted net income for the first six months of 2012 of  $198.5 million (reconciled below), or $0.57 per diluted share, compared to $304.1 million, or $0.87 per diluted share, for the first six months of 2011. Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $725.3 million for the first six months of 2012,  compared to  $839.7 million for the same period in 2011.  

E&P Segment – Excluding the non-cash impairment, operating income from the company’s E&P segment (reconciled below) was $192.3 million for the six months ended June 30, 2012, compared to $400.8 million for the same period in 2011. The decrease was primarily due to lower average realized gas prices and increased operating costs and expenses from higher activity levels which were partially offset by higher production volumes.

Gas and oil production was 270.8 Bcfe in the first six months of 2012,  up 14%  compared to 237.8 Bcfe in the first six months of 2011, and included 236.8 Bcf from the company’s Fayetteville Shale play, up from 208.5 Bcf in the first six months of 2011.  Production from the Marcellus Shale was 19.2 Bcf in the first six months of 2012, compared to 7.9 Bcf in the first six months of 2011. The company expects that its full-year production for 2012 should range

between approximately 560 and 570 Bcfe, an increase of approximately 13% compared to 2011.

Southwestern’s average realized gas price was $3.30 per Mcf, including the effect of hedges, in the first six months of 2012 compared to $4.21 per Mcf in the first six months of 2011. The company’s hedging activities increased the average gas price realized during the first six months of 2012 by $1.30 per Mcf, compared to an increase of $0.45 per Mcf during the first six months of 2011. Disregarding the impact of hedges, the average price received for the company’s gas production during the first six months of 2012 was approximately $0.48 per Mcf lower than average monthly NYMEX settlement prices, compared to approximately $0.45 per Mcf during the first six months of 2011.  

Lease operating expenses for the company’s E&P segment were $0.81 per Mcfe in the first six months of 2012,  compared to $0.83 per Mcfe in the first six months of 2011.  The decrease was primarily due to decreased compression costs in the Fayetteville Shale.

General and administrative expenses were $0.29 per Mcfe in the first six months of 2012, compared to $0.27 per Mcfe in the first six months of 2011.  The increase in general and administrative expenses was primarily a result of personnel and information system costs associated with the expansion of the company’s E&P operations due to the continued development of the Fayetteville Shale play and Marcellus Shale play.

Taxes other than income taxes were $0.11 per Mcfe during the first six months of 2012,  flat compared to the first six months of 2011.  In February 2012, the Commonwealth of Pennsylvania passed the Unconventional Gas Well Impact Fee Act which imposes an annual impact fee for a period of up to fifteen years on each natural gas well drilled. The impact fee adjusts annually based on the age of the well, the average NYMEX natural gas price for the year and an inflation index. As a result of this legislation, Southwestern recorded a one-time expense in the first quarter of 2012 of $3.2 million, or approximately $0.024 per Mcfe, based on the required retroactive application of this legislation to all wells drilled in 2011 and previous years.

The company’s full cost pool amortization rate increased to $1.36 per Mcfe in the first six months of 2012, compared to $1.30 per Mcfe in the first six months of 2011.

Midstream Services - Operating income for the company’s midstream activities was $141.1 million in the first six months of 2012,  up 24%  compared to $113.6 million in the first six months of 2011. The increase in operating income was primarily due to increased gathering revenues related to the company’s Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses.

Capital Structure and Investments – At June 30, 2012, the company had approximately $1.7 billion in long-term debt and its total debt-to-total capitalization was 32.2%, compared to 25.3% at December 31, 2011.  Excluding the non-cash impairment, the company’s total debt-to-total capitalization was 29.0%. The company also had cash and cash equivalents of approximately $41 million and restricted cash of approximately $144 million at June 30, 2012.

For the first six months of 2012, Southwestern invested a total of approximately $1.2  billion, compared to $1.1 billion during the first six months of 2011, which included $1,065 million invested in its E&P business and $74 million invested in its Midstream Services activities.

Southwestern’s total capital investments program for 2012 is expected to be approximately $2.1 billion.

E&P Operations Review

Southwestern invested approximately $1,065 million in its E&P business during the first six months of 2012, of which approximately $635 million was invested in its Fayetteville Shale play, $272 million in the Marcellus Shale, $145 million in New Ventures, $7 million in Ark-La-Tex and $6 million in E&P Services. 

Fayetteville Shale Play – For the second quarter of 2012, Southwestern placed a total of 131 operated wells on production in the Fayetteville Shale play, all of which were horizontal wells fracture stimulated using slickwater. At June 30, 2012, the company’s gross production rate from the Fayetteville Shale play was approximately 1,877 MMcf per day, up from approximately 1,775 MMcf per day a year ago. The company’s production from the Fayetteville Shale has been affected by the recent extremely high temperatures in central Arkansas and, year-to-date, the company estimates that its production from the field has been reduced by approximately 0.5 to 1.0 Bcf due to the extreme heat. Since June 30, the company’s gross producing rate has returned to approximately 2 Bcf per day. The company is currently utilizing 11 drilling rigs in its Fayetteville Shale play, including 7  that are capable of drilling horizontal wells. The graph below provides gross production data from the company’s operated wells in the Fayetteville Shale play area through June 30, 2012.

During the second quarter of 2012, the company’s horizontal wells had an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,840 feet and average time to drill to total depth of 6.9 days from re-entry to re-entry. This compares to an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,743 feet and average time to drill to total depth of 7.3 days from re-entry to re-entry in the first quarter of

2012.  In the second quarter of 2012, the company had 30 operated wells placed on production which had average times to drill to total depth of 5 days or less from re-entry to re-entry. In total, the company has had a total of 160 wells drilled to total depth of 5 days or less from re-entry to re-entry.

The company’s wells placed on production during the second quarter of 2012 averaged initial production rates of 3,500 Mcf per day. Results from the company’s drilling activities from 2007 by quarter are shown below.

Note: Results as of June 30, 2012. 

Marcellus Shale – As of June 30, 2012,  Southwestern has participated in a total of 120 operated horizontal wells in northeast Pennsylvania, of which 41 were producing.  Net production from the area was 9.9 Bcf in the second quarter of 2012, compared to 5.1 Bcf in the second quarter of 2011. At June 30, 2012, the company’s gross operated production from the area was approximately 166 MMcf per day and was limited by high line pressures and gathering constraints. Recent gross production from the area has exceeded 200 MMcf per day.

The graph below provides normalized average daily production data through June 30, 2012, for the company’s horizontal wells in the Marcellus Shale. The “purple curve” indicates results for 20 wells with more than 12 fracture stimulation stages,  the “orange curve” indicates results for 20 wells with 9 to 12 fracture stimulation stages and the “green curve” indicates results for 1 well with less than 9 fracture stimulation stages. The normalized production curves are intended to provide a qualitative indication of the company’s Marcellus Shale wells’ performance and should

not be used to estimate an individual well’s estimated ultimate recovery. The 4,  6, 8 and 10 Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the company’s wells.

Ark-La-Tex – Total net production from the company’s East Texas and conventional Arkoma Basin properties was 6.4 Bcfe in the second quarter of 2012, compared to 10.3 Bcfe in the second quarter of 2011.

On May 1, 2012,  Southwestern sold its oil and natural gas leases, wells and gathering equipment in its Overton Field in East Texas for approximately $168 million, excluding typical purchase price adjustments.  The sale includes approximately 19,800 net acres in Smith County, Texas. Net production from the field was approximately 24 MMcfe per day as of the closing date and proved net reserves were approximately 143 Bcfe as of year-end 2011.

New Ventures – As of June 30, 2012,  Southwestern held 3,756,870 net undeveloped acres in connection with its New Ventures prospects, of which 2,518,518 net acres were located in New Brunswick, Canada.

Southwestern has approximately 563,000 net acres targeting the Lower Smackover Brown Dense formation in southern Arkansas and northern Louisiana.  The company has drilled four wells in the play area to date and is currently drilling two wells. The company’s first two wells, which were completed earlier this year, are currently shut-in for testing. The company’s third well, the BML #31-22 #1-1H located in Union Parish, Louisiana,  was drilled to a vertical depth of approximately 10,400 feet with a 4,300-foot horizontal lateral and was completed with 19 successful fracture stimulation stages in June.  After 41 days of flowing up casing, this well’s highest 24-hour producing rate to date was 421 barrels of 50^o API oil per day, 3,900 Mcf of high Btu gas per day and 836 barrels of water per day (43% of load recovered to date) with a

calculated flowing bottom hole pressure of 5,700 psi on a 24/64-inch choke.  The well was shut-in on July 27 in order to perform a pressure build-up test. The company believes that it will begin selling both oil and gas from the BML well in the fourth quarter of 2012. The oil pricing the company is receiving from this area is at a premium to WTI due to the geographic location of the play, and analysis of the gas shows a Btu content of approximately 1,220 per cubic foot, so it is expected to receive a premium to NYMEX gas prices due to the richer gas liquids. The company’s fourth well, the Johnson #21-22-1 #1 located in Union Parish, Louisiana, was drilled to a vertical depth of 10,507 feet in July. Like in the BML well, this well also encountered unusually high pressure within the target formation. The company plans to complete this well vertically in August, but the well will be able to be re-entered as a horizontal well in the future. The company has also commenced drilling on the Dean 31-22-1E #1, located in Union Parish, Louisiana, which is currently drilling at approximately 8,325 feet. This well is planned to be drilled to approximately 10,450 feet and be completed vertically. The company is also drilling the Doles 30-22-1H #1, located in Union Parish, Louisiana, which is currently drilling at approximately 6,375 feet. This well is planned to be drilled to a measured depth of approximately 17,300 feet and is currently designed to be completed with a 6,000-foot horizontal lateral.

The company has also leased approximately 290,000 net acres in the Denver-Julesburg Basin in eastern Colorado where the company has begun testing a new unconventional oil play targeting middle and late Pennsylvanian to Permian age carbonates and shales. In July,  the company completed its first well, the Ewertz Farms 1-58 #1-26, located in Adams County, Colorado, which was drilled to a total vertical depth of 8,550 feet with a 2,000-foot horizontal lateral targeting the Marmaton formation. This well began flowback in  mid-July and only 24% of flowback has been recovered to date, however oil production began 3 days after flowback commenced. The highest 24-hour producing rate to date for the Ewertz Farms well was 65 barrels of oil per day, 40 Mcf of gas per day and 740 barrels of water per day on pump. The company has also drilled the Staner 5-58 #1-8 well located in Arapahoe County to a total vertical depth of 9,650  feet. This well is planned to be completed in August as a vertical completion. The company will evaluate the production from these two wells over the next 90 days.

In New Brunswick, Canada, the company has deferred its planned 2012 exploration program until 2013 to provide additional time for public engagement and completion of the permitting process in the Province.  The New Brunswick Department of Natural Resources and other key government officials support this decision and the company will continue to work together with the appropriate parties to deliver on its commitments to the Province in 2013.  

Explanation and Reconciliation of Non-GAAP Financial Measures

The company reports its 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 its 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 the company may present from time to time are net income, diluted earnings per share and its 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 and six months ended June 30, 2012 and June 30, 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.  

Southwestern will host a teleconference call on Friday, August 3, 2012, at 10:00 a.m. Eastern to discuss the company’s second quarter 2012 results. The toll-free number to call is 877-407-8035 and the international toll-free number is 201-689-8035. The teleconference can also be heard “live” on the Internet at http://www.swn.com.

Southwestern Energy Company is an independent energy company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering and marketing. Additional information on the company can be found on the Internet at http://www.swn.com.

All statements, other than historical facts and financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements, other than to the extent set forth below. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the company’s ability to transport its production to the most favorable markets or at all; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas areas; the company’s ability to fund the company’s planned capital investments; the impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives;  the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and the Marcellus Shale play; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company’s future property acquisition or divestiture activities; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the

risk of loss as a result of non-performance by the company’s counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Financial Summary Follows

# # #