Southwestern Energy (SWN) 8-K Results of Operations and Financial Condition

2350 N. Sam Houston Parkway East Suite 125 Houston, Texas  77032 (281) 618-4700     Fax: (281) 618-4820

NEWS RELEASE

SOUTHWESTERN ENERGY ANNOUNCES

2008 FINANCIAL AND OPERATING RESULTS

Company Reports Production Growth of 71%, Reserve Growth of 51% and Finding and Development Cost of $1.53 per Mcfe in 2008

Houston, Texas – February 26, 2009...Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the fourth quarter and the year ended December 31, 2008. Calendar year 2008 highlights include:

·

Net income of $567.9 million, up 157% from 2007

·

Net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure reconciled below) of $1,167.5 million, up 79% from 2007

·

Oil and gas production of 194.6 Bcfe, up 71% over 2007

·

Proved oil and gas reserves of 2,185 Bcfe, up 51% over 2007

Southwestern reported net income for 2008 of $567.9 million, or $1.64 per diluted share, more than doubling net income of $221.2 million, or $0.64 per diluted share, in 2007. Net cash provided by operating activities before changes in operating assets and liabilities (non-GAAP; see reconciliation below) was $1,167.5 million, up 79% from $651.2 million in 2007.

“2008 was a tremendous year for Southwestern Energy,” remarked Harold M. Korell, Chairman and Chief Executive Officer of Southwestern Energy. “Looking at our achievements, we recorded exceptional production and reserve growth as we continued to move up the learning curve in the Fayetteville Shale. We 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%, nearly $200 million of cash on hand at year-end and nothing borrowed on our $1 billion unsecured credit facility. By far, the key accomplishment for us in 2008 was the progress we made in our Fayetteville Shale play, a project wherewe have thousands of wells to drill and quite possibly the most economic position in a shale play in the United States. Overall, I could not be any more pleased with our accomplishments in 2008.”

“Looking to the future, Southwestern Energy will continue to focus on organic growth and the value added for each dollar we invest, which means we will reevaluate proposed investments as needed to take into account prevailing market conditions. 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. There is a lot of uncertainty in today’s markets, but 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.”

Fourth Quarter of 2008 Financial Results

For the fourth quarter of 2008, Southwestern reported net income of $104.2 million, or $0.30 per diluted share, compared to $71.6 million, or $0.21 per diluted share, for the same period in 2007, primarily due to a 65% increase in total gas and oil production which was partially offset by lower realized natural gas prices and increased operating costs and expenses. Net cash provided by operating activities before changes in operating assets and liabilities (non-GAAP; see reconciliation below), was $283.4 million in the fourth quarter of 2008, up from $204.3 million in 2007.

E&P Segment- Operating income from the company’s E&P segment was $152.1 million for the three months ended December 31, 2008, compared to $113.6 million for the same period in 2007. The increase was primarily due to higher production which was partially offset by lower realized natural gas prices and increased operating costs and expenses.

Gas and oil production totaled 57.6 Bcfe in the fourth quarter of 2008, up from 34.9 Bcfe in the fourth quarter of 2007, and included 44.1 Bcf from the company’s Fayetteville Shale play, up from 19.9 Bcf in the fourth quarter of 2007.

Southwestern’s average realized gas price was $5.93 per Mcf, including the effect of hedges, in the fourth quarter of 2008, down from $6.90 per Mcf in the fourth quarter of 2007. The company’s commodity hedging activities increased its average gas price by $0.79 per Mcf during the fourth quarter of 2008 and by $0.69 per Mcf during the same period in 2007. As of February 23, 2009, the company had approximately 135 Bcf of 2009 natural gas production hedged (approximately 48% of its targeted total) through a combination of fixed-priced swaps and collars with a weighted average floor price of $8.48 per Mcf.

Disregarding the impact of commodity price hedges, the company’s average price received for its gas production during the fourth quarter of 2008 was approximately $1.80 per Mcf lower than average NYMEX spot prices, compared to approximately $0.76 per Mcf lower during the fourth quarter of 2007. During the year, the majority of the company’s gas from the Arkoma Basin was moved to markets in the Midwest and was priced primarily based on two indices, “NGPL TexOk” and “Centerpoint East.” Late in the third quarter and during the fourth quarter of 2008, differentials to NYMEX spot prices on NGPL TexOk and Centerpoint East began widening above historical averages as a result of the delay in the construction of Phase 1 of the Fayetteville Lateral portion of the Texas Gas Transmission Pipeline (Boardwalk Pipeline). On December 24, 2008, the Fayetteville Lateral was placed in-service and Southwestern began transporting gas to markets through the pipeline. As a result, basis differentials on both NGPL TexOk and Centerpoint East have currently contracted from their highs experienced during the third and fourth quarters of 2008. The company has protected approximately 36.8 Bcf of its first quarter 2009 expected gas

production from the potential of widening basis differentials through financial hedging activities and physical sales arrangements at an average differential to NYMEX gas prices of approximately $1.00 per Mcf.

Southwestern’s average realized oil price was $61.64 per barrel during the fourth quarter of 2008, compared to $90.96 per barrel in the fourth quarter of 2007.

Lease operating expenses per unit of production for the company’s E&P segment were $0.87 per Mcfe in the fourth quarter of 2008, compared to $0.79 per Mcfe in the fourth quarter of 2007. The increase was driven by higher per unit costs associated with gathering and compression costs in the company’s Fayetteville Shale operations, partially offset by the impact of lower natural gas prices on the cost of compression fuel. General and administrative expenses per unit of production were $0.49 per Mcfe in the fourth quarter of 2008, compared to $0.52 per Mcfe in the fourth quarter of 2007. The decrease was primarily due to the effects of the company’s increased production volumes which more than offset increased compensation and related costs primarily associated with the expansion of the company’s E&P operations due to the Fayetteville Shale play. Taxes other than income taxes per unit of production were $0.06 per Mcfe in the fourth quarter of 2008, compared to $0.09 per Mcfe in the fourth quarter of 2007, primarily due to the change in the mix of the company’s production volumes. The company’s full cost pool amortization rate decreased to $1.87 per Mcfe in the fourth quarter of 2008, compared to $2.39 per Mcfe in the fourth quarter of 2007. The decline in the average amortization rate was due to the combined effects of sales of oil and gas properties in the second and third quarters of 2008 (the proceeds of which were credited to the full cost pool) and the company’s lower finding and development costs in 2008.

Midstream Services- Operating income for the company’s midstream services segment, which is comprised of natural gas gathering and marketing activities, was $18.9 million for the three months ended December 31, 2008, up from $6.8 million in the same period in 2007. The increase in operating income was primarily due to higher gathering revenues and an increase in the margin from gas marketing activities, partially offset by increased operating costs and expenses.

Full-Year 2008 Financial Results

Southwestern reported net income for 2008 of $567.9 million, or $1.64 per diluted share, up from $221.2 million, or $0.64 per diluted share, in 2007. Results for 2008 included an after-tax gain on sale from the company’s utility assets of $35.4 million, or $0.10 per diluted share. Net cash provided by operating activities before changes in operating assets and liabilities (non-GAAP; see reconciliation below), was $1,167.5 million in 2008, up from $651.2 million in 2007. The company’s 2008 financial results were driven primarily by the positive effect on earnings of the significant growth in production volumes from the Fayetteville Shale play and higher realized natural gas prices.

E&P Segment- Operating income from the company’s E&P segment was $813.5 million in 2008, compared to $358.1 million in 2007, primarily due to a 71% increase in total equivalent gas and oil production and higher realized gas and oil prices, partially offset by higher operating costs and expenses.

Gas and oil production totaled 194.6 Bcfe in 2008, up from 113.6 Bcfe in 2007, and included 134.5 Bcf from the company’s Fayetteville Shale play, up from 53.5 Bcf in 2007. During 2008, approximately 99% of the company’s production was natural gas, compared to 97% in 2007. Southwestern’s 2009 total gas and oil production guidance is 280.0 to 284.0 Bcfe, an increase of approximately 45% over its 2008 production, of which approximately 229.0 to 232.0 Bcf is expected to come from the Fayetteville Shale.

Southwestern’s average realized gas price was $7.52 per Mcf in 2008, compared to $6.80 per Mcf in 2007, including the effects of hedges. The company’s commodity hedging activities decreased its average gas price $0.21 per Mcf in 2008 and increased its average price by $0.64 per Mcf in 2007. Disregarding the impact of commodity price hedges, the average price received for the company’s gas production was approximately $1.30 per Mcf lower than average NYMEX spot prices during 2008, compared to $0.70 per Mcf in 2007.

Southwestern’s average oil price was $107.18 per barrel in 2008, compared to $69.12 per barrel in 2007.

Lease operating expenses per unit of production for the company’s E&P segment were $0.89 per Mcfe in 2008, compared to $0.73 per Mcfe in 2007. The increase was due to increases in gathering and compression costs, including the impact of higher natural gas prices on the cost of compression fuel, the majority of which relates to the company’s operations in the Fayetteville Shale play.

General and administrative expenses per unit of production were $0.41 per Mcfe in 2008, compared to $0.48 per Mcfe in 2007. The decrease in general and administrative costs per Mcfe from 2007 was due to the effects of the company’s increased production volumes which more than offset increased compensation and related costs primarily associated with the expansion of the company’s E&P operations due to the Fayetteville Shale play. Southwestern added 219 new employees during 2008, most of which were hired in its E&P segment.

Taxes other than income taxes per unit of production decreased to $0.13 per Mcfe in 2008, compared to $0.16 per Mcfe in 2007, primarily due to the change in the mix of the company’s production volumes.

The company’s full cost pool amortization rate averaged $1.99 per Mcfe in 2008, down from $2.41 per Mcfe in 2007, due to the combined effects of sales of oil and gas properties in the second and third quarters of 2008 (the proceeds of which were credited to the full cost pool) and the company’s lower finding and development costs in 2008. The amortization rate is impacted by 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 future full cost pool amortization rate cannot be predicted 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 natural gas gathering and marketing activities was $62.3 million in 2008, up from $13.2 million in 2007. The increase in operating income was primarily due to higher gathering revenues and an increase in the

margin from gas marketing activities, partially offset by increased operating costs and expenses. At February 15, 2009, the company’s midstream segment was 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. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to the company’s Fayetteville Shale play are developed and production increases.

Natural Gas Distribution Segment - Effective July 1, 2008, the company sold all of the capital stock of Arkansas Western Gas Company (“AWG”) to SourceGas, LLC for $223.5 million (net of expenses related to the sale). In order to receive regulatory approval for the sale and certain related transactions, the company paid $9.8 million to AWG for the benefit of its customers. The company recorded a pre-tax gain on the sale of $57.3 million in the third quarter of 2008. As a result of the sale of the utility, Southwestern is no longer engaged in natural gas distribution operations. AWG provided operating income for the first half of 2008 of $10.7 million, compared to $10.0 million for the entire year of 2007.

Southwestern Reports Record Oil and Gas Reserves

Southwestern’s estimated proved oil and gas reserves totaled 2,185 Bcfe at December 31, 2008, up 51% from 1,450 Bcfe at the end of 2007. Approximately 100% of the company’s year-end 2008 estimated proved reserves were natural gas and 62% were classified as proved developed, compared to 96% and 64%, respectively, in 2007. Southwestern operates approximately 95% of its reserves, based on pre-tax PV-10 value, and the company’s average proved reserves-to-production ratio, or average reserve life, approximated 11.2 years at year-end 2008. Netherland, Sewell & Associates, Inc., an independent oil and gas reserve engineering firm, audited the company’s estimated proved reserves.

In 2008, Southwestern replaced 523% of its production volumes by adding 920 Bcfe of proved natural gas and oil reserves and having net upward revisions of 98 Bcfe. In 2007, the company’s reserve replacement ratio was 474%, including revisions. For the period ending December 31, 2008, the company’s three-year average reserve replacement ratio, including revisions, was 483%. Excluding reserve revisions, the company’s 2008 and three-year average reserve replacement ratios were 473% and 471%, respectively.

Southwestern’s finding and development cost was $1.53 per Mcfe in 2008, including reserve revisions, compared to $2.54 per Mcfe in 2007. For the period ending December 31, 2008, the company’s three-yearfinding and development cost, including revisions, was $2.01 per Mcfe. Excluding reserve revisions, the company’s 2008 and three-year average finding and development costs were $1.70 per Mcfe and $2.06 per Mcfe, respectively (finding and development costs are considered by the Securities and Exchange Commission to be non-GAAP financial measures and have been reconciled below).

The following table details additional informationrelating to reserve estimates as of and for the year ended December 31, 2008:

Natural Gas (Bcf)

Crude Oil (MMBbls)

Total (Bcfe)

Proved Reserves, Beginning of Year	1,396.9	8.9	1,450.3
Revisions of Previous Estimates	100.2	(0.4)	98.1
Extensions, Discoveries & Other Additions	919.6	0.1	920.2
Production	(192.3)	(0.4)	(194.6)
Acquisition of Reserves in Place	--	--	--
Disposition of Reserves in Place	(48.9)	(6.8)	(89.5)
Proved Reserves, End of Year	2,175.5	1.5	2,184.6
Proved Developed Reserves:
Beginning of Year	880.3	7.3	923.9
End of Year	1,336.4	1.4	1,344.5

Note: Figures may not add due to rounding.

The following table provides information as of December 31, 2008, related to proved reserves, well count, and net acreage, and 2008 annual information as toproduction and capitalinvestments, for each of our operating areas, for our New Ventures and overall:

		U.S. Exploitation
	Fayetteville	Arkoma		East	Permian/	New
	Shale Play	Basin		Texas	Gulf Coast(1)	Ventures (2)	Total
Estimated Proved Reserves:
Total Reserves (Bcfe)	1,545	281		351	-	8	2,185
Percent of Total	71%	13%		16%	-	-	100%
Percent Natural Gas	100%	100%		97%	-	100%	100%
Percent Proved Developed	52%	81%		89%	-	100%	62%
Production (Bcfe)	134.5	24.4		31.6	3.1	1.0	194.6
Capital Investments (millions)(3)	$ 1,191	$ 133		$ 160	$ 3	$ 73	$ 1,560
Total Gross Producing Wells	882	1,163		531	-	14	2,590
Total Net Producing Wells	639	584		428	-	10	1,661
Total Net Acreage	749,735	551,471	(4)	134,403	-	149,909	1,585,518
Net Undeveloped Acreage	552,254	357,792	(4)	98,529	-	138,638	1,147,213

(1)  The company’s Permian Basin and onshore Texas Gulf Coast properties were sold during 2008.

(2)  Includes New Ventures opportunities such as the Marcellus Shale play in Pennsylvania and the company’s Riverton coalbed methane play in Louisiana.  

(3)  The company’s Total and Fayetteville Shale play capital investments exclude $36 million related to the purchase of drilling rig related and ancillary equipment.  

(4)  Includes 123,442 net developed acres and 1,930 net undeveloped acres in the Arkoma Basin that are also within the company’s Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.

2008 E&P Operations Review

Southwestern invested a total of $1.6 billion in its E&P business during 2008 and participated in drilling 750 wells, 479 of which were successful, 11 were dry and 260 were in progress at year-end. Of the 260 wells in progress at year-end, 236 were located in the company’s Fayetteville Shale play. Of the $1.6 billion invested, approximately $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.  

During 2008, Southwestern invested approximately $1.2 billion in its Fayetteville Shale play, $160 million in East Texas, $133 million in its conventional Arkoma Basin program and $73 million in New Ventures.

Fayetteville Shale Play- As of December 31, 2008, Southwestern had spud a total of 1,230 wells in the play, 1,015 of which were operated by the company and 215 of which were outside-operated wells. Of these wells, 604 were spud in 2008, compared to 415 wells in 2007. At year-end 2008, 804 wells had been drilled and completed, including 726 horizontal wells.

Southwestern’s net production from the Fayetteville Shale play was 134.5 Bcf in 2008, up from 53.5 Bcf in 2007, as gross production from the company’s 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 by year-end. In 2009, the company’s estimated production from the Fayetteville Shale is expected to range between 229.0 to 232.0 Bcf.

Southwestern invested approximately $1.2 billion in its Fayetteville Shale drilling program during 2008, adding 984 Bcf in new reserves during 2008 at a finding and development cost of $1.21 per Mcf (non-GAAP, see reconciliation below), including upward reserve revisions of approximately 159 Bcf due primarily to improved well performance. Total proved net gas reserves booked in the Fayetteville Shale play at year-end 2008 were 1,545 Bcf, compared to 716 Bcf of reserves booked at the end of 2007. The company’s average gross proved reserves for each of the proved undeveloped wells included in its 2008 year-end reserves was approximately 1.9 Bcf, up from 1.5 Bcf per well at the end of 2007. The company’s gross proved reserves for wells that were placed on production in the second half of 2008 averaged 2.2 Bcf per well.

During 2008, the company continued to improve its drilling practices in the Fayetteville Shale play. The company’s 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. The company also continued to improve its completion practices, 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.

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. Results from the company’s drilling activities in 2008 and 2007, by quarter, are shown below.

Time Frame	Wells Placed on Production	Average IP Rate (Mcf/d)	30th-Day Avg Rate (# of wells)	60th-Day Avg Rate (# of wells)	Average Lateral Length	Completion Method SW/XL/Hy-RHy
1st Qtr 2007	58	1,261	1,066 (58)	958 (58)	2,104	11/37/10
2nd Qtr 2007	46	1,497	1,254 (46)	1,034 (46)	2,512	24/12/10
3rd Qtr 2007	74	1,788	1,512 (72)	1,350 (71)	2,622	69/4/1
4th Qtr 2007	77	2,028	1,690 (77)	1,499 (76)	3,193	68/1/8
1st Qtr 2008	75	2,343	2,147 (75)	1,943 (74)	3,301	71/1/3
2nd Qtr 2008	83	2,541	2,155 (83)	1,858 (83)	3,562	83/0/0
3rd Qtr 2008	97	2,882	2,573 (96)	2,355 (95)	3,736	97/0/0
4th Qtr 2008	74	3,347	2,802 (59)	2,703 (26)	3,850	74/0/0

SW – Slickwater fluids

XL – Crosslinked gel fluids

Hy-RHy – Hybrid or Reverse Hybrid method (combination slickwater/crosslinked gel fluid system)

Note: Data excludes wells which were sold in May 2008.

During the fourth quarter of 2008, the company’s 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. The company currently has 22 drilling rigs running in its Fayetteville Shale play area, 15 that are capable of drilling horizontal wells and 7 smaller rigs that are used to drill the vertical portion of the wells.

During 2008, the company began to test closer perforation cluster spacing in its horizontal wells with positive results. Southwestern tested this technique on approximately 200 of its wells and has seen a 20% to 25% improvement in early production over average initial production of wells on which the company did not utilize this technique. Southwestern estimates that ultimate recovery on these wells could be improved by a corresponding 20% to 25% and is currently planning to utilize this technique on all wells it plans to drill in 2009. The company currently expects its average completed well costs to decline slightly in 2009 to approximately $2.9 million per well, as lower oilfield service costs are projected to more than offset higher costs associated with this new completion technique and longer laterals.

At December 31, 2008, Southwestern had acquired approximately 961 square miles of 3-D seismic data and plans to acquire approximately 139 square miles of 3-D seismic data during 2009, the total of which will give the company seismic data on approximately 41% of its net acreage position in the Fayetteville Shale, excluding its acreage held by conventional production in the traditional Fairway portion of the Arkoma Basin.

At December 31, 2008, Southwestern held approximately 875,000 net acres in the play area (552,254 net undeveloped acres, 197,481 net developed acres held by Fayetteville Shale production and 125,372 net acres in the traditional Fairway portion of the Arkoma Basin), down slightly from approximately 906,700 net acres at year-end 2007 due to the sale of 55,631 net acres in May 2008 to XTO Energy, Inc. At year-end 2008, approximately 26% of the company’s leasehold acreage was held by production, excluding its acreage in the traditional Fairway portion of the Arkoma Basin. The company’s undeveloped acreage

position as of December 31, 2008, had an average remaining lease term of 5 years, an average royalty interest of 15% and was obtained at an average cost of $140 per acre.

Conventional Arkoma Program - At December 31, 2008, Southwestern had approximately 281 Bcf of reserves which were attributable to its conventional Arkoma properties, representing approximately 13% of its total reserves, compared to 304 Bcf at year-end 2007. In 2008, the company invested approximately $133 million and participated in 81 wells in its conventional Arkoma drilling program, of which 67 were successful and 8 were in progress at year-end, resulting in a 92% success rate and adding new reserves of 37 Bcf. This area recorded net downward revisions of approximately 36 Bcf primarily due to a comparative decrease in year-end gas prices and negative performance revisions. Net production from the company’s conventional Arkoma properties was 24.4 Bcf in 2008, compared to 23.8 Bcf in 2007.

East Texas- At December 31, 2008, the company had approximately 351 Bcfe of reserves in East Texas, representing approximately 16% of its total reserves, compared to 353 Bcfe at year-end 2007. In 2008, the company 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 and adding new reserves of 53 Bcfe. This area recorded net downward revisions of approximately 23 Bcfe primarily due to a comparative decrease in year-end gas prices and negative performance revisions. Net production from East Texas was 31.6 Bcfe in 2008, compared to 29.9 Bcfe in 2007.

The company’s 2008 drilling program was primarily focused on developing the James Lime formation in its Angelina River Trend area located in Angelina, Nacogdoches, San Augustine and Shelby Counties in Texas. During 2008, Southwestern participated in 32 James Lime horizontal wells (20 of which it operated) and placed 15 wells it operated on production at an average gross initial production rate of 9.1 MMcfe per day with 5 wells in progress at year-end. Net proved reserves in the Angelina area were 74 Bcfe at year-end 2008, compared to 33 Bcfe at year-end 2007, while net production from its Angelina properties was 11.3 Bcfe in 2008, compared to 2.5 Bcfe in 2007. At December 31, 2008, Southwestern held approximately 86,400 gross undeveloped acres and 16,700 gross developed acres at Angelina with an average working interest of 67% and an average net revenue interest of 52%.

Permian Basin and Gulf Coast- During 2008, the company sold the oil and gas leases, wells and equipment that comprised its Permian Basin and onshore Texas Gulf Coast operating assets to various buyers for approximately $240 million in the aggregate. Net production from these areas during 2008 was 3.1 Bcfe, compared to 6.1 Bcfe in 2007.

New Ventures- At December 31, 2008, Southwestern held 138,638 net undeveloped acres in the United States outside of its core operating areas in connection with New Ventures. This compares to 156,465 net undeveloped acres held at year-end 2007. In 2008, the company invested approximately $73 million in its New Ventures program, including $58 million in the Marcellus Shale play in Pennsylvania. At year-end 2008, Southwestern had approximately 114,738 net acres in Pennsylvania under which it believes the Marcellus Shale is prospective at a total cost of $530 per acre. During 2008, the company drilled its first four wells (three vertical and one horizontal) on its acreage in Bradford and Susquehanna Counties, three of which have been production tested.  

Recent Developments

2009 Planned Capital Investments - The company’s planned capital investment program for 2009 is $1.9 billion, which includes approximately $1.6 billion for its E&P segment, $220 million for its Midstream Services segment and $40 million for other corporate purposes. Of the $1.6 billion in capital for its E&P segment, approximately $1.3 billion is planned to be invested in the company’s Fayetteville Shale play. The company’s capital investments will also include up to $110 million in East Texas, approximately $60 million in its conventional drilling program in the Arkoma Basin, $80 million in unconventional, exploration and New Ventures projects and $40 million for other E&P projects. The company will reevaluate its proposed investments as needed to take into account prevailing market conditions. The planned capital program for 2009 is flexible and can be modified, including downward if the low natural gas price environment persists for an extended period of time.

Fayetteville Shale Play - As of February 15, 2009, the company’s gross operated production rate from the Fayetteville Shale play was approximately 750 MMcf per day. The graph below provides gross production data from the company’s operated wells in the Fayetteville Shale play area.

The graph below provides normalized average daily production data through January 31, 2009, for the company’s horizontal wells using slickwater and crosslinked gel fluids. The “dark blue” curve is for horizontal wells fracture stimulated with either slickwater or crosslinked gel fluid. The “red curve” indicates results for the company’s wells with lateral lengths greater than 3,000 feet, while the “purple curve” indicates results for the company’s wells with lateral lengths greater than 4,000 feet. The normalized production curves are intended to provide a qualitative indication of the company’s Fayetteville Shale wells’ performance and should not be used to estimate an individual well’s estimated ultimate recovery. The 1.5, 2.0, 2.5 and 3.0 Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the company’s wells.

East Texas-In the second quarter of 2008, Southwestern 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 depth in the fourth quarter of 2008 and was completed in the first quarter of 2009. It is currently being tested. The second horizontal well, the Red River 164 #1, is drilling and it is expected to be completed and tested in the second quarter of 2009. The company may invest more capital in the Haynesville/Bossier Shale play than previously planned.

New Ventures - In the first quarter of 2009, the company purchased approximately 21,715 net acres in Lycoming County, Pennsylvania, for approximately $8.2 million. As a result, Southwestern currently has approximately 137,000 net undeveloped acres in Pennsylvania under which it believes the Marcellus Shale is prospective.

Explanation and Reconciliation of Non-GAAP Financial Measures

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.

	3 Months Ended December 31,		12 Months Ended December 31,
	2008	2007	2008	2007
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 283,408	$ 204,264	$ 1,167,494	$ 651,170
Add back (deduct):
Change in operating assets and liabilities	(89,306)	(16,547)	(6,685)	(28,435)
Net cash provided by operating activities	$ 194,102	$ 187,717	$ 1,160,809	$ 622,735

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 year and three years ending December 31, 2008.

	For the 12 Months Ending December 31, 2008	For the 12 Months Ending December 31, 2007	For the 3 Years Ending December 31, 2008	Fayetteville Shale Play 2008
Total exploration, development and acquisition costs incurred ($ in thousands)	$ 1,559,995	$ 1,370,876	$ 3,690,327	$ 1,191,558
Reserve extensions, discoveries and acquisitions (MMcfe)	920,181	507,855	1,793,532	824,706
Finding & development costs, excluding revisions ($/Mcfe)	$ 1.70	$ 2.70	$ 2.06	$ 1.44
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe)	1,018,281	538,830	1,835,967	983,635
Finding & development costs, including revisions ($/Mcfe)	$ 1.53	$ 2.54	$ 2.01	$ 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.

Southwestern will host a teleconference call on Friday, February 27, 2009, at 10:00 a.m. Eastern to discuss the company’s fourth quarter and year-end 2008 financial and operating results. The toll-free number to call is 800-289-0726 and the reservation number is 2542191. The teleconference can also be heard “live” on the Internet athttp://www.swn.com.

Southwestern Energy Company is an integrated 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 athttp://www.swn.com.

Contacts:	Greg D. Kerley	Brad D. Sylvester, CFA
	Executive Vice President	Vice President, Investor Relations
	and Chief Financial Officer	(281) 618-4897
	(281) 618-4803

All statements, other than historical 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. 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 plays; the company’s ability to fund the company’s planned capital investments; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the impact of federal, state and local government regulation, including any increase in severance taxes; 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

OPERATING STATISTICS (Unaudited)			Page 1 of 5
Southwestern Energy Company and Subsidiaries
	Three Months		Twelve Months
Periods Ended December 31	2008	2007	2008	2007
Exploration & Production
Production
Gas production (MMcf)	57,373	34,002	192,265	109,881
Oil production (MBbls)	40	142	385	614
Total equivalent production (MMcfe)	57,609	34,851	194,573	113,565
Commodity Prices
Average gas price per Mcf, including hedges	$     5.93	$      6.90	$     7.52	$      6.80
Average gas price per Mcf, excluding hedges	$     5.14	$      6.21	$     7.73	$      6.16
Average oil price per Bbl	$   61.64	$     90.96	$ 107.18	$     69.12
Operating Expenses per Mcfe
Lease operating expenses	$    ��0.87	$      0.79	$     0.89	$      0.73
General & administrative expenses	$     0.49	$      0.52	$     0.41	$      0.48
Taxes, other than income taxes	$     0.06	$      0.09	$     0.13	$      0.16
Full cost pool amortization	$     1.87	$      2.39	$     1.99	$      2.41
Midstream
Gas volumes marketed (Bcf)	76.8	46.2	258.0	145.7
Gas volumes gathered (Bcf)	71.1	30.2	224.1	78.7

STATEMENTS OF OPERATIONS (Unaudited)			Page 2 of 5
Southwestern Energy Company and Subsidiaries
	Three Months		Twelve Months
Periods Ended December 31	2008	2007	2008	2007
	(in thousands, except share/per share amounts)
Operating Revenues
Gas sales	$    330,077	$      273,249	$ 1,490,646	$      870,047
Gas marketing	154,805	107,996	729,671	316,912
Oil sales	2,424	12,868	41,240	42,434
Gas gathering	11,614	5,346	41,748	11,627
Transportation and other	1,157	3,316	8,247	14,111
	500,077	402,775	2,311,552	1,255,131
Operating Costs and Expenses
Gas purchases – midstream services	149,639	105,043	710,129	306,336
Gas purchases – gas distribution	—	27,974	61,439	85,445
Operating expenses	29,674	23,742	107,577	85,826
General and administrative expenses	31,423	25,487	101,959	80,269
Depreciation, depletion and amortization	113,930	90,268	414,408	293,914
Taxes, other than income taxes	4,479	4,013	29,272	21,875
	329,145	276,527	1,424,784	873,665
Operating Income	170,932	126,248	886,768	381,466
Interest Expense
Interest on debt	14,202	13,987	61,152	36,191
Other interest charges	535	375	2,284	1,474
Interest capitalized	(12,937)	(4,217)	(34,532)	(13,792)
	1,800	10,145	28,904	23,873
Other Income (Loss)	1,874	(198)	4,404	(219)
Gain on Sale of Utility Assets	—	—	57,264	—
Income Before Income Taxes and Minority Interest	171,006	115,905	919,532	357,374
Minority Interest in Partnership	(40)	(72)	(587)	(345)
Income Before Income Taxes	170,966	115,833	918,945	357,029
Provision for Income Taxes
Current	14,500	—	122,000	—
Deferred	52,267	44,201	228,999	135,855
	66,767	44,201	350,999	135,855
Net Income	$    104,199	$        71,632	$    567,946	$      221,174
Earnings Per Share(1)
Basic	$           0.30	$            0.21	$           1.66	$            0.65
Diluted	$           0.30	$            0.21	$           1.64	$            0.64
Weighted Average Common Shares Outstanding(1)
Basic	342,366,075	340,047,938	341,621,814	338,953,446
Diluted	346,342,212	347,819,050	346,245,938	347,442,660

(1) 2007 restated to reflect the two-for-one stock split effected on March 25, 2008.

BALANCE SHEETS (Unaudited)	Page 3 of 5
Southwestern Energy Company and Subsidiaries
December 31	2008	2007
	(in thousands)
ASSETS
Current Assets	$        889,265	$         304,464
Current Assets Held For Sale	-	58,877
Property, Plant and Equipment, at cost	5,328,914	4,278,384
Less:  Accumulated depreciation, depletion and amortization	1,615,307	1,200,754
	3,713,607	3,077,630
Assets Held For Sale	-	143,234
Other Assets	157,286	38,511
	$    4,760,158	$      3,622,716
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$        792,861	$         391,777
Current Liabilities Associated With Assets Held For Sale	-	39,118
Long-Term Debt	674,200	977,600
Deferred Income Taxes	721,707	479,196
Long-Term Hedging Liability	5,934	15,186
Other Liabilities	47,493	47,352
Other Liabilities Associated With Assets Held For Sale	-	15,417
Commitments and Contingencies
Minority Interest in Partnership	10,133	10,570
Stockholders’ Equity
Common stock, $.01 par value; authorized 540,000,000 shares, issued 343,624,956 shares in 2008 and 341,581,672 in 2007(1)	3,436	3,416
Additional paid-in capital(1)	811,492	752,369
Retained earnings	1,449,977	882,031
Accumulated other comprehensive income	247,665	13,348
Common stock in treasury, 225,050 shares in 2008 and 222,774 in 2007(1)	(4,740)	(4,664)
	2,507,830	1,646,500
	$    4,760,158	$      3,622,716

 (1) 2007 restated to reflect the two-for-one stock split effected on March 25, 2008.

STATEMENTS OF CASH FLOWS (Unaudited)	Page 4 of 5
Southwestern Energy Company and Subsidiaries
	Twelve Months
Periods Ended December 31	2008	2007
	(in thousands)
Cash Flows From Operating Activities
Net income	$        567,946	$         221,174
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	416,151	295,332
Deferred income taxes	228,999	135,855
Gain on sale of utility assets	(57,264)	—
Unrealized loss (gain) on derivatives	4,644	(7,103)
Stock-based compensation expense	7,952	6,377
Gain on sale of property, plant and equipment	(497)	—
Minority interest in partnership	(437)	(465)
Change in assets and liabilities	(6,685)	(28,435)
Net cash provided by operating activities	1,160,809	622,735
Cash Flows From Investing Activities
Capital investments	(1,755,888)	(1,519,433)
Proceeds from sale of assets	964,031	5,791
Other items	(221)	145
Net cash used in investing activities	(792,078)	(1,513,497)
Cash Flows From Financing Activities
Debt retirement	(1,200)	(1,200)
Payments on revolving long-term debt	(1,843,600)	(916,550)
Borrowings under revolving long-term debt	1,001,400	1,758,750
Proceeds from issuance of long-term debt	600,000	—
Debt issuance costs and revolving credit facility costs	(8,895)	(2,000)
Excess tax benefit for stock-based compensation	43,107	—
Change in bank drafts outstanding	31,397	5,193
Proceeds from exercise of common stock options	3,505	5,474
Net cash provided by (used in) financing activities	(174,286)	849,667
Increase (decrease) in cash and cash equivalents	194,445	(41,095)
Cash and cash equivalents at beginning of year(1)	1,832	42,927
Cash and cash equivalents at end of year(1)	$        196,277	$             1,832

(1)

Cash and cash equivalents at the beginning of the year for 2008 and at the beginning and end of the year 2007 include amounts classified as “held for sale.”

SEGMENT INFORMATION (Unaudited)					Page 5 of 5
Southwestern Energy Company and Subsidiaries
	Exploration			Natural Gas
	&		Midstream	Distribution
	Production		Services	& Other	Eliminations	Total
	(in thousands)
Quarter Ending December 31, 2008
Revenues	$    343,387		$    445,717	$            231	$  (289,258)	$    500,077
Gas purchases	—		405,290	—	(255,651)	149,639
Operating expenses	49,875		13,294	—	(33,495)	29,674
General & administrative expenses	28,068		3,452	15	(112)	31,423
Depreciation, depletion & amortization	109,807		3,816	307	—	113,930
Taxes, other than income taxes	3,536		933	10	—	4,479
Operating Income (Loss)	$    152,101		$      18,932	$          (101)	$              —	$    170,932
Capital Investments(1)	$    440,803	(2)	$      49,476	$        8,868	$              —	$    499,147
Quarter Ending December 31, 2007
Revenues	$      248,755		$      310,711	$        52,725	$    (209,416)	$      402,775
Gas purchases	—		292,944	33,378	(193,305)	133,017
Operating expenses	27,649		5,428	6,636	(15,971)	23,742
General & administrative expenses	18,041		2,956	4,630	(140)	25,487
Depreciation, depletion & amortization	86,518		2,233	1,517	—	90,268
Taxes, other than income taxes	2,986		313	714	—	4,013
Operating Income	$      113,561		$          6,837	$          5,850	$               —	$      126,248
Capital Investments(1)	$      328,235	(2)	$        30,968	$          3,241	$               —	$      362,444
Twelve Months Ending December 31, 2008
Revenues	$1,491,302		$2,173,971	$    118,399	$(1,472,120)	$ 2,311,552
Gas purchases	—		2,043,417	79,120	(1,350,969)	771,568
Operating expenses	173,692		40,382	14,139	(120,636)	107,577
General & administrative expenses	80,215		13,522	8,737	(515)	101,959
Depreciation, depletion & amortization	399,159		11,402	3,847	—	414,408
Taxes, other than income taxes	24,732		2,899	1,641	—	29,272
Operating Income	$    813,504		$      62,349	$      10,915	$              —	$    886,768
Capital Investments(1)	$1,595,828	(2)	$    183,021	$      17,319	$              —	$ 1,796,168
Twelve Months Ending December 31, 2007
Revenues	$      795,944		$      961,994	$      174,914	$    (677,721)	$   1,255,131
Gas purchases	—		915,053	111,338	(634,610)	391,781
Operating expenses	83,383		18,568	26,419	(42,544)	85,826
General & administrative expenses	54,802		8,624	17,410	(567)	80,269
Depreciation, depletion & amortization	281,910		5,524	6,480	—	293,914
Taxes, other than income taxes	17,770		989	3,116	—	21,875
Operating Income	$      358,079		$        13,236	$        10,151	$               —	$      381,466
Capital Investments(1)	$   1,379,657	(2)	$      107,363	$        16,118	$               —	$   1,503,138

(1)  Capital investments include increases of $29.2 million and $36.2 million for the three- and twelve-month periods ended December 31, 2008, respectively, and reductions of $18.1 million and $20.6 million for the three- and twelve-month periods ended December 31, 2007, respectively, relating to the change in accrued expenditures between periods.

(2)  Exploration and production capital investments include $15.7 million and $26.7 million for the three- and twelve-month periods ended December 31, 2008, respectively, and $0.5 million and $4.5 million for the three- and twelve-month periods ended December 31, 2007, respectively, for the investment in drilling rig equipment.