Southwestern Energy Announces 2012 Financial And Operating Results

      Southwestern Energy Announces 2012 Financial And Operating Results

PR Newswire

HOUSTON, Feb. 20, 2013

HOUSTON, Feb. 20, 2013 /PRNewswire/ --Southwestern Energy Company (NYSE: SWN)
today announced its financial and operating results for the fourth quarter and
the year ended December 31, 2012. Calendar year 2012 highlights include:

  oGas and oil production of 565 Bcfe, up 13% over 2011
  oAdjusted net income of $485.2 million, which excludes non-cash ceiling
    test impairments of natural gas and oil properties and unrealized net
    gains on derivative contracts (a non-GAAP measure reconciled below)
  oNet cash provided by operating activities before changes in operating
    assets and liabilities of approximately $1.6 billion (a non-GAAP measure
    reconciled below)

"Southwestern Energy's storyline in 2012 was 'Success in a low gas price
environment,' not 'Survival hoping for a better product prices,'" remarked
Steve Mueller, President and Chief Executive Officer of Southwestern Energy.
"We grew production by 13%, set records both for highest average initial
producing rates and lowest well costs in the Fayetteville Shale and ramped our
Marcellus production dramatically. During 2012, we also posted the second
highest cash flow in the company's history, along with record gathered gas
volumes that translated to record cash flows in our Midstream business.

"I am especially excited about the way we eliminated some of our operating
costs. We didn't just reduce costs. A team made up of several disciplines
found ways to eliminate the need for two of our three salt water disposal
facilities in the Fayetteville Shale. Working with agencies in Arkansas, our
staff developed new methods to creatively and effectively reuse the water
leading to less road use, less water to dispose of and significant long term
cost savings.

"Our approach in 2013 maintains the sharp focus on innovation both in our
operating areas and our exploration projects. Good economic decisions remain
imperative, along with staying disciplined and improving the efficiency and
safety in our operations. I am very proud of what our employees have
accomplished in 2012 and I am very excited about what our team can do in 2013.
It looks to be one of the most exciting years in Southwestern Energy's
history."

Fourth Quarter of 2012 Financial Results

For the fourth quarter of 2012, Southwestern reported a net loss of $355.6
million, or $1.02 per diluted share. This included a $849.3 million non-cash
ceiling test impairment ($510.4 million net of taxes) of the company's natural
gas and oil properties resulting from lower natural gas prices. The net loss
also included a non-cash unrealizedloss of $2.6 million ($1.6 million net of
taxes) on derivative contracts. Excluding these non-cash items, Southwestern
reported net income for the fourth quarter of 2012 of $156.4 million
(reconciled below), or $0.44 per diluted share, compared to net income of
$158.5 million, or $0.45 per diluted share, for the prior year period. Net
cash provided by operating activities before changes in operating assets and
liabilities (reconciled below) was $456.9 million for the fourth quarter of
2012, compared to $453.7 million for the same period in 2011.

E&P Segment – Excluding the non-cash items noted above, operating income from
the company's E&P segment (reconciled below) was $196.8 million for the three
months ended December 31, 2012, compared to $195.8 million for the same period
in 2011. The increase was primarily due to higher production volumes,
partially offset by lower realized natural gas prices and increased operating
costs and expenses from higher activity levels.

Gas and oil production totaled 149.9 Bcfe in the fourth quarter of 2012, up
12% from 133.3 Bcfe in the fourth quarter of 2011, and included 125.1 Bcf from
the company's Fayetteville Shale play, up from 116.5 Bcf in the fourth quarter
of 2011. Production from the Marcellus Shale was 19.3 Bcf in the fourth
quarter of 2012, compared to 8.1 Bcf in the fourth quarter of 2011.

Including the effect of hedges, Southwestern's average realized gas price in
the fourth quarter of 2012 was $3.72 per Mcf, down from $4.04 per Mcf in the
fourth quarter of 2011. The company's commodity hedging activities increased
its average gas price by $0.76 per Mcf during the fourth quarter of 2012,
compared to an increase of $1.00 per Mcf during the same period in 2011. As of
February 20, 2013, the company had approximately 185 Bcf of its 2013
forecasted gas production hedged at an average floor price of $5.06 per Mcf
and approximately 55 Bcf of its 2014 forecasted gas production hedged at an
average floor price of $4.43 per Mcf. As of December 31, 2012, the company had
protected approximately 232.7 Bcf of its 2013 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 $0.05 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 hedges,
the company's average price received for its gas production during the fourth
quarter of 2012 was approximately $0.44 per Mcf lower than average NYMEX
settlement prices, compared to approximately $0.51 per Mcf lower during the
fourth quarter of 2011.

Lease operating expenses per unit of production for the company's E&P segment
were $0.81 per Mcfe in the fourth quarter of 2012, compared to $0.84 per Mcfe
in the fourth quarter of 2011. The decrease was primarily due to lower salt
water disposal costs.

General and administrative expenses per unit of production were $0.25 per Mcfe
in the fourth quarter of 2012, down from $0.29 per Mcfe in the fourth quarter
of 2011. The decrease was primarily due to decreased personnel costs per unit
of production.

Taxes other than income taxes per unit of production were $0.09 per Mcfe in
the fourth quarter of 2012, compared to $0.10 in the fourth quarter of 2011.
Taxes other than income taxes per Mcfe vary from period to period due to
changes in severance and ad valorem taxes that result from the mix of the
company's production volumes and fluctuations in commodity prices.

The company's full cost pool amortization rate decreased to $1.24 per Mcfe in
the fourth quarter of 2012, compared to $1.31 per Mcfe in the fourth 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 $77.7 million for the three months ended December 31, 2012, up from $67.6
million in the same period in 2011. The increase in operating income was
primarily due to the increase in gathering revenues from the company's
Fayetteville and Marcellus Shale properties, partially offset by increased
operating costs and expenses.

Full-Year 2012 Financial Results

Southwestern reported a net loss of $707.1 million in 2012, or $2.03 per
diluted share. This included $1,939.7 million in non-cash ceiling test
impairments ($1,192.4 million net of taxes) of the company's natural gas and
oil properties resulting from lower natural gas prices. The net loss also
included a non-cash gain of $0.3 million ($0.2 million net of taxes) on
derivative contracts. Excluding these non-cash items, the company reported
adjusted net income of $485.2 million (reconciled below) in 2012, or $1.39 per
diluted share, compared to $637.8 million, or $1.82 per diluted share, in
2011. Net cash provided by operating activities before changes in operating
assets and liabilities (reconciled below) was approximately $1.6 billion in
2012, compared to approximately $1.8 billion for the same period in 2011.

E&P Segment – Excluding the non-cash items noted above, operating income from
the company's E&P segment (reconciled below) was $528.3 million 2012, compared
to $825.1 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 565.0 Bcfe in 2012, up 13% compared to 500.0 Bcfe
in 2011, and included 485.5 Bcf from the company's Fayetteville Shale play, up
from 436.8 Bcf in 2011. Production from the Marcellus Shale was 53.6 Bcf in
2012, compared to 23.4 Bcf in 2011.

Southwestern's average realized gas price was $3.44 per Mcf, including the
effect of hedges, in 2012 compared to $4.19 per Mcf in 2011. The company's
hedging activities increased the average gas price realized in 2012 by $1.10
per Mcf, compared to an increase of $0.63 per Mcf in 2011. Disregarding the
impact of hedges, the average price received for the company's gas production
during 2012 was approximately $0.45 per Mcf lower than average NYMEX
settlement prices, compared to approximately $0.48 per Mcf lower than NYMEX
settlement prices in 2011. For 2013, the company expects its total gas sales
discount to NYMEX to be $0.50 to $0.55 per Mcf.

Lease operating expenses for the company's E&P segment were $0.80 per Mcfe in
2012, down from $0.84 per Mcfe in 2011. The decrease was primarily due to
lower compression and salt water disposal costs associated with the
Fayetteville Shale play.

General and administrative expenses were $0.26 per Mcfe in 2012, down from
$0.27 per Mcfe in 2011. The decrease was primarily due to decreased personnel
costs per unit of production.

Taxes other than income taxes were $0.10 per Mcfe in 2012, down from $0.11 per
Mcfe in 2011.

The company's full cost pool amortization rate increased to $1.31 per Mcfe in
2012, compared to $1.30 per Mcfe in 2011.

Midstream Services – Operating income for the company's midstream activities
was $294.3 million in 2012, up 19% compared to $248.0 million 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 a decrease in gas marketing margin and increased operating
costs and expenses. At December 31, 2012, the company's midstream segment was
gathering approximately 2.3 Bcf per day through 1,852 miles of gathering lines
in the Fayetteville Shale play, compared to gathering approximately 2.1 Bcf
per day through 1,791 miles of gathering lines at December 31, 2011. Gathering
volumes, revenues and expenses for this segment are expected to grow over the
next few years largely as a result of continued development of the company's
acreage in the Fayetteville Shale and Marcellus Shale and development activity
undertaken by other operators in those areas.

Capital Structure and Investments – At December 31, 2012, the company had
approximately $1.7 billion in long-term debt and its long-term debt-to-total
capitalization ratio was 35.5%, up from 25.3% at December 31, 2011. The
company had no borrowings on its revolving credit facility and also had cash
and cash equivalents and restricted cash of approximately $62.1 million at
December 31, 2012.

In 2012, Southwestern invested approximately $2.1 billion, down from
approximately $2.2 billion in capital investments in 2011, and included
approximately $1.9 billion invested in its E&P business, $165 million invested
in its Midstream Services segment and $55 million invested for corporate and
other purposes.

2012 Gas and Oil Reserves and Operational Review

Southwestern's estimated proved gas and oil reserves totaled approximately
4,018 Bcfe at December 31, 2012, compared to 5,893 Bcfe at the end of 2011.
The decrease in reserves was primarily due to downward reserve revisions
caused by the effect of lower natural gas prices, production and asset
dispositions, partially offset by an increase in reserves from the development
of the Marcellus Shale play. Since the company is primarily a natural gas
producer it is impacted more by changes in prices for natural gas than changes
in price for crude oil, condensate or natural gas liquids. The average prices
utilized to value the company's estimated proved natural gas and oil reserves
at December 31, 2012 were $2.76 per MMBtu for natural gas and $91.21 per
barrel for oil, compared to $4.12 per MMBtu for natural gas and $92.71 per
barrel for oil at December 31, 2011. Approximately 100% of the company's
estimated proved reserves were natural gas and 80% were classified as proved
developed at year-end 2012, compared to 100% and 55%, respectively, at
year-end 2011.

The following table details additional information relating to reserve
estimates as of and for the year ended December 31, 2012:

                                      Natural Gas (Bcf) Crude Oil Total (Bcfe)
                                                        (MBbls)
Proved Reserves, Beginning of Year    5,887.2           996       5,893.2
Revisions of Previous Estimates       (2,088.0)         (44)      (2,088.2)
Extensions, Discoveries, & Other      918.6             154       919.5
Additions
Production                            (564.5)           (83)      (565.0)
Acquisition of Reserves in Place      ----              ----      ----
Disposition of Reserves in Place      (136.5)           (779)     (141.2)
Proved Reserves, End of Year          4,016.8           244       4,018.3
Proved, Developed Reserves:
 Beginning of Year                  3,254.0           983       3,259.9
 End of Year                        3,195.7           243       3,197.1

 Note: Figures may not add due to rounding

In 2012, Southwestern added 919.5 Bcfe of proved gas and oil reserves as a
result of its drilling program, of which 582.8 Bcfe were proved developed and
336.7 Bcfe were proved undeveloped. The total downward reserve revisions of
2,088.2 Bcfe was primarily an effect of the low commodity price environment
encountered during 2012 and included downward performance revisions of 336.4
Bcfe. In addition, the company's reserves decreased by 565.0 Bcfe of
production and 141.2 Bcfe as a result of the sale of certain oil and natural
gas leases and wells in 2012. For the period ending December31, 2012, the
company's three-year average reserve replacement ratio, including revisions,
was 141%. Excluding reserve revisions, the company's 2012 and three-year
average reserve replacement ratios were 163% and 259%, respectively.

For the period ending December31, 2012, the company's three-year finding and
development cost, including revisions, was $2.74 per Mcfe (finding and
development costs are considered by the Securities and Exchange Commission
(SEC) to be non-GAAP financial measures and have been computed below).
Excluding reserve revisions, the company's 2012 and three-year average finding
and development costs were $2.08 per Mcfe and $1.48 per Mcfe, respectively.

The following table provides an overall and by category summary of the
company's gas and oil reserves, as of fiscal year end 2012 based on average
prices utilized to value the company's estimated proved natural gas and oil
reserves of $2.76 per MMBtu for natural gas and $91.21 per barrel for oil and
required by the SEC, and its well count, net acreage and PV-10 as of December
31, 2012 and sets forth 2012 annual information related to production and
capital investments for each of its operating areas:

2012 Proved Reserves by Category and Summary Operating Data

                                                Ark-La-Tex
               Fayetteville      Marcellus      East          Arkoma         New
               Shale Play        Shale          Texas         Basin          Ventures         Total
                                 Play
Estimated
Proved
Reserves:
Natural Gas
(Bcf):
Developed          2,624           374            51            146            1                3,196
(Bcf)
Undeveloped        364             442            1             14             –                821
(Bcf)
                   2,988           816            52            160            1                4,017
Crude Oil
(MMBbls):
Developed          –               –              0.1           –              0.1              0.2
(MMBbls)
Undeveloped        –               –              –             –              –                –
(MMBbls)
                   –               –              0.1           –              0.1              0.2
Total Proved
Reserves
(Bcfe)^(1):
Proved
Developed          2,624           374            52            146            1                3,197
(Bcfe)
Proved
Undeveloped        364             442            1             14             –                821
(Bcfe)
                   2,988           816            53            160            1                4,018
Percent of         75%             20%            1%            4%             –                100%
Total
Percent Proved     88%             46%            97%           91%            100%             80%
Developed
Percent Proved     12%             54%            3%            9%             –                20%
Undeveloped
Production         486             54             11            14             –                565
(Bcfe)
Capital
Investments    $   991           $ 507          $ 5           $ 6            $ 337            $ 1,846
(millions)^(2)
Total Gross
Producing          3,228           132            173           1,180          4                4,717
Wells^(3)
Total Net
Producing          2,186           71             110           570            4                2,941
Wells^(3)
Total Net          788,849  ^(4)   176,298 ^(5)   49,340 ^(6)   238,940 ^(7)   3,822,344 ^(8)   5,075,771
Acreage
Net
Undeveloped        308,924  ^(4)   159,078 ^(5)   1,874  ^(6)   63,341  ^(7)   3,819,128 ^(8)   4,352,345
Acreage
PV-10:
Pre-tax        $   1,693         $ 483          $ 30          $ 112          $ 6              $ 2,324
(millions)^(9)
PV of taxes        199             57             3             14             –                273
(millions)^(9)
After-tax      $   1,494         $ 426          $ 27          $ 98           $ 6              $ 2,051
(millions)^(9)
Percent of         73%             21%            1%            5%             –                100%
Total
Percent            97%             99%            97%           89%            100%             97%
Operated^(10)

     The company has no reserves from synthetic gas, synthetic oil or
     nonrenewable natural resources intended to be upgraded into synthetic gas
     or oil. We used standard engineering and geoscience methods, or a
     combination of methodologies in determining estimates of material
     properties, including performance and test date analysis offset
     statistical analogy of performance data, volumetric evaluation, including
(1)  analysis of petrophysical parameters (including porosity, net pay, fluid
     saturations (i.e., water, oil and gas) and permeability) in combination
     with estimated reservoir parameters (including reservoir temperature and
     pressure, formation depth and formation volume factors), geological
     analysis, including structure and isopach maps and seismic analysis,
     including review of 2-D and 3-D data to ascertain faults, closure and
     other factors.
     The company's Total and Fayetteville Shale play capital investments
(2)  exclude $15 million related to its drilling rig related equipment, sand
     facility and other equipment.
(3)  Represents all producing wells, including wells in which we only have an
     overriding royalty interest, as of December 31, 2012.
     Assuming successful wells are not drilled to develop the acreage and
     leases are not extended, leasehold expiring over the next three years
(4)  will be 46,007 net acres in 2013, 183,824 net acres in 2014, which
     includes 153,863 net acres held on federal lands, and 39,071 net acres in
     2015.
     Assuming successful wells are not drilled to develop the acreage and
(5)  leases are not extended, leasehold expiring over the next three years
     will be 41,860 net acres in 2013, 13,467 net acres in 2014 and 3,835 net
     acres in 2015.
     Assuming successful wells are not drilled to develop the acreage and
(6)  leases are not extended, leasehold expiring over the next three years
     will be 1,340 net acres in 2013, 152 net acres in 2014 and 202 net acres
     in 2015.
     Includes 123,442 net developed acres and 1,211 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
(7)  table above. Assuming successful wells are not drilled to develop the
     acreage and leases are not extended, leasehold expiring over the next
     three years will be 1,200 net acres in 2013, 670 net acres in 2014 and
     17,788 net acres in 2015.
     Assuming successful wells are not drilled to develop the acreage and
     leases are not extended, leasehold expiring over the next three years,
     excluding New Brunswick, Canada and the Lower Smackover Brown Dense
     (LSBD) area will be 1,120 net acres in 2013, 60,294 net acres in 2014 and
     142,294 net acres in 2015. With regard to the company's acreage in New
     Brunswick, Canada, 2,518,518 net acres will expire in March 2015. The
(8)  company has applied for an additional 1-year option to extend its
     exploration license agreements and, if granted by the Province, this
     would extend its exploration license agreements until March 2016. With
     regard to the company's acreage in the LSBD play, assuming successful
     wells are not drilled and leases are not extended, leasehold expiring
     over the next three years will be 68,023 net acres in 2013, 237,181 net
     acres in 2014 and 159,718 net acres in 2015.
     Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a
     company's proved reserves that it believes is used by securities analysts
     to compare relative values among peer companies without regard to income
(9)  taxes. The reconciling difference in pre-tax PV-10 and the after-tax
     PV-10, or standardized measure, is the discounted value of future income
     taxes on the estimated cash flows from its proved oil and natural gas
     reserves.
(10) Based upon pre-tax PV-10 of proved developed producing properties.

During 2012, Southwestern invested a total of $1.9 billion in its E&P business
and participated in drilling 595 wells, 383 of which were successful, and 203
which were in progress at year-end. Of the 203 wells in progress at year-end,
133 were located in the company's Fayetteville Shale play. Of the $1.9 billion
invested in 2012, approximately $1.4 billion was invested in exploratory and
development drilling and workovers, $186 million for acquisition of
properties, $10 million for seismic expenditures and $254 million in
capitalized interest and other expenses. Additionally, the company invested
approximately $15 million in its drilling rig related equipment, sand facility
and other equipment.

Fayetteville Shale – In 2012, Southwestern invested approximately $991 million
in its Fayetteville Shale play, which included approximately $877 million to
spud 491 wells, 453 of which were operated. Included in the company's total
capital investments in the area during 2012 was $4 million for the acquisition
of properties and $110 million in capitalized costs and other expenses.

Southwestern's net production from the Fayetteville Shale was 485.5 Bcf in
2012, up 11% from 436.8 Bcf in 2011, as gross production from the company's
operated wells in the Fayetteville Shale increased from approximately 1,947
MMcf per day at the beginning of 2012 to approximately 2,090 MMcf per day by
year-end.

The company's total proved net reserves booked in the Fayetteville Shale at
year-end 2012 were 2,988 Bcf from a total of 3,508 locations, of which 3,175
were proved developed producing, 123 were proved developed non-producing and
210 were proved undeveloped. Of the 3,508 locations, 3,468 were horizontal.
Total proved net gas reserves booked in the area at year-end 2011 totaled
approximately 5,104 Bcf from a total of 4,376 locations, of which 2,735 were
proved developed producing, 59 were proved developed non-producing and 1,582
were proved undeveloped. The company's reserves in the Fayetteville Shale
increased from new reserve additions of 415 Bcf, offset by downward price
revisions of 1,684 Bcf, downward performance revisions of 362 Bcf and
production of 486 Bcf. In 2012, the company converted approximately 52% of the
wells it placed to sales from previously-booked proven undeveloped locations.
The average gross proved reserves for the undeveloped wells included in its
2012 year-end reserves was approximately 2.8 Bcf per well, compared to 2.4 Bcf
per well in 2011.

Over the past several years, the company has seen continual improvement in its
drilling practices in the Fayetteville Shale play. Southwestern's operated
horizontal wells had an average completed well cost of $2.5 million per well,
average horizontal lateral length of 4,833 feet and average time to drill to
total depth of 6.7 days from re-entry to re-entry in 2012. This compares to an
average completed operated 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 approximately 7.9 days from re-entry to re-entry during 2011. The
operated wells Southwestern placed on production during 2012 averaged initial
production rates of 3,629 Mcf per day, compared to average initial production
rates of 3,330 Mcf per day in 2011. The increase in initial production rates
in 2012 was primarily due to the optimization of the company's drilling plan
in the first quarter of 2012 toward areas in the field with the highest-return
wells. As a result, the company's average initial production rates on a per
well basis were significantly higher, particularly during the last half of
2012. During 2012, the company placed 60 operated wells on production with
initial production rates that exceeded 5.0 MMcf per day.

During the fourth quarter of 2012, the company's horizontal wells had an
average completed well cost of $2.3 million per well, average horizontal
lateral length of 4,784 feet and average time to drill to total depth of 5.7
days from re-entry to re-entry. This compares to an average completed well
cost of $2.6 million per well, average horizontal lateral length of 4,974 feet
and average time to drill to total depth of 6.8 days from re-entry to re-entry
in the third quarter of 2012. In the fourth quarter of 2012, the company had
51 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 243 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 fourth quarter of 2012
averaged initial production rates of 3,962 Mcf per day. Results from the
company's drilling activities from 2007 by quarter are shown below.

           Wells Placed  Average IP   30th-Day Avg Rate   60th-Day Avg Average
Time Frame on Production Rate (Mcf/d) (# of wells)        Rate (# of   Lateral
                                                          wells)       Length
1^st Qtr   58            1,261        1,066 (58)          958 (58)     2,104
2007
2^nd Qtr   46            1,497        1,254 (46)          1,034 (46)   2,512
2007
3^rd Qtr   74            1,769        1,510 (72)          1,334 (72)   2,622
2007
4^th Qtr   77            2,027        1,690 (77)          1,481 (77)   3,193
2007
1^st Qtr   75            2,343        2,147 (75)          1,943 (74)   3,301
2008
2^nd Qtr   83            2,541        2,155 (83)          1,886 (83)   3,562
2008
3^rd Qtr   97            2,882        2,560 (97)          2,349 (97)   3,736
2008
4^th Qtr   74            3,350^(1)    2,722 (74)          2,386 (74)   3,850
2008^(1)
1^st Qtr   120           2,992^(1)    2,537 (120)         2,293 (120)  3,874
2009^(1)
2^nd Qtr   111           3,611        2,833 (111)         2,556 (111)  4,123
2009
3^rd Qtr   93            3,604        2,624 (93)          2,255 (93)   4,100
2009
4^th Qtr   122           3,727        2,674 (122)         2,360 (120)  4,303
2009
1^st Qtr   106           3,197^(2)    2,388 (106)         2,123 (106)  4,348
2010^(2)
2^nd Qtr   143           3,449        2,554 (143)         2,321 (142)  4,532
2010
3^rd Qtr   145           3,281        2,448 (145)         2,202 (144)  4,503
2010
4^th Qtr   159           3,472        2,678 (159)         2,294 (159)  4,667
2010
1^st Qtr   137           3,231        2,604 (137)         2,238(137)   4,985
2011
2^nd Qtr   149           3,014        2,328 (149)         1,991 (149)  4,839
2011
3^rd Qtr   132           3,443        2,666 (132)         2,372 (132)  4,847
2011
4^th Qtr   142           3,646        2,606 (142)         2,243 (142)  4,703
2011
1^st Qtr   146           3,319        2,421 (146)         2,131 (146)  4,743
2012
2^nd Qtr   131           3,500        2,515 (131)         2,225 (131)  4,840
2012
3^rd Qtr   105           3,857        2,816 (105)         2,448(104)   4,974
2012
4^th Qtr   111           3,962        2,834 (109)         2,497 (70)   4,784
2012

Note: Results as of December 31, 2012.
       The significant increase in the average initial production rate for the
(1)    fourth quarter of 2008 and the subsequent decrease for the first
       quarter of 2009 primarily reflected the impact of the delay in the
       Boardwalk Pipeline.
       In the first quarter of 2010, the company's results were impacted by
(2)    the shift of all wells to "green completions" and the mix of wells, as
       a large percentage of wells were placed on production in the shallower
       northern and far eastern borders of the company's acreage.

At December 31, 2012, Southwestern held leases for approximately 913,502 net
acres in the Fayetteville Shale area, compared to approximately 925,842 net
acres at year-end 2011. In 2013, Southwestern plans to invest approximately
$830 million in the Fayetteville Shale and drill approximately 385 to 390
gross horizontal wells, all of which will be operated by the company.

Marcellus Shale  – In 2012, Southwestern invested approximately $507 million
in the Marcellus Shale, which included approximately $400 million to spud 92
wells, all of which were operated. Included in the company's total capital
investments in the Marcellus Shale during 2012 was approximately $24 million
for acquisition of leasehold properties, $6 million for seismic and $77
million in facilities, capitalized costs and other expenses.

Southwestern's net production from the Marcellus Shale was 53.6 Bcf in 2012,
up 130% from 23.4 Bcf in 2011. Gross production from the company's operated
wells in the Marcellus Shale increased from approximately 133 MMcf per day at
the beginning of 2012 to approximately 300 MMcf per day by year-end.

The company's total proved net reserves booked in the Marcellus Shale more
than doubled to 816 Bcf at year-end 2012 from a total of 203 locations, of
which 129 were proved developed producing, 1 was proved developed
non-producing and 73 were proved undeveloped. Total proved net reserves from
the company's Marcellus Shale area were 342 Bcf at year-end 2011 from a total
of 60 locations, of which 30 were proved developed producing, 2 were proved
developed non-producing and 28 were proved undeveloped. The increase in the
company's reserves in the Marcellus Shale during 2012 was primarily due to new
reserve additions of 500 Bcf and upward performance revisions of 36 Bcf,
partially offset by production of 54 Bcf and downward price revisions of 9
Bcf. The average gross proved reserves for the undeveloped wells included in
its 2012 year-end reserves was approximately 7.6 Bcf per well, compared to 7.5
Bcf per well in 2011. The average gross proved reserves for the company's
undeveloped wells by area were approximately 8.1 Bcf per well for wells booked
in Bradford County, 6.2 Bcf per well in Lycoming County, 6.7 Bcf per well in
northern Susquehanna County and 5.1 Bcf per well in southern Susquehanna
County.

As of December 31, 2012, Southwestern had spud 160 operated wells, 72 of which
were on production and 84 were in progress. Of the wells placed on production,
48 were located in Bradford County, 4 were located in Lycoming County and 20
were located in Susquehanna County. Of the 84 wells in progress at year-end
2012, 33 were either waiting on either completion or waiting to be placed to
sales, including 5 in Bradford County, 4 in Lycoming County and 24 in
Susquehanna County. The company's operated horizontal wells had an average
completed well cost of $6.1 million per well, average horizontal lateral
length of 4,070 feet and an average of 12 fracture stimulation stages in 2012.
This compares to an average completed operated well cost of $7.0 million per
well, average horizontal lateral length of 4,223 feet and an average of 14
fracture stimulation stages in 2011.

The graph below provides normalized average daily production data through
December 31, 2012, for the company's horizontal wells in the Marcellus Shale.
The "purple curve" indicates results for 27 wells with more than 12 fracture
stimulation stages, the "orange curve" indicates results for 40 wells with 9
to 12 fracture stimulation stages and the "green curve" indicates results for
4 wells 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.

(Photo: http://photos.prnewswire.com/prnh/20130220/DA63322)

At December 31, 2012, Southwestern held leases for approximately 176,298 net
acres in the Marcellus Shale area, compared to approximately 186,893 net acres
at year-end 2011. In 2013, Southwestern plans to invest approximately $705
million in the Marcellus Shale and drill approximately 86 to 88 gross
horizontal wells, all of which will be operated by the company.

Ark-La-Tex –  In 2012, Southwestern invested approximately $11 million in its
Ark-La-Tex division. Net production from these assets was 25.6 Bcfe in 2012,
compared to 39.8 Bcfe in 2011. Total proved net reserves from the company's
Ark-La-Tex division were approximately 213 Bcfe at December 31, 2012, compared
to 447 Bcfe at year-end 2011. The company's reserves in this division
decreased by 141 Bcfe related to the sale of the company's Overton Field in
East Texas, 10 Bcfe due to downward performance revisions and 59 Bcfe of
downward price revisions, partially offset by 3 Bcfe of new reserve additions.
In 2013, the company expects to invest approximately $15 million in its
Ark-La-Tex program.

New Ventures  – As of December 31, 2012, Southwestern held 3,819,128 net
undeveloped acres in connection with its New Ventures prospects, of which
2,518,518 net acres were located in New Brunswick, Canada. This compares to
3,600,314 net undeveloped acres held at year-end 2011.

Southwestern has 507,059 net acres targeting the Lower Smackover Brown Dense
formation, an unconventional oil reservoir that ranges in vertical depths from
8,000 to 11,000 feet and appears to be laterally extensive over a large area
ranging in thickness from 300 to 550 feet, located in southern Arkansas and
northern Louisiana. The company has drilled six operated wells in the play
area to date, two of which are currently producing, three of which are shut-in
for further testing or shut-in waiting on a gas pipeline tie-in and one that
was temporarily abandoned. The company's Dean 31-22-1E #1 vertical well,
located in Union Parish, Louisiana, was placed on production in October 2012
and reached a peak production rate of 214 barrels of condensate per day and
1,273 Mcf of gas per day with a calculated bottom hole flowing pressure of
5,000 psi on a 10/64" choke. After 107 days on production, the well was
shut-in waiting on a gas pipeline. Prior to shut-in, the well was producing
110 barrels of condensate per day and 700 Mcf of gas per day with a calculated
bottom hole flowing pressure of 3,000 psi on a 12/64" choke. The company's BML
#31-22 #1-1H horizontal well located in Union Parish was placed on production
in June 2012 and reached a peak production rate of 421 barrels of condensate
per day and 3,900 Mcf of gas per day with a calculated bottom hole flowing
pressure of 5,700 psi on a 24/64" choke. This well was shut-in in early August
and placed back on production in late November so that the gas could be
gathered and sold. After 128 days on production, the BML well is currently
producing 185 barrels of condensate per day and 1,890 Mcf of gas per day with
a calculated bottom hole flowing pressure of 2,800 psi on a 22/64" choke. The
company's Doles 30-22-1H #1 horizontal well located in Union Parish was placed
on production in November 2012 and reached a peak production rate of 435
barrels of condensate per day and 2,500 Mcf of gas per day with a calculated
bottom hole flowing pressure of 5,400 psi on a 26/64" choke. After 95 days on
production, the well is currently producing 240 barrels of condensate per day
and 2,180 Mcf of gas per day with a calculated bottom hole flowing pressure of
4,250 psi on a 26/64" choke.

In February 2013, the company reached a tentative agreement for a joint
venture in its Brown Dense play that includes an initial cash payment as well
as a 3-year term carry on accelerated investment activity. Final terms of the
potential joint venture agreement will be disclosed upon closing of the
agreement. Southwestern is encouraged by what it has learned from its early
work in the Brown Dense play to date and has permitted and plans to drill
additional wells in the area in 2013. If the company's drilling program yields
positive results, it expects that activity in the play could increase
significantly over the next several years.

Southwestern has 301,918 net acres in the Denver-Julesburg Basin in eastern
Colorado where it has begun testing a new unconventional oil play targeting
middle and late Pennsylvanian to Permian-age carbonates and shales. The
company has drilled a horizontal well and a vertical well, both of which are
testing multiple intervals. In February 2013, the company re-entered its
vertical well and is in the process of drilling a 3,400-foot lateral in the
Marmaton formation. This lateral is expected to be completed in the second
quarter of 2013.

The company has also drilled a horizontal oil well in Sheridan County,
Montana, targeting the Bakken and Three Forks objectives. Southwestern plans
to permit and drill additional wells in the area in 2013.

In New Brunswick, Canada, Southwestern received two one-year extensions to its
exploration license agreements which expire on March 31, 2014 and March 31,
2015, respectively. The company has applied for an additional one-year
extension and, if granted by the Province, this would extend its exploration
license agreements until March 31, 2016. Since 2010, the company has conducted
airborne gravity and magnetics surveys, surface geochemistry surveys and, as
of December 31, 2012, had acquired 248 miles of 2-D seismic data. In 2013
Southwestern intends to acquire an additional 130 miles of 2-D seismic data in
preparation for drilling its first wells. Through December 31, 2012, the
company had invested approximately $25.8 million in its New Brunswick
exploration program, which represents its first venture outside of the United
States.

In 2012, Southwestern invested $337 million in its New Ventures program and
currently plans to invest approximately $235 million in New Ventures 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 twelve months ended December 31, 2012 and 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.

                                                 3 Months Ended Dec. 31,
                                                 2012            2011
                                                 (in thousands)
Net income (loss):
Net income (loss)                                $  (355,583)  $   158,533
Add back (deduct):
Impairment of natural gas and oil properties     510,372         --
(net of taxes)
Unrealized loss on derivative contracts (net of  1,610           --
taxes)
Adjusted netincome                              $   156,399   $   158,533

                                                 12 Months Ended Dec. 31,
                                                 2012            2011
                                                 (in thousands)
Net income (loss):
Net income (loss)                                $  (707,064)  $   637,769
Add back (deduct):
Impairment of natural gas and oil properties     1,192,412       --
(net of taxes)
Unrealized gain on derivative contracts (net of  (167)           --
taxes)
Adjusted netincome                              $   485,181   $   637,769

                                       3 Months Ended Dec. 31,
                                       2012                  2011
Diluted earnings per share:
Net income (loss) per share            $       (1.02)  $      0.45
Add back (deduct):
Impairment of natural gas and oil      1.46                  --
properties (net of taxes)
Unrealized loss on derivative          --                    --
contracts (net of taxes)
Adjusted net income per share          $        0.44  $      0.45

                                       12 Months Ended Dec. 31,
                                       2012                  2011
Diluted earnings per share:
Net income (loss) per share            $       (2.03)  $      1.82
Add back (deduct):
Impairment of natural gas and oil      3.42                  --
properties (net of taxes)
Unrealized gain on derivative          --                    --
contracts (net of taxes)
Adjusted net income per share          $        1.39  $      1.82

                                                  3 Months Ended Dec. 31,
                                                  2012           2011
                                                  (in thousands)
Cash flow from operating activities:
Net cash provided by operating activities         $   461,465  $   439,606
Add back (deduct):
Change in operating assets and liabilities        (4,541)        14,072
Net cash provided by operating activities before
changes                                           $   456,924  $   453,678

 in operating assets and liabilities

                                                    12 Months Ended Dec. 31,
                                                    2012          2011
                                                    (in thousands)
Cash flow from operating activities:
Net cash provided by operating activities           $ 1,653,942  $ 1,739,817
Add back (deduct):
Change in operating assets and liabilities          (55,061)      26,201
Net cash provided by operating activities before
changes                                             $ 1,598,881  $ 1,766,018

 in operating assets and liabilities

                                             3 Months Ended Dec. 31,
                                             2012            2011
                                             (in thousands)
E&P segment operating income:
E&P segment operating income (loss)          $  (655,085)  $   195,840
Add back (deduct):
Impairment of natural gas and oil properties 849,261         --
Unrealized loss on derivative contracts      2,618           --
Adjusted E&P segment operating income        $   196,794   $   195,840

                                             12 Months Ended Dec. 31,
                                             2012           2011
                                             (in thousands)
E&P segment operating income:
E&P segment operating income (loss)          $ (1,411,211)  $   825,138
Add back (deduct):
Impairment of natural gas and oil properties 1,939,734      --
Unrealized gain on derivative contracts      (272)          --
Adjusted E&P segment operating income        $   528,251  $   825,138

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 periods ending December 31, 2012 and
three years ending December 31, 2012.

             For the 12   For the 12  For the 3    Fayetteville  Fayetteville
             Months       Months      Years
             Ending       Ending      Ending       Shale Play     Shale Play
             December     December    December     2012           2011
             31, 2012     31, 2011    31, 2012
Total
exploration,
development
and          $       $       $    
acquisition                                $  1,048,420  $  1,347,605
costs        1,910,943   1,960,106  5,652,473
incurred ($
in
thousands)
Reserve
extensions,
discoveries  919,515      1,459,456   3,810,096    414,874        1,211,210
and
acquisitions
(MMcfe)
Finding &
development  $       $       $    
costs,                             $        $      
excluding      2.08                      2.53           1.11
revisions                 1.34        1.48
($/Mcfe)
Reserve
extensions,
discoveries,
acquisitions (1,168,732)  1,493,201   2,065,186    (1,631,154)    1,196,041
and reserve
revisions
(MMcfe)
Finding &
development  $       $       $    
costs,                             $         $      
including     (1.64)                      (0.64)         1.13
revisions                 1.31        2.74
($/Mcfe)

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.

Southwestern management will host a teleconference call on Thursday, February
21, 2013 at 10:00 a.m. EST to discuss its fourth quarter and year-end 2012
results. The toll-free number to call is 877-407-8035 and the international
dial-in 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

OPERATING STATISTICS (Unaudited)
Southwestern Energy Company and
Subsidiaries
                            Three Months              Twelve Months
Periods Ended December 31   2012         2011         2012         2011
Exploration & Production
Production
 Natural gas production    149.8        133.2        564.5        499.4
(Bcf)
 Oil production (MBbls)    24           18           83           97
 Total equivalent          149.9        133.3        565.0        500.0
production (Bcfe)
Commodity Prices
 Average gas price per
Mcf, including              $       $       $       $     
                            3.72         4.04         3.44         4.19
  hedges
 Average gas price per
Mcf, excluding              $       $       $       $     
                            2.96         3.04         2.34         3.56
 hedges
 Average oil price per Bbl $        $        $         $    
                            98.17        96.49        101.54       94.08
Operating Expenses per Mcfe
 Lease operating expenses  $       $       $       $     
                            0.81         0.84         0.80         0.84
 General & administrative  $       $       $       $     
expenses                    0.25         0.29         0.26         0.27
 Taxes, other than income  $       $       $       $     
taxes                       0.09         0.10         0.10         0.11
 Full cost pool            $       $       $       $     
amortization                1.24         1.31         1.31         1.30
Midstream
Gas volumes marketed (Bcf)  177.5        161.0        676.2        611.4
Gas volumes gathered (Bcf)  222.6        200.0        845.5        745.7

STATEMENTS OF OPERATIONS
(Unaudited)
Southwestern Energy Company and
Subsidiaries
                     Three Months                 Twelve Months
Periods Ended        2012            2011         2012           2011
December 31
                     (in thousands, except share/per share amounts)
Operating Revenues
Gas sales            $   557,209  $          $  1,941,361  $  2,079,725
                                     535,560
Gas marketing        168,025         164,880      591,528        714,123
Oil sales            2,330           1,698        8,427          9,085
Gas gathering        45,434          42,012       173,727        149,973
                     772,998         744,150      2,715,043      2,952,906
Operating Costs and
Expenses
Gas purchases –      168,525         163,573      592,466        709,091
midstream services
Operating expenses   65,257          65,181       244,735        240,944
General and
administrative       45,268          45,086       175,147        158,041
expenses
Depreciation,
depletion and        205,561         190,331      810,953        704,511
amortization
Impairment of
natural gas and oil  849,261         —            1,939,734      —
properties
Taxes, other than    16,430          16,089       67,584         65,518
income taxes
                     1,350,302       480,260      3,830,619      1,878,105
Operating Income     (577,304)       263,890      (1,115,576)    1,074,801
(Loss)
Interest Expense
Interest on debt     24,142          17,041       93,296         65,421
Other interest       1,358           892          4,454          4,306
charges
Interest capitalized (16,148)        (13,121)     (62,093)       (45,652)
                     9,352           4,812        35,657         24,075
Other Income (Loss), (1,585)         (57)         1,030          264
Net
Income (Loss) Before (588,241)       259,021      (1,150,203)    1,050,990
Income Taxes
Provision (Benefit)
for Income Taxes
Current              18,320          507          18,689         4,198
Deferred             (250,978)       99,981       (461,828)      409,023
                     (232,658)       100,488      (443,139)      413,221
Net Income (Loss)    $             $          $             $  
                     (355,583)       158,533     (707,064)     637,769
Earnings Per Share
 Net income (loss)  $          $       $          $      
- Basic              (1.02)          0.47        (2.03)        1.84
 Net income (loss)  $          $       $          $      
- Diluted            (1.02)          0.45        (2.03)        1.82
Weighted Average
Common Shares
Outstanding
 Basic              349,618,083     347,605,871  348,610,503    347,205,316
 Diluted            349,618,083     350,048,857  348,610,503    349,921,413

BALANCE SHEETS (Unaudited)
Southwestern Energy Company and
Subsidiaries
December 31                               2012               2011
                                          (in thousands)
ASSETS
Current Assets ^                          $     808,912  $     978,278
Property and Equipment                    13,028,439         11,060,819
Less: Accumulated depreciation, depletion 7,191,463          4,415,339
and amortization
                                          5,836,976          6,645,480
Other Assets                              91,639             279,139
                                          $   6,737,527   $   7,902,897
LIABILITIES AND EQUITY
Current Liabilities                       $     767,771  $     884,913
Long-Term Debt                            1,668,273          1,342,100
Deferred Income Taxes                     1,049,138          1,586,798
Long-Term Hedging Liability               —                  55
Other Liabilities                         216,473            119,727
Commitments and Contingencies
Equity
Common stock, $.01 par value; authorized
1,250,000,000 shares in 2012 and 2011,    3,511              3,491
issued 351,100,391 shares in 2012 and
349,058,501 in 2011
Additional paid-in capital                934,939            903,399
Retained earnings                         1,949,150          2,656,214
Accumulated other comprehensive income    149,804            408,428
Common stock in treasury, 64,715 shares   (1,532)            (2,228)
in 2012 and 98,889 in 2011
Total equity                              3,035,872          3,969,304
                                          $  6,737,527      $   7,902,897

STATEMENTS OF CASH FLOWS (Unaudited)
Southwestern Energy Company and
Subsidiaries
                                        Twelve Months
Periods Ended December 31               2012                2011
                                        (in thousands)
Cash Flows From Operating Activities
Net income (loss)                       $    (707,064)   $     637,769
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depreciation, depletion and             814,710             707,966
amortization
Impairment of natural gas and oil       1,939,734           —
properties
Deferred income taxes                   (461,828)           409,023
Unrealized (gain) loss on derivatives   (272)               (281)
Stock-based compensation expense        11,795              10,550
Other                                   1,806               991
Change in assets and liabilities        55,061              (26,201)
Net cash provided by operating          1,653,942           1,739,817
activities
Cash Flows From Investing Activities
Capital investments                     (2,107,755)         (2,184,474)
Proceeds from sale of property and      201,101             154,526
equipment
Transfers to restricted cash            (167,788)           (85,055)
Transfers from restricted cash          159,246             85,055
Other items                             8,519               5,158
Net cash used in investing activities   (1,906,677)         (2,024,790)
Cash Flows From Financing Activities
Payments on short-term debt             (1,200)             (1,200)
Payments on revolving long-term debt    (2,263,900)         (3,445,900)
Borrowings under revolving long-term    1,592,400           3,696,200
debt
Debt issuance costs and revolving       (8,339)             (10,211)
credit facility costs
Excess tax benefit for stock-based      —                   14,626
compensation
Change in bank drafts outstanding       (35,608)            24,637
Proceeds from issuance of long-term     998,780             —
debt
Proceeds from exercise of common stock  9,184               6,412
options
Other                                   (428)               (261)
Net cash provided by financing          290,889             284,303
activities
Effect of exchange rate changes on cash (198)               242
Increase (decrease) in cash and cash    37,956              (428)
equivalents
Cash and cash equivalents at beginning  15,627              16,055
of year
Cash and cash equivalents at end of     $      53,583  $      15,627
year

SEGMENT INFORMATION
(Unaudited)
Southwestern Energy Company and Subsidiaries
                 Exploration
                 &             Midstream
                 Production    Services    Other     Eliminations  Total
                 (in thousands)
Quarter Ending
December 31,
2012
                 $           $         $      $            $  
Revenues         559,782       726,292            (513,389)    772,998
                                           313
Gas purchases    —             591,707     —         (423,182)     168,525
Operating        120,713       34,560      (69)      (89,947)      65,257
expenses
General &
administrative   37,452        8,012       64        (260)         45,268
expenses
Depreciation,
depletion &      193,434       11,896      231       —             205,561
amortization
Impairment of
natural gas and  849,261       —           —         —             849,261
oil properties
Taxes, other
than income      14,007        2,413       10        —             16,430
taxes
                               $        $      $        $
Operating Income $ (655,085)  77,704              —         (577,304)
                                           75
Capital          $           $        $      $        $  
Investments ^(1) 410,112       59,402     24,374     —         493,888
Quarter Ending
December 31,
2011
                 $           $         $      $            $  
Revenues         538,830       675,811            (471,358)    744,150
                                           867
Gas purchases    —             555,356     —         (391,783)     163,573
Operating        112,055       31,866      36        (78,776)      65,181
expenses
General &
administrative   38,173        7,642       70        (799)         45,086
expenses
Depreciation,
depletion &      179,995       10,091      245       —             190,331
amortization
Taxes, other
than income      12,767        3,302       20        —             16,089
taxes
                 $           $        $      $        $  
Operating Income 195,840       67,554                —       263,890
                                           496
Capital          $           $        $      $        $  
Investments ^(1) 612,059       22,778      15,399      —       650,236
Twelve Months
Ending December
31, 2012
Revenues         $ 1,948,222  $           $      $             $
                               2,363,480   2,865  (1,599,524)   2,715,043
Gas purchases    —             1,858,824   —         (1,266,358)   592,466
Operating        453,301       121,858     94        (330,518)     244,735
expenses
General &
administrative   145,056       32,494      245       (2,648)       175,147
expenses
Depreciation,
depletion &      765,368       44,395      1,190     —             810,953
amortization
Impairment of
natural gas and  1,939,734     —           —         —             1,939,734
oil properties
Taxes, other
than income      55,974        11,607      3         —             67,584
taxes
Operating Income $             $         $      $        $
                 (1,411,211)   294,302      1,333   —          (1,115,576)
Capital          $ 1,860,681  $         $      $        $
Investments ^(1)               164,978     54,860     —         2,080,519
Twelve Months
Ending December
31, 2011
Revenues         $ 2,100,488  $           $      $             $
                               2,859,519   3,268  (2,010,369)   2,952,906
Gas purchases    —             2,418,092   —         (1,709,001)   709,091
Operating        420,720       118,344     89        (298,209)     240,944
expenses
General &
administrative   134,840       26,091      269       (3,159)       158,041
expenses
Depreciation,
depletion &      666,125       37,261      1,125     —             704,511
amortization
Taxes, other
than income      53,665        11,779      74        —             65,518
taxes
Operating Income $           $         $      $        $
(Loss)           825,138       247,952      1,711    —         1,074,801
Capital          $ 1,977,493  $         $      $        $
Investments ^(1)               160,776     68,905     —         2,207,174

    Capital investments include an increase of $3.8 million and an increase of
    $7.3 million for the three-month periods ended December 31, 2012 and 2011,
(1) respectively, and a decrease of $36.9 million and an increase of $4.3
    million for the twelve-month periods ended December 31, 2012 and 2011,
    respectively, relating to the change in accrued expenditures between
    periods.





SOURCE Southwestern Energy Company

Website: http://www.swn.com
Contact: R. Craig Owen, Senior Vice President and Chief Financial Officer,
+1-281-618-2808, or Brad D. Sylvester, CFA, Vice President, Investor
Relations, +1-281-618-4897
 
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