Home Page
00:01:15 EDT Wed 01 Oct 2014
Enter Symbol
or Name
USA
CA



SOUTHWESTERN ENERGY CO
Symbol U : SWN
Recent Sedar Documents

Southwestern Energy Announces 2012 Financial And Operating Results

2013-02-20 17:15 ET - News Release

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:

  • Gas and oil production of 565 Bcfe, up 13% over 2011
  • Adjusted 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)
  • Net 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 unrealized loss 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 (MBbls)

Total (Bcfe)

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 Additions

918.6

154

919.5

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 December 31, 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 December 31, 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 Play


Texas


Basin


Ventures


Total

Estimated Proved Reserves:


















Natural Gas (Bcf):


















Developed (Bcf)


2,624



374



51



146



1



3,196

Undeveloped (Bcf)


364



442



1



14





821



2,988



816



52



160



1



4,017

Crude Oil (MMBbls):


















Developed (MMBbls)






0.1





0.1



0.2

Undeveloped (MMBbls)


















0.1





0.1



0.2

Total Proved Reserves (Bcfe)(1):


















Proved Developed (Bcfe)


2,624



374



52



146



1



3,197

Proved Undeveloped (Bcfe)


364



442



1



14





821



2,988



816



53



160



1



4,018

Percent of Total


75%



20%



1%



4%





100%



















Percent Proved Developed


88%



46%



97%



91%



100%



80%

Percent Proved Undeveloped


12%



54%



3%



9%





20%



















Production (Bcfe)


486



54



11



14





565

Capital Investments (millions)(2)

$

991


$

507


$

5


$

6


$

337


$

1,846

Total Gross Producing Wells(3)


3,228



132



173



1,180



4



4,717

Total Net Producing Wells(3)


2,186



71



110



570



4



2,941



















Total Net Acreage


788,849

(4)


176,298

(5)


49,340

(6)


238,940

(7)


3,822,344

(8)


5,075,771

Net Undeveloped Acreage


308,924

(4)


159,078

(5)


1,874

(6)


63,341

(7)


3,819,128

(8)


4,352,345



















PV-10:


















Pre-tax (millions)(9)

$

1,693


$

483


$

30


$

112


$

6


$

2,324

PV of taxes (millions)(9)


199



57



3



14





273

After-tax (millions)(9)

$

1,494


$

426


$

27


$

98


$

6


$

2,051

Percent of Total


73%



21%



1%



5%





100%

Percent Operated(10)


97%



99%



97%



89%



100%



97%



(1)

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 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.



(2)

The company's Total and Fayetteville Shale play capital investments 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.



(4)

Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years 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.



(5)

Assuming successful wells are not drilled to develop the acreage and 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.



(6)

Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,340 net acres in 2013, 152 net acres in 2014 and 202 net acres in 2015.



(7)

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 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.



(8)

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 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.



(9)

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 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.

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

1st Qtr 2007

58

1,261

1,066 (58)

958 (58)

2,104

2nd Qtr 2007

46

1,497

1,254 (46)

1,034 (46)

2,512

3rd Qtr 2007

74

1,769

1,510 (72)

1,334 (72)

2,622

4th Qtr 2007

77

2,027

1,690 (77)

1,481 (77)

3,193

1st Qtr 2008

75

2,343

2,147 (75)

1,943 (74)

3,301

2nd Qtr 2008

83

2,541

2,155 (83)

1,886 (83)

3,562

3rd Qtr 2008

97

2,882

2,560 (97)

2,349 (97)

3,736

4th Qtr 2008(1)

74

3,350(1)

2,722 (74)

2,386 (74)

3,850

1st Qtr 2009(1)

120

2,992(1)

2,537 (120)

2,293 (120)

3,874

2nd Qtr 2009

111

3,611

2,833 (111)

2,556 (111)

4,123

3rd Qtr 2009

93

3,604

2,624 (93)

2,255 (93)

4,100

4th Qtr 2009

122

3,727

2,674 (122)

2,360 (120)

4,303

1st Qtr 2010(2)

106

3,197(2)

2,388 (106)

2,123 (106)

4,348

2nd Qtr 2010

143

3,449

2,554 (143)

2,321 (142)

4,532

3rd Qtr 2010

145

3,281

2,448 (145)

2,202 (144)

4,503

4th Qtr 2010

159

3,472

2,678 (159)

2,294 (159)

4,667

1st Qtr 2011

137

3,231

2,604 (137)

2,238(137)

4,985

2nd Qtr 2011

149

3,014

2,328 (149)

1,991 (149)

4,839

3rd Qtr 2011

132

3,443

2,666 (132)

2,372 (132)

4,847

4th Qtr 2011

142

3,646

2,606 (142)

2,243 (142)

4,703

1st Qtr 2012

146

3,319

2,421 (146)

2,131 (146)

4,743

2nd Qtr 2012

131

3,500

2,515 (131)

2,225 (131)

4,840

3rd Qtr 2012

105

3,857

2,816 (105)

2,448(104)

4,974

4th Qtr 2012

111

3,962

2,834 (109)

2,497 (70)

4,784

Note: 

Results as of December 31, 2012. 

(1)

The significant increase in the average initial production rate for the 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. 

(2)

In the first quarter of 2010, the company's results were impacted by 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 (net of taxes)

510,372


--

Unrealized loss on derivative contracts (net of taxes)

1,610


--

Adjusted net income

$     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 (net of taxes)

1,192,412


--

Unrealized gain on derivative contracts (net of taxes)

(167)


--

Adjusted net income

$     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 properties (net of taxes)

1.46


--

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 properties (net of taxes)

3.42


--

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

  in operating assets and liabilities

$     456,924


$     453,678




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

  in operating assets and liabilities

$  1,598,881


$  1,766,018




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 Months


For the 12 Months


For the 3 Years



Fayetteville 


Fayetteville 


Ending


Ending


Ending



Shale Play


Shale Play


December 31, 2012


December 31, 2011


December 31, 2012



2012


2011












Total exploration, development and acquisition costs incurred ($ in thousands)

$                1,910,943


$                1,960,106


$                5,652,473



$   1,048,420


$   1,347,605

Reserve extensions, discoveries and acquisitions (MMcfe)

919,515


1,459,456


3,810,096



414,874


1,211,210

Finding & development costs, excluding revisions ($/Mcfe)

$                           2.08


$                           1.34


$                           1.48



$             2.53


$             1.11

Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe)

(1,168,732)


1,493,201


2,065,186



(1,631,154)


1,196,041

Finding & development costs, including revisions ($/Mcfe)

$                         (1.64)


$                           1.31


$                           2.74



$           (0.64)


$             1.13

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 (Bcf)

149.8


133.2


564.5


499.4

  Oil production (MBbls)

24


18


83


97

  Total equivalent production (Bcfe)

149.9


133.3


565.0


500.0

Commodity Prices








  Average gas price per Mcf, including

    hedges

$           3.72


$           4.04


$           3.44


$           4.19

  Average gas price per Mcf, excluding

    hedges

$           2.96


$           3.04


$           2.34


$           3.56

  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 December 31

2012


2011


2012


2011


(in thousands, except share/per share amounts)

Operating Revenues








Gas sales

$      557,209


$      535,560


$   1,941,361


$   2,079,725

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 – midstream services

168,525


163,573


592,466


709,091

Operating expenses

65,257


65,181


244,735


240,944

General and administrative expenses

45,268


45,086


175,147


158,041

Depreciation, depletion and amortization

205,561


190,331


810,953


704,511

Impairment of natural gas and oil properties

849,261



1,939,734


Taxes, other than income taxes

16,430


16,089


67,584


65,518


1,350,302


480,260


3,830,619


1,878,105

Operating Income (Loss)

(577,304)


263,890


(1,115,576)


1,074,801

Interest Expense








Interest on debt

24,142


17,041


93,296


65,421

Other interest charges

1,358


892


4,454


4,306

Interest capitalized

(16,148)


(13,121)


(62,093)


(45,652)


9,352


4,812


35,657


24,075

Other Income (Loss), Net

(1,585)


(57)


1,030


264

Income (Loss) Before Income Taxes

(588,241)


259,021


(1,150,203)


1,050,990

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 and amortization

7,191,463


4,415,339


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, issued 351,100,391 shares in 2012 and 349,058,501 in 2011

3,511


3,491

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 in 2012 and 98,889  in 2011

(1,532)


(2,228)

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 amortization

814,710


707,966

Impairment of natural gas and oil properties

1,939,734


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 activities

1,653,942


1,739,817





Cash Flows From Investing Activities




Capital investments

(2,107,755)


(2,184,474)

Proceeds from sale of property and equipment

201,101


154,526

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 debt

1,592,400


3,696,200

Debt issuance costs and revolving credit facility costs

(8,339)


(10,211)

Excess tax benefit for stock-based compensation


14,626

Change in bank drafts outstanding

(35,608)


24,637

Proceeds from issuance of long-term debt

998,780


Proceeds from exercise of common stock options

9,184


6,412

Other

(428)


(261)

Net cash provided by financing activities

290,889


284,303





Effect of exchange rate changes on cash

(198)


242

Increase (decrease) in cash and cash equivalents

37,956


(428)

Cash and cash equivalents at beginning of year

15,627


16,055

Cash and cash equivalents at end of year

$           53,583


$           15,627

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


$             313


$    (513,389)


$     772,998

Gas purchases


591,707



(423,182)


168,525

Operating expenses

120,713


34,560


(69)


(89,947)


65,257

General & administrative expenses

37,452


8,012


64


(260)


45,268

Depreciation, depletion & amortization

193,434


11,896


231



205,561

Impairment of natural gas and oil properties

849,261





849,261

Taxes, other than income taxes

14,007


2,413


10



16,430

Operating Income

$  (655,085)


$       77,704


$                75


$               —


$  (577,304)











Capital Investments (1)

$     410,112


$        59,402


$        24,374


$               —


$     493,888











Quarter Ending December 31, 2011




















Revenues

$     538,830


$     675,811


$             867


$    (471,358)


$     744,150

Gas purchases


555,356



(391,783)


163,573

Operating expenses

112,055


31,866


36


(78,776)


65,181

General & administrative expenses

38,173


7,642


70


(799)


45,086

Depreciation, depletion & amortization

179,995


10,091


245



190,331

Taxes, other than income taxes

12,767


3,302


20



16,089

Operating Income

$     195,840


$       67,554


$             496


$                 —


$     263,890











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 expenses

453,301


121,858


94


(330,518)


244,735

General & administrative expenses

145,056


32,494


245


(2,648)


175,147

Depreciation, depletion & amortization

765,368


44,395


1,190



810,953

Impairment of natural gas and oil properties

1,939,734





1,939,734

Taxes, other than income taxes

55,974


11,607


3



67,584

Operating Income

$ (1,411,211)


$     294,302


$          1,333


$              —


$ (1,115,576)











Capital Investments (1)

$  1,860,681


$     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 expenses

420,720


118,344


89


(298,209)


240,944

General & administrative expenses

134,840


26,091


269


(3,159)


158,041

Depreciation, depletion & amortization

666,125


37,261


1,125



704,511

Taxes, other than income taxes

53,665


11,779


74



65,518

Operating Income (Loss)

$     825,138


$     247,952


$          1,711


$               —


$  1,074,801











Capital Investments (1)

$  1,977,493


$     160,776


$        68,905


$               —


$  2,207,174











(1)

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, 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

© 2014 Canjex Publishing Ltd. All rights reserved.