Southwestern Energy Announces Third Quarter 2013 Financial And Operating Results

HOUSTON, Oct. 31, 2013 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the three months ended September 30, 2013. Highlights include:

  • Record gas and oil production of 172.4 Bcfe, up 19% compared to year-ago levels
  • 2013 production guidance raised to 653 to 655 Bcfe, up from 643 to 651 previously
  • Adjusted net income of $179.8 million, up 36% compared to year-ago levels when excluding unrealized net gains and losses on derivative contracts and non-cash ceiling test impairments of natural gas and oil properties (a non-GAAP measure reconciled below)
  • Record net cash provided by operating activities before changes in operating assets and liabilities of approximately $526.7 million, up 26% compared to year-ago levels (a non-GAAP measure reconciled below)
  • Marcellus Shale production up 196% compared to year-ago levels; gross operated production surpasses 600 MMcf per day; additional firm transportation capacity secured currently totals over 1 Bcf per day by year-end 2015
  • Record well initial production rate of 10 MMcf per day in the Fayetteville Shale
  • Vertical well in Lower Smackover Brown Dense exploration program produces 600 barrels of oil per day

"We had a very good third quarter, fueled by our record production, which resulted in the highest quarterly cash flow ever for Southwestern Energy," remarked Steve Mueller, President and Chief Executive Officer of Southwestern Energy. "Our production growth from the Marcellus Shale was outstanding, as gross production reached a new milestone of 600 MMcf of gas per day and net production was up 32% sequentially. In addition, we continue to improve our completion techniques and flowback procedures in the Fayetteville Shale which have also resulted in new milestones, the greatest of which is surpassing the 3 Tcf cumulative gross operated production milestone on September 16, which is almost exactly 9 years to the day we commenced first production from the Fayetteville in 2004. Finally, in our Lower Smackover Brown Dense project we drilled our best well to date which reached a peak rate of 600 barrels of oil per day and 1.3 MMcf of gas per day, or over 800 barrels of oil equivalent per day. We will be drilling and completing three additional vertical wells in 2013 to test more of this project. We believe our curiosity and innovation will keep driving us higher up the learning curve as we work to unlock more value from these resource plays." 

Third Quarter of 2013 Financial Results

For the third quarter of 2013, Southwestern reported net income of $185.9 million, or $0.53 per diluted share, compared to a net loss of $54.1 million, or $0.16 per diluted share in the third quarter of 2012. Net income also included a non-cash unrealized net gain of $10.1 million ($6.1 million net of taxes) on derivative contracts associated with the company's hedging program. Excluding this non-cash item, Southwestern reported adjusted net income for the third quarter of 2013 of $179.8 million (reconciled below), or $0.51 per diluted share. The net loss for the three months ended September 30, 2012 included a $289.8 million non-cash ceiling test impairment ($185.7 million net of taxes) of the company's natural gas and oil properties resulting from lower natural gas prices and a non-cash unrealized net loss of $1.1 million ($0.7 million net of taxes) on derivative contracts associated with the company's hedging program. Excluding the non-cash impairment and unrealized loss, Southwestern reported adjusted net income for the third quarter of 2012 of $132.3 million, or $0.38 per diluted share.

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was a record $526.7 million for the third quarter of 2013, up 26% compared to $416.6 million for the same period in 2012.

E&P Segment – Operating income from the company's E&P segment was $222.7 million for the three months ended September 30, 2013, compared to $148.0 million for the three months ended September 30, 2012 (reconciled below). The increase was primarily due to higher production volumes and higher realized natural gas prices, partially offset by higher operating costs and expenses due to increased activity levels.

Gas and oil production totaled 172.4 Bcfe in the third quarter of 2013, up 19% from 144.3 Bcfe in the third quarter of 2012, and included 122.7 Bcf from the company's Fayetteville Shale play, compared to 123.6 Bcf in the third quarter of 2012. Production from the Marcellus Shale was 44.7 Bcf in the third quarter of 2013, compared to 15.1 Bcf in the third quarter of 2012. The company currently expects its total gas and oil production for 2013 to range between of 653 to 655 Bcfe, an increase of approximately 16% over the company's 2012 gas and oil production (using midpoints). The company's production guidance for the remainder of 2013 is as follows:


1st Quarter Actual

2nd Quarter Actual

3rd Quarter Actual

4th Quarter Estimate

Full-Year 2013 Estimate







Previous Guidance (Bcfe)

147.8

160.1

164 - 168

171 - 175

643 - 651

New Guidance (Bcfe)

147.8

160.1

172.4

173 - 175

653 - 655

Southwestern's average realized gas price in the third quarter of 2013 was $3.60 per Mcf, up from $3.41 per Mcf in the third quarter of 2012. The company's commodity hedging activities increased its average gas price by $0.54 per Mcf during the third quarter of 2013, compared to an increase of $1.06 per Mcf during the same period in 2012. As of October 31, 2013, the company had approximately 84 Bcf of its remaining 2013 expected gas production hedged at an average price of $4.68 per Mcf and approximately 233 Bcf of its 2014 forecasted gas production hedged at an average price of $4.41 per Mcf. As of September 30, 2013, the company had protected approximately 74 Bcf of its remaining 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 ($0.06) 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 third quarter of 2013 was approximately $0.52 per Mcf lower than average NYMEX settlement prices, compared to approximately $0.46 per Mcf lower during the third quarter of 2012. For the fourth quarter of 2013, the company expects its total natural gas sales discount to NYMEX to be approximately $0.55 per Mcf.

Lease operating expenses per unit of production for the company's E&P segment were $0.87 per Mcfe in the third quarter of 2013, compared to $0.79 per Mcfe in the third quarter of 2012. The increase was primarily due to increased third-party compression and gathering costs in the Marcellus Shale and higher activity levels, offset slightly by a decrease in salt water disposal costs in the Fayetteville Shale.

General and administrative expenses per unit of production were $0.24 per Mcfe in the third quarter of 2013, compared to $0.21 per Mcfe in the third quarter of 2012. The increase was primarily due to higher personnel costs.

Taxes other than income taxes per unit of production were $0.09 per Mcfe in both of the third quarters of 2013 and 2012. 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 $1.07 per Mcfe in the third quarter of 2013, compared to $1.30 per Mcfe in the third quarter of 2012. 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 $86.7 million for the three months ended September 30, 2013, up 15% from $75.5 million in the same period in 2012. The increase in operating income was primarily due to the increase in gathering activity from the company's Fayetteville and Marcellus Shale properties from higher gathered volumes, partially offset by increased operating costs and expenses from higher activity. At September 30, 2013, the company's midstream segment was gathering approximately 2.3 Bcf per day through 1,920 miles of gathering lines in the Fayetteville Shale and approximately 344 MMcf per day from 89 miles of gathering lines in the Marcellus Shale. 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.

First Nine Months of 2013 Financial Results

For the first nine months of 2013, Southwestern reported net income of $559.0 million, or $1.59 per diluted share, compared to a net loss of $351.5 million, or $1.01 per diluted share, for the first nine months of 2012. Net income for the first nine months of 2013 included non-cash unrealized net gains of $72.7 million ($43.6 million net of taxes) on derivative contracts associated with the company's hedging program. Excluding this non-cash item, Southwestern reported adjusted net income for the first nine months of 2013 of $515.5 million (reconciled below), or $1.47 per diluted share. For the first nine months of 2012, the company reported adjusted net income of $330.0 million (reconciled below), or $0.95 per diluted share, excluding non-cash ceiling test impairments and non-cash unrealized net losses on derivative contracts associated with the company's hedging program.

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $1.4 billion for the first nine months of 2013, up 27% from $1.1 billion for the same period in 2012.

E&P Segment – Operating income from the company's E&P segment (reconciled below) was $651.0 million for the nine months ended September 30, 2013, compared to $344.9 million for the same period in 2012. The increase was primarily due to higher production volumes and higher realized natural gas prices, partially offset by higher operating costs and expenses due to increased activity levels.

Gas and oil production was 480.3 Bcfe in the first nine months of 2013, up 16% compared to 415.1 Bcfe in the first nine months of 2012, and included 362.8 Bcf from the company's Fayetteville Shale play, up from 360.4 Bcf in the first nine months of 2012. Production from the Marcellus Shale was 102.1 Bcf in the first nine months of 2013, compared to 34.3 Bcf in the first nine months of 2012.

Southwestern's average realized gas price was $3.63 per Mcf in the first nine months of 2013, including the effect of hedges, compared to $3.33 per Mcf in the first nine months of 2012. The company's hedging activities increased the average gas price realized during the first nine months of 2013 by $0.45 per Mcf, compared to an increase of $1.21 per Mcf during the first nine months of 2012. Disregarding the impact of hedges, the average price received for the company's gas production during the first nine months of 2013 and 2012 was approximately $0.49 per Mcf and $0.47 per Mcf lower than average monthly NYMEX settlement prices, respectively.

Lease operating expenses for the company's E&P segment were $0.85 per Mcfe in the first nine months of 2013, compared to $0.80 per Mcfe in the first nine months of 2012. The increase was primarily due to an increase in third-party gathering costs in the Marcellus Shale and higher activity levels, offset slightly by a decrease in salt water disposal costs in the Fayetteville Shale.

General and administrative expenses were $0.23 per Mcfe in the first nine months of 2013, compared to $0.26 per Mcfe in the first nine months of 2012. The decrease was primarily due to lower personnel costs.

Taxes other than income taxes were $0.10 per Mcfe during both the first nine months of 2013 and 2012. 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 production volumes and fluctuations in commodity prices.

The company's full cost pool amortization rate decreased to $1.07 per Mcfe in the first nine months of 2013, compared to $1.34 per Mcfe in the first nine months of 2012.

Midstream Services - Operating income for the company's midstream activities was $235.9 million in the first nine months of 2013, up 9% compared to $216.6 million in the first nine months of 2012. The increase in operating income was primarily due to increased gathering activity related to the company's Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses.

Capital Structure and Investments – At September 30, 2013, the company had approximately $1.9 billion in long-term debt and its long-term debt-to-total capitalization ratio was 35%, compared to 35% at December 31, 2012. The company had approximately $243 million borrowed on its revolving credit facility and also had cash and cash equivalents of approximately $19 million at September 30, 2013.

For the first nine months of 2013, Southwestern invested a total of approximately $1.8 billion, compared to $1.6 billion during the first nine months of 2012. The company's capital investments in 2013 included $1.6 billion invested in its E&P business and $135 million invested in its Midstream Services activities.

E&P Operations Review

Southwestern invested approximately $1.6 billion in its E&P business during the first nine months of 2013, of which approximately $735 million was invested in the Marcellus Shale, $678 million in the Fayetteville Shale, $133 million in New Ventures, $52 million in E&P Services and $5 million in Ark-La-Tex.

Marcellus Shale – At September 30, 2013, Southwestern had 151 operated horizontal wells on production and 80 wells in progress in the Marcellus Shale, resulting in net production of 44.7 Bcf in the third quarter of 2013, up 196% compared to 15.1 Bcf in the third quarter of 2012. Gross production from the company's operated wells in the Marcellus Shale was approximately 611 MMcf per day at September 30, 2013.

Of the 151 operated horizontal wells on production at September 30, 2013, 82 were located in Bradford County, 8 were located in Lycoming County and 61 were located in Susquehanna County. Of the 80 wells in progress at September 30, 2013, 38 were either waiting on completion or waiting to be placed to sales, including 3 in Bradford County, 8 in Lycoming County and 27 in Susquehanna County. A graph of the company's gross operated production by county is shown below:

(Photo: http://photos.prnewswire.com/prnh/20131031/DA08275-a)

In the fourth quarter of 2013, the company expects to drill its first well in Sullivan County on a portion of the undeveloped acreage it purchased in May of 2013. The company's first wells in Wyoming and Tioga Counties are currently scheduled early in 2014.

Results from the company's drilling activities from 2010 by quarter are shown below.

Time Frame

30th-Day Avg Rate

(# of wells)

Average Completed

Lateral Length

Average

RE-RE

(Rig Days)

Average Completed

Well Cost

($MM)

3rd Qtr 2010

1,405 (1)

2,927

22.6

$5.8

4th Qtr 2010

5,584 (6)

3,805

19.8

$7.1

1st Qtr 2011

5,052 (3)

3,864

18.1

$6.6

2nd Qtr 2011

6,114 (7)

4,780

13.4

$6.7

4th Qtr 2011

5,284 (5)

4,129

18.8

$6.0

1st Qtr 2012

7,327 (2)

4,009

13.2

$6.0

2nd Qtr 2012

3,859 (17)

3,934

12.9

$6.0

3rd Qtr 2012

4,493 (8)

4,380

13.2

$5.7

4th Qtr 2012

4,606 (22)

3,830

15.9

$7.0

1st Qtr 2013

5,356 (21)

4,712

11.0

$7.0

2nd Qtr 2013

5,530 (37)

4,654

11.6

$6.6

3rd Qtr 2013

4,540 (15)

5,404

11.5

$7.3

The graph below provides normalized average daily production data through September 30, 2013, for the company's horizontal wells in the Marcellus Shale. The "pink curve" indicates results for 32 wells with more than 18 fracture stimulation stages, the "purple curve" indicates results for 66 wells with 13 to 18 fracture stimulation stages, the "orange curve" indicates results for 49 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, 8, 12 and 16 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/20131031/DA08275-b)

In October, Southwestern secured additional firm transportation capacity, subject to completing a new interconnect project, beginning in November 2014 for up to an additional 150,000 MMBtu per day. This agreement increases the company's total contracted firm transportation capacity for its Marcellus Shale gas to up to approximately 870 MMcf per day by year-end 2014 and over 1 Bcf per day by year-end of 2015.

Fayetteville Shale – For the third quarter of 2013, Southwestern placed a total of 89 operated horizontal wells on production in the Fayetteville Shale. At September 30, 2013, the company's gross operated production rate was approximately 2,030 MMcf per day.

During the third quarter of 2013, the company's horizontal wells had an average horizontal lateral length of 5,490 feet and average time to drill to total depth of 6.5 days from re-entry to re-entry for an average completed well cost of $2.6 million per well. This compares to an average horizontal lateral length of 5,165 feet and average time to drill to total depth of 6.2 days from re-entry to re-entry for an average completed well cost of $2.3 million per well in the second quarter of 2013. In the third quarter of 2013, the company had 33 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 385 wells drilled to total depth of 5 days or less from re-entry to re-entry.

In the third quarter of 2013, Southwestern placed on production its two highest-rate wells since the inception of the play. The company's Sneed 08-12 6-1H7 well located in Faulkner County and the Ledbetter 07-16 12-14H well located in Conway County achieved peak 24-hour production rates of 10,084 and 9,148 Mcf per day, respectively. In the third quarter, Southwestern placed a total of 19 wells on line that achieved peak 24-hour production rates in excess of 6,000 Mcf per day. Additionally, in October, Southwestern has placed another 6 wells on line with peak 24-hour production rates above 6,000 Mcf per day, including 2 wells which are producing from the Upper Fayetteville formation. In total, the company's wells placed on production during the third quarter of 2013 averaged initial production rates of 4,979 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)

2,447(105)

4,974

4th Qtr 2012

111

3,962

2,815 (111)

2,405 (111)

4,784

1st Qtr 2013

102

3,301

2,366 (102)

2,069 (102)

4,942

2nd Qtr 2013

126

3,625

2,233 (126)

1,980 (125)

5,165

3rd Qtr 2013

89

4,979

2,493 (61)

2,146 (31)

5,490



Note:

Results as of September 30, 2013. 

(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.

Ark-La-Tex Total net production from the company's East Texas and conventional Arkoma Basin assets was 14.1 Bcfe in the first nine months of 2013, compared to 20.3 Bcfe in the first nine months of 2012. The decline in production is primarily due to the sale of a portion of the company's East Texas properties in 2012.

New Ventures – In the Lower Smackover Brown Dense project located in southern Arkansas and northern Louisiana, the company has drilled ten operated wells in the play area to date, five of which are currently testing or producing, one is waiting on completion and one is drilling. The most recent well placed on production was the company's Sharp 22-22-1 #1 vertical well in Union Parish, Louisiana, which was drilled to a total vertical depth of 9,776 feet and was completed with 3 stages. The company is encouraged by initial flow rates from this well which achieved a peak 24-hour production rate of approximately 600 barrels of condensate and 1.3 MMcf of 1,240-Btu gas per day. After 88 days, the well is currently producing approximately 530 barrels of oil and 1.1 million cubic feet of gas per day on a 16/64-inch choke. The company's Hollis 27-22-3 #1 vertical well in Union Parish was drilled to a total vertical depth of 11,429 feet and was completed with 3 stages and has recently begun flowback. The company drilled the Dean 31-22-2H Alt horizontal well in Union Parish in April to a total vertical depth of 10,055 feet with a lateral length of 3,172 feet. Additional testing in this well is planned in the second quarter of 2014. The company's McMahen 19-21 #1-7 vertical well in Columbia County, Arkansas, was recently drilled to a total vertical depth of 11,365 feet and is expected to be completed with 3 to 4 stages in November. Southwestern has also spud another vertical well, the Plum Creek 13-23-2 #1V, in Union Parish, Louisiana in late-October.

In the Denver-Julesburg Basin in eastern Colorado, the company's Staner 5-58 #1-8 horizontal well located in Arapahoe County was completed with 14 successful stages and began flowing back in late July. The well achieved a peak 24-hour production rate of 146 barrels of oil per day and 59 Mcf of gas per day. The company plans to continue to test the concept with additional wells in the area in the first quarter of 2014.

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 nine months ended September 30, 2013 and September 30, 2012. 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 September 30,


2013


2012


(in thousands)

Net income (loss):




Net income (loss)

$     185,867


$       (54,053)

Deduct (add back):




Impairment of natural gas and oil properties (net of taxes)

--


(185,669)

Unrealized gain (loss) on derivative contracts (net of taxes)

6,059


(701)

Adjusted net income 

$     179,808


$     132,317




9 Months Ended September 30,


2013


2012


(in thousands)

Net income (loss):




Net income (loss)

$     559,013


$    (351,481)

Deduct (add back):




Impairment of natural gas and oil properties (net of taxes)

--


(682,039)

Unrealized gain on derivative contracts (net of taxes)

43,562


558

Adjusted net income 

$     515,451


$     330,000




3 Months Ended September 30,


2013


2012



Diluted earnings per share:




Net income (loss) per share

$               0.53


$              (0.16)

Deduct (add back):




Impairment of natural gas and oil properties (net of taxes)

--


(0.53)

Unrealized gain (loss) on derivative contracts (net of taxes)

0.02


(0.01)

Adjusted net income per share

$               0.51


$             0.38




9 Months Ended September 30,


2013


2012



Diluted earnings per share:




Net income (loss) per share

$               1.59


$              (1.01)

Deduct (add back):




Impairment of natural gas and oil properties (net of taxes)

--


(1.96)

Unrealized gain on derivative contracts (net of taxes)

0.12


--

Adjusted net income per share

$               1.47


$               0.95




3 Months Ended September 30,


2013


2012


(in thousands)

Cash flow from operating activities:




Net cash provided by operating activities

$     499,966


$     355,087

Deduct (add back):




Change in operating assets and liabilities

(26,691)


(61,523)

Net cash provided by operating activities before changes

  in operating assets and liabilities

$     526,657


$     416,610




9 Months Ended September 30,


2013


2012


(in thousands)

Cash flow from operating activities:




Net cash provided by operating activities

$  1,377,518


$  1,192,477

Deduct (add back):




Change in operating assets and liabilities

(68,028)


50,520

Net cash provided by operating activities before changes

  in operating assets and liabilities

$  1,445,546


$  1,141,957




3 Months Ended September 30,


2013


2012


(in thousands)

E&P segment operating income:




E&P segment operating income (loss)

$     222,692


$    (141,865)

Deduct (add back):




Impairment of natural gas and oil properties

--


(289,821)

E&P segment operating income excluding impairment

  of natural gas and oil properties 

$     222,692


$     147,956




9 Months Ended September 30,


2013


2012


(in thousands)

E&P segment operating income:




E&P segment operating income (loss)

$     650,996


$    (745,533)

Deduct (add back):




Impairment of natural gas and oil properties

--


(1,090,473)

E&P segment operating income excluding impairment

  of natural gas and oil properties 

$     650,996


$     344,940

Southwestern management will host a teleconference call on Friday, November 1, 2013 at 10:00 a.m. EDT to discuss its third quarter 2013 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


Nine Months

Periods Ended September 30,


2013


2012


2013


2012














Exploration & Production













Production













Gas Production ( Bcf)



172.1



144.2



479.4



414.7

Oil Production (MBbls)



37



19



102



59

NGL production (MBbls)



12





40



Total equivalent production (Bcfe)



172.4



144.3



480.3



415.1














Commodity Prices













Average realized gas price per Mcf, including hedges


$

3.60


$

3.41


$

3.63


$

3.33

Average realized gas price per Mcf, excluding hedges


$

3.06


$

2.35


$

3.18


$

2.12

Average oil price per Bbl


$

106.72


$

99.67


$

105.05


$

102.89

Average NGL price per Bbl


$

42.05


$


$

44.20


$














Operating Expenses per Mcfe













Lease operating expenses


$

0.87


$

0.79


$

0.85


$

0.80

General & administrative expenses


$

0.24


$

0.21


$

0.23


$

0.26

Taxes, other than income taxes


$

0.09


$

0.09


$

0.10


$

0.10

Full cost pool amortization


$

1.07


$

1.30


$

1.07


$

1.34



























Midstream













Gas volumes marketed (Bcf)



206.4



171.2



574.9



498.7

Gas volumes gathered (Bcf)



229.9



214.7



667.3



622.9



























STATEMENTS OF OPERATIONS (Unaudited)


Southwestern Energy Company and Subsidiaries








Three Months


Nine Months

Periods Ended September 30,


2013


2012


2013


2012




(in thousands, except share/per amounts)

Operating Revenues













Gas sales


$

617,427


$

497,219


$

1,736,101


$

1,394,745

Gas marketing



201,112



148,764



581,932



423,503

Oil sales



4,397



1,889



12,431



6,097

Gas gathering



45,430



43,855



133,592



128,293




868,366



691,727



2,464,056



1,952,638

Operating Costs and Expenses













Gas purchases - midstream services



195,271



149,651



575,337



423,941

Operating expenses



90,269



61,906



236,648



179,478

General and administrative expenses



50,969



36,121



135,754



129,879

Depreciation, depletion and amortization



204,934



203,935



571,268



605,392

Impairment of natural gas and oil properties





289,821





1,090,473

Taxes, other than income taxes



17,694



16,252



58,543



51,154




559,137



757,686



1,577,550



2,480,317

Operating Income (Loss)



309,229



(65,959)



886,506



(527,679)

Interest Expense













Interest on debt



25,435



25,463



74,581



69,154

Other interest charges



1,049



1,058



3,203



3,096

Interest capitalized



(15,466)



(15,915)



(48,467)



(45,945)




11,018



10,606



29,317



26,305

Other Gain (Loss), Net



(319)



238



(498)



2,615

Gain (Loss) on Derivatives



12,124



(5,879)



75,779



(10,593)

Income (Loss) Before Income Taxes



310,016



(82,206)



932,470



(561,962)

Provision for Income Taxes













Current



(16,068)



101



402



369

Deferred



140,217



(28,254)



373,055



(210,850)




124,149



(28,153)



373,457



(210,481)

Net Income (Loss)


$

185,867


$

(54,053)


$

559,013


$

(351,481)

Earnings (Loss) Per Share













Basic


$

0.53


$

(0.16)


$

1.60


$

(1.01)

Diluted


$

0.53


$

(0.16)


$

1.59


$

(1.01)

Weighted Average Common Shares Outstanding

Basic



350,517,337



348,649,630



350,334,634



348,272,192

Diluted



351,222,830



348,649,630



351,014,974



348,272,192

  








BALANCE SHEETS (Unaudited)


Southwestern Energy Company and Subsidiaries













September 30,


2013


2012


(in thousands)

ASSETS














Current Assets


$

739,975


$

846,747

Property and Equipment



14,823,553



12,506,903

Less: Accumulated depreciation, depletion and amortization



(7,786,820)



(6,131,344)




7,036,733



6,375,559

Other Long-Term Assets



117,680



134,256




7,894,388



7,356,562








LIABILITIES AND EQUITY














Current Liabilities



809,811



761,165

Long-Term Debt



1,911,165



1,695,342

Deferred Income Taxes



1,388,833



1,313,584

Other Long-Term Liabilities



264,590



159,462

Commitments and Contingencies







Equity







Common stock, $0.01 par value; authorized 1,250,000,000
shares; issued 351,768,352 shares in 2013 and 351,415,917 in
2012



3,517



3,504

Additional paid-in capital



960,058



928,322

Retained earnings



2,508,163



2,304,733

Accumulated other comprehensive income



48,758



192,040

Common stock in treasury; 14,625 shares in 2013
and 66,791 in 2012



(507)



(1,590)

Total Equity



3,519,989



3,427,009



$

7,894,388


$

7,356,562

 








STATEMENTS OF CASH FLOWS (Unaudited)


Southwestern Energy Company and Subsidiaries








Nine Months

Periods Ended September 30,


2013


2012


(in thousands)

Cash Flows From Operating Activities







Net Income (loss)


$

559,013


$

(351,481)

Adjustment to reconcile net income to net cash provided by operating
activities:







Depreciation, depletion and amortization



574,221



608,167

Impairment of natural gas and oil properties





1,090,473

Deferred income taxes



373,055



(210,850)

Mark to market gain on derivatives



(72,664)



(892)

Stock-based compensation



8,883



8,226

Other



3,038



(1,686)

Change in assets and liabilities



(68,028)



50,520

Net cash provided by operating activities



1,377,518



1,192,477








Cash Flows From Investing Activities







Capital investments



(1,727,543)



(1,623,751)

Proceeds from sale of property and equipment



3,081



201,161

Transfers to restricted cash





(167,774)

Transfers from restricted cash



8,542



40,700

Other



4,700



5,239

Net cash used in investing activities



(1,711,220)



(1,544,425)








Cash Flows From Financing Activities







Payments on current portions of long-term debt



(600)



(600)

Payments on revolving long-term debt



(2,134,550)



(1,774,000)

Borrowings under revolving long-term debt



2,377,950



1,129,000

Change in bank drafts outstanding



49,106



1,627

Proceeds from issuance of long term debt





998,780

Debt Issuance costs





(8,338)

Proceeds from exercise of common stock options



6,751



8,422

Net cash provided by financing activities



298,657



354,891








Effect of exchange rate changes on cash



412



(10)

Increase (decrease) in cash and cash equivalents



(34,633)



2,933

Cash and cash equivalents at beginning of year



53,583



15,627

Cash and cash equivalents at end of period


$

18,950


$

18,560


















SEGMENT INFORMATION (Unaudited)


Southwestern Energy Company and Subsidiaries


Exploration














and


Midstream












Production


Services


Other


Eliminations


Total


(in thousands)

Quarter Ending September 30, 2013
















Revenues


$

622,477


$

847,605


$

96


$

(601,812)


$

868,366

Gas purchases





701,304





(506,033)



195,271

Operating expenses



150,602



35,395



30



(95,758)



90,269

General & administrative expenses



42,013



8,937



40



(21)



50,969

Depreciation, depletion & amortization



191,860



12,970



104





204,934

Taxes, other than income taxes



15,310



2,341



43





17,694

Operating income



222,692



86,658



(121)





309,229

















Capital investments(1)



496,331



40,052



5,726





542,109

































Quarter Ending September 30, 2012
















Revenues


$

498,101


$

602,339


$

849


$

(409,562)


$

691,727

Gas purchases





474,628





(324,977)



149,651

Operating expenses



113,416



32,221



56



(83,787)



61,906

General & administrative expenses



30,256



6,615



48



(798)



36,121

Depreciation, depletion & amortization



192,994



10,620



321





203,935

Impairment of natural gas and oil properties



289,821









289,821

Taxes, other than income taxes



13,479



2,767



6





16,252

Operating income (loss)



(141,865)



75,488



418





(65,959)

















Capital investments(1)



385,585



31,693



7,608





424,886

































Nine months Ending September 30, 2013
















Revenues


$

1,752,638


$

2,455,287


$

257


$

(1,744,126)


$

2,464,056

Gas purchases





2,042,948





(1,467,611)



575,337

Operating expenses



406,586



106,415



104



(276,457)



236,648

General & administrative expenses



111,605



24,120



87



(58)



135,754

Depreciation, depletion & amortization



533,577



37,377



314





571,268

Taxes, other than income taxes



49,874



8,573



96





58,543

Operating income



650,996



235,854



(344)





886,506

















Capital investments(1)



1,602,885



135,425



16,748





1,755,058

































Nine months Ending September 30, 2012
















Revenues


$

1,399,033


$

1,637,188


$

2,552


$

(1,086,135)


$

1,952,638

Gas purchases





1,267,117





(843,176)



423,941

Operating expenses



332,588



87,298



163



(240,571)



179,478

General & administrative expenses



107,604



24,482



181



(2,388)



129,879

Depreciation, depletion & amortization



571,935



32,499



958





605,392

Impairment of natural gas and oil properties



1,090,473









1,090,473

Taxes, other than income taxes



41,966



9,194



(6)





51,154

Operating income (loss)



(745,533)



216,598



1,256





(527,679)

















Capital investments(1)



1,450,569



105,576



30,486





1,586,631

















(1) Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increases of $25.8 million and a decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.

 

SOURCE Southwestern Energy Company



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