Midstream Services – Operating income for the company’s Midstream Services segment, which is comprised of natural gas gathering and marketing activities, was $97 million for the third quarter of 2014, up 13%  from  $86 million for the same period in 2013.  Adjusted EBITDA for the segment was $111 million in the third quarter of 2014, up from $99 million in the same period in 2013 (a non-GAAP measure reconciled below). The growth in operating income and adjusted EBITDA was primarily due to increases in gas volumes gathered and marketing margins.

At September 30, 2014, the company’s midstream segment was gathering approximately 2.3 Bcf per day through 1,999 miles of gathering lines in the Fayetteville Shale and approximately 0.4 Bcf per day from 63 miles of owned gathering lines in the Marcellus Shale.

First Nine Months of 2014 Financial Results

For the first nine months of 2014, Southwestern reported adjusted net income of $616 million, or $1.75 per diluted share (reconciled below), when excluding a $7 million ($4 million net of taxes) loss on derivative contracts that have not been settled. For the first nine months of 2013, the company reported adjusted net income of $516 million, or $1.47 per diluted share (reconciled below),  when excluding a $72 million ($43 million net of taxes) gain on derivative contracts that have not been settled.

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $1.7  billion for the first nine months of 2014, up 18% from $1.4 billion for the same period in 2013. 

E&P Segment – Operating income from the company’s E&P segment was $817 million for the nine months ended September 30, 2014, compared to $651 million for the same period in 2013. The increase was primarily due to higher production volumes and higher realized natural gas prices, offset by increased operating costs and expenses primarily associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale and Marcellus Shale assets. 

Gas and oil production was 567 Bcfe in the first nine months of 2014, up 18% compared to 480 Bcfe in the first nine months of 2013, and included 369 Bcf from the Fayetteville Shale, up from 363 Bcf in the first nine months of 2013. Production from the Marcellus Shale was 185 Bcf in the first nine months of 2014,  an 81% increase from 102 Bcf in the first nine months of 2013. 

Southwestern’s average realized gas price was $3.79 per Mcf, including the effect of hedges, in the first nine months of 2014 compared to $3.64 per Mcf in the first nine months of 2013. The company’s hedging activities decreased the average gas price realized during the first nine months of 2014 by $0.12 per Mcf, compared to an increase of $0.46 per Mcf during the first nine months of 2013. Disregarding the impact of hedges, the average price received for the company’s gas production during the first nine months of 2014 was approximately $0.64 per Mcf lower than average monthly NYMEX settlement prices, compared to approximately $0.49 per Mcf during the first nine months of 2013.  

Lease operating expenses for the company’s E&P segment were $0.91 per Mcfe in the first nine months of 2014, compared to $0.85 per Mcfe in the first nine months of 2013.  The increase was primarily due to an increase in gathering costs in the Marcellus Shale and an increase in compression costs. 

General and administrative expenses were $0.24 per Mcfe in the first nine months of 2014, compared to $0.23 per Mcfe in the first nine months of 2013.  The increase was primarily due to higher personnel costs.

Taxes other than income taxes were $0.11 per Mcfe during the first nine months of 2014, compared to $0.10 per Mcfe in the first nine months of 2013. 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 increased to $1.10 per Mcfe in the first nine months of 2014, compared to $1.07 per Mcfe in the first nine months of 2013.

Midstream Services - Operating income for the company’s midstream activities was $272 million in the first nine months of 2014, up 16% compared to $235 million in the first nine months of 2013. Adjusted EBITDA for the segment was $315 million for the first nine months of 2014, up from $273 million in the same period in 2013 (a non-GAAP measure reconciled below). The increase in operating income and adjusted EBITDA was primarily due to increases in gas volumes gathered and marketing margins.  

During the first nine months of both 2014 and 2013, Southwestern invested a total of $1.8 billion.  The 2014 investments included approximately $1.7  billion invested in its E&P business, $109 million invested in its Midstream Services segment and $22 million invested for corporate and other purposes. 

E&P Operations Review

During the first nine months of 2014, Southwestern invested a total of approximately $1.7 billion in its E&P business, including $705 million in the Fayetteville Shale, $502 million in the Marcellus Shale, $247 million in the Niobrara, $97 million in the Brown Dense, $82 million for Drilling Rigs, $64 million in New Ventures,  $7 million in E&P Services and $3 million in its Ark-La-Tex division.

Marcellus Shale – In the third quarter of 2014, Southwestern placed 18 new wells on production in the Marcellus Shale and had net gas production from the Marcellus Shale of 66 Bcf, up approximately 47% from 45 Bcf in the third quarter of 2013. Gross operated production in the Marcellus Shale was approximately 840 MMcf per day at September 30, 2014.

As of September 30, 2014, Southwestern had 234 operated wells on production and 102 wells in progress. Of the operated wells on production, 233 were horizontal wells of which 109 were located in Susquehanna County, 103 were located in Bradford County and 21 were located in Lycoming County. Of the 102 wells in progress, 36 were either waiting on completion or waiting to be placed to sales, including 19 in Susquehanna County, 16 in Bradford County and 1 in Wyoming County.

Results from the company’s drilling activities since the third quarter of 2010 are shown below.

*Average CLAT of wells that have produced for 30 days.

Southwestern continues to test the Upper Marcellus formation where 3 wells have been drilled to date and are expected to be completed in the fourth quarter of 2014.  One additional well is scheduled to be drilled in the fourth quarter of 2014 and completed in the first quarter of 2015.  Additionally, testing continues on the acreage in Wyoming, Sullivan and Tioga Counties that was acquired in 2013, including the Dimmig 2H, the company’s first horizontal well in Wyoming County. That well is currently testing and the initial results are encouraging. We also recently began drilling our first well in Tioga County.

Two wells have also been drilled near the New York border in Susquehanna County. Early results are positive and work has begun to build a gathering system for future development in this area.

The graph below provides normalized average daily production data through September 30, 2014, for the company’s horizontal wells in the Marcellus Shale. The “pink curve” indicates results for 59 wells with more than 18 fracture stimulation stages, the “purple curve” indicates results for 104 wells with 13 to 18 fracture stimulation stages, the “orange curve” indicates results for 65 wells with 9 to 12 fracture stimulation stages and the “green curve” indicates results for 5 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 type curves are shown solely for reference purposes and are not intended to be projections of the performance of the company’s wells.

Note:  Data as of September 30, 2014 

Fayetteville Shale – In the third quarter of 2014, Southwestern placed 106 new wells on production in the Fayetteville Shale and had net gas production from the Fayetteville Shale of 126 Bcf in the third quarter of 2014, compared to 123 Bcf in the third quarter of 2013. Gross operated gas production in the Fayetteville Shale was approximately 2,058 MMcf per day at September 30, 2014.

During the third quarter of 2014, the company’s horizontal wells in the Fayetteville Shale had an average completed well cost of $2.4 million per well, average horizontal lateral length of 5,202 feet and average time to drill to total depth of 6.5 days from re-entry to re-entry. This compares to an average horizontal lateral length of 5,382 feet and average time to drill to total depth of 6.7 days from re-entry to re-entry for an average completed well cost of $2.5 million per well in the second quarter of 2014. In the third quarter of 2014, the company had 23 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. Since inception, the company has drilled 334 wells to total depth in 5 days or less from re-entry to re-entry in the Fayetteville Shale.

In the third quarter of 2014, the company placed 36 operated wells on production with initial production rates that exceeded 5,000 Mcf per day, and 13 wells that exceeded 6,000 Mcf per day. To date, the company has placed a total of 466 wells on production with initial production rates greater than 5,000 Mcf per day, of which 145 wells have been in the past year. The company’s wells placed on production during the third quarter of 2014 averaged initial production rates of 4,303 Mcf per day. Results from the company’s drilling activities since the first quarter of 2007 are shown below.

Note: Results as of September 30, 2014. 

In the Upper Fayetteville formation, the company has placed 15 wells on production to date with an average initial production rate of 3.4 million cubic feet of gas per day. Three of these wells had an average initial production rate over 5.0 million cubic feet of gas per day, with the highest initial production rate being 6.6 million cubic feet of gas per day. The company plans to drill five additional Upper Fayetteville wells in the fourth quarter and complete them in early 2015.

Ark-La-Tex – Total net production from the company’s East Texas and conventional Arkoma Basin assets was 12.0 Bcfe in the first nine months of 2014, compared to 14.1 Bcfe in the first nine months of 2013.

New Ventures – Through the end of the third quarter, the company has acquired or leased a total of 380,000 net acres in northwest Colorado. Testing of this acreage is progressing as the company has drilled three vertical wells to date that are in various stages of testing. The first horizontal well is currently drilling and an additional vertical well is planned for the fourth quarter. 

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 financial statement users with 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 adjusted net income, adjusted diluted earnings per share, adjusted EBITDA 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, 2014 and September 30, 2013, respectively. 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.