HOUSTON, Oct. 22, 2015 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the quarter ended September 30, 2015. Third quarter highlights include:

• Record production of 249 Bcfe, up 27% compared to year-ago levels;
• Total Appalachia net production of 130 Bcfe, comprised of 93 Bcf from Northeast Appalachia (a 41% increase compared to year-ago levels) and 37 Bcfe from Southwest Appalachia;
• Strong operational performance in Southwest Appalachia demonstrated by latest well results;
• Adjusted net income attributable to common stock (a non-GAAP measure reconciled below) of $3 million, or $0.01 per diluted share when excluding a non-cash ceiling test impairment of natural gas and oil properties and certain other items; and
• Net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure reconciled below) of approximately $330 million.

"During the third quarter, we once again delivered excellent operational results while managing through the challenging commodity price environment," remarked Steve Mueller, Chairman and Chief Executive Officer of Southwestern Energy. "Our acquired acreage in Southwest Appalachia continues to provide exciting results, which we feel only scratches the surface of its potential considering we have been operating these assets for less than ten months. As we look forward, our disciplined approach to investing and our low costs will continue to differentiate our portfolio of high quality assets during these difficult times."

Third Quarter of 2015 Financial Results

For the third quarter of 2015, Southwestern reported adjusted net income attributable to common stock of $3 million, or $0.01 per diluted share, when excluding a non-cash ceiling test impairment of natural gas and oil properties of $2.8 billion ($1.7 billion net of taxes) and certain other items typically excluded by the investment community in published estimates, which in aggregate decreased net income by $1.8 billion or $4.63 per share (diluted). Including these items, the net loss attributable to common stock for the third quarter of 2015 was $1.8 billion, or $4.62 per diluted share (reconciled below). For the third quarter of 2014, Southwestern reported adjusted net income attributable to common stock of $178 million, or $0.50 per diluted share, when excluding a $54 million ($33 million net of taxes) gain on derivative contracts that have not been settled. Including this gain, Southwestern reported net income attributable to common stock of $211 million, or $0.60 per diluted share, in the third quarter of 2014 (reconciled below).

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $330 million for the third quarter of 2015, compared to $504 million for the same period in 2014. On a GAAP basis, net cash provided by operating activities was $287 million for the third quarter of 2015, compared to $580 million in the third quarter of 2014.

The third quarter of 2014 includes the operating results from our gathering system in northeast Pennsylvania and our conventional E&P assets in East Texas and the Arkoma basin which were divested during the second quarter of 2015. See "Divestitures" below for additional information.

E&P Segment – The operating loss from the company's E&P segment was $71 million for the third quarter of 2015 (reconciled below), when excluding the non-cash impairment, compared to operating income of $189 million for the same period in 2014. The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses from higher activity levels, partially offset by the revenue impacts of higher production volumes. On a GAAP basis, the operating loss from the company's E&P segment was $2.9 billion for the third quarter of 2015, down from operating income of $189 million during the third quarter of 2014.

Net production totaled 249 Bcfe in the third quarter of 2015, up 27% from 196 Bcfe in the third quarter of 2014. The quarter included 118 Bcf from the Fayetteville Shale, 93 Bcf from Northeast Appalachia and 37 Bcfe from Southwest Appalachia. This compares to 126 Bcf from the Fayetteville Shale and 66 Bcf from Northeast Appalachia in the third quarter of 2014.

Including the effect of hedges, Southwestern's average realized gas price in the third quarter of 2015 was $2.21 per Mcf, down from $3.43 per Mcf in the third quarter of 2014. The company's commodity hedging activities increased its average realized gas price by $0.44 per Mcf during the third quarter of 2015, compared to an increase of $0.22 per Mcf during the same period in 2014. As of September 30, 2015, the company had approximately 60 Bcf of its remaining 2015 forecasted gas production hedged at an average price of $4.40 per Mcf.

Like most producers, 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 2015 was approximately $1.00 per Mcf lower than average NYMEX settlement prices, compared to approximately $0.85 per Mcf lower during the third quarter of 2014. As of September 30, 2015, the company had protected approximately 82 Bcf of its remaining 2015 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 ($0.17) per Mcf.

Lease operating expenses per unit of production for the company's E&P segment were $0.92 per Mcfe in the third quarter of 2015, compared to $0.91 per Mcfe in the third quarter of 2014. The increase was primarily due to higher operating costs in Southwest Appalachia associated with liquids production.

General and administrative expenses per unit of production were $0.20 per Mcfe in the third quarter of 2015, compared to $0.23 per Mcfe in the third quarter of 2014, down primarily due to the increase in production volumes.

Taxes other than income taxes were $0.10 per Mcfe in the third quarter of 2015 and 2014. 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 $0.98 per Mcfe in the third quarter of 2015, compared to $1.09 per Mcfe in the third quarter of 2014. 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 gathering and marketing activities, was $68 million for the third quarter of 2015, down 30% from $97 million for the same period in 2014. The decrease in operating income was largely due to the 2015 divestiture of the gathering system in northeast Pennsylvania. At September 30, 2015, the company's midstream segment was gathering approximately 2.1 Bcf per day through 2,037 miles of gathering lines in the Fayetteville Shale.

First Nine Months of 2015 Financial Results

For the first nine months of 2015, Southwestern reported adjusted net income attributable to common stock, which includes a $14 million impact from a theoretical income allocation to preferred stock, of $77 million, or $0.20 per diluted share, when excluding a non-cash ceiling test impairment of natural gas and oil properties of $4.4 billion ($2.7 billion net of taxes) and certain other items typically excluded by the investment community in published estimates, which in aggregate decreased net income by $2.6 billion or $6.89 per share (diluted). Including these items, the net loss attributable to common stock for the first nine months of 2015 was $2.5 billion, or $6.65 per diluted share (reconciled below). For the first nine months of 2014, Southwestern reported adjusted net income attributable to common stock of $616 million, or $1.75 per diluted share, when excluding a $7 million ($4 million net of taxes) loss on derivative contracts that have not been settled. Including this loss, Southwestern reported net income attributable to common stock of $612 million, or $1.74 per diluted share, for the first nine months of 2014 (reconciled below).

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $1.2 billion for first nine months of 2015, compared to $1.7 billion for the same period in 2014. On a GAAP basis, net cash provided by operating activities was $1.2 billion for the first nine months of 2015, compared to $1.8 billion for the first nine months of 2014.

E&P Segment – The operating loss from the company's E&P segment was $97 million for the first nine months of 2015 (reconciled below), when excluding the non-cash impairment, compared to operating income of $817 million for the same period in 2014. The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses from higher activity levels, partially offset by the revenue impacts of higher production volumes. On a GAAP basis, the operating loss from the company's E&P segment was $4.5 billion for the first nine months of 2015, down from operating income of $817 million during the first nine months of 2014.

Net production totaled 727 Bcfe in the first nine months of 2015, up 28% from 567 Bcfe in the first nine months of 2014. The first nine months of 2015 included 354 Bcf from the Fayetteville Shale, 263 Bcf from Northeast Appalachia and 103 Bcfe from Southwest Appalachia. This compares to 369 Bcf from the Fayetteville Shale and 185 Bcf from Northeast Appalachia in the first nine months of 2014.

Including the effect of hedges, Southwestern's average realized gas price in the first nine months of 2015 was $2.47 per Mcf, down from $3.79 per Mcf in the first nine months of 2014. The company's commodity hedging activities increased its average realized gas price by $0.42 per Mcf during the first nine months of 2015, compared to a decrease of $0.12 per Mcf during the same period in 2014. Disregarding the impact of hedges, the average price received for the company's gas production during the first nine months of 2015 was approximately $0.75 per Mcf lower than average monthly NYMEX settlement prices, compared to approximately $0.64 per Mcf during the first nine months of 2014.

Lease operating expenses per unit of production for the company's E&P segment were $0.92 per Mcfe in the first nine months of 2015, compared to $0.91 per Mcfe in the first nine months of 2014. The increase was primarily due to higher operating costs in Southwest Appalachia associated with liquids production.

General and administrative expenses per unit of production were $0.22 per Mcfe in the first nine months of 2015, compared to $0.24 per Mcfe in the first nine months of 2014, down primarily due to the increase in production volumes.

Taxes other than income taxes were $0.11 per Mcfe during the first nine months of 2015 and 2014.

The company's full cost pool amortization rate decreased to $1.08 per Mcfe in the first nine months of 2015, compared to $1.10 per Mcfe in the first nine months of 2014.

Midstream Services – Operating income, excluding the gain on sale of assets divested, for the company's Midstream Services segment was $234 million for the first nine months of 2015, down 14% from $272 million for the same period in 2014 (reconciled below). The decrease in operating income was largely due to the 2015 divestiture of the gathering system in northeast Pennsylvania. On a GAAP basis, operating income for the Midstream Services segment was $511 million for the first nine months of 2015, compared to $272 million for the first nine months of 2014.

Capital Structure and Investments – At September 30, 2015, the company had approximately $4.7 billion in long-term debt, including a combined $800 million borrowed on its revolving credit facility and commercial paper program.

During the first nine months of 2015, excluding the $617 million of acquisition costs and post-closing adjustments for the Appalachia transactions that closed in December 2014 and January 2015, Southwestern invested a total of $1.4 billion. This is down from $1.8 billion in the first nine months of 2014 and included approximately $1.4 billion invested in its E&P business, $45 million invested in its Midstream Services segment and $10 million invested for corporate and other purposes.

Divestitures

The company divested its gathering system in northeast Pennsylvania and its conventional E&P assets in East Texas and the Arkoma basin in the second quarter of 2015.

The northeast Pennsylvania gathering system generated operating income of $13 million for the nine months ended September 30, 2015, compared to operating income of $8 million and $27 million for the three and nine months ended September 30, 2014. For the nine months ended September 30, 2015, this gathering system generated net cash provided by operating activities of $15 million. For the three and nine months ended September 30, 2014, this gathering system generated net cash provided by operating activities of approximately $10 million and $32 million, respectively.

The conventional E&P assets in East Texas and the Arkoma basin had production of 6 Bcfe during the first nine months of 2015. This compares to 4 Bcfe and 12 Bcfe for the three and nine months ended September 30, 2014. For the three months ended September 30, 2015, these assets generated an operating loss of approximately $1 million, compared to operating income of $5 million and $24 million for the three and nine months ended September 30, 2014.

E&P Operations Review

During the first nine months of 2015, Southwestern invested approximately $1.4 billion in its E&P business, excluding the acquisition costs and post-closing adjustments for the Appalachia transactions noted previously. This includes $466 million in Northeast Appalachia, $369 million in Southwest Appalachia, $453 million in the Fayetteville Shale, $2 million in its Ark-La-Tex division, $74 million in New Ventures, and $18 million in E&P Services.

Northeast Appalachia – In the third quarter of 2015, Southwestern placed 26 new wells on production in Northeast Appalachia and had net gas production of 93 Bcf, up 41% from 66 Bcf in the third quarter of 2014. Gross operated production in Northeast Appalachia was approximately 1,237 MMcf per day at September 30, 2015.

In the third quarter of 2015, the average 30th-day rate was 5,752 Mcf per day on 19 wells that had an average lateral length of 5,512 feet and an average cost of $5.6 million per well. This compares to an average 30th-day rate of 6,594 Mcf per day on 21 wells that had an average lateral length of 5,853 feet and an average cost of $6.8 million per well in the second quarter of 2015.

Operational efficiencies continue to be realized as the company focuses on combining its technological advances from the upgraded rig fleet that was added to the portfolio last year, its advancement of learnings and the incremental utility of the infrastructure in this area after five years of operations. During the third quarter of 2015, average time to drill to total depth was reduced to 8 days from re-entry to re-entry compared to 9 days in the second quarter of 2015.

As of September 30, 2015, Southwestern had 394 operated wells on production and 102 wells in progress. Of the operated wells on production, 393 were horizontal wells of which 231 were located in Susquehanna County, 137 were located in Bradford County and 25 were located in Lycoming County. Of the 102 wells in progress, 50 were either waiting on completion or waiting to be placed to sales, including 43 in Susquehanna County, 3 in Bradford County and 4 wells in Sullivan, Tioga and Wyoming Counties, combined.

The graph below provides normalized average daily production data through September 30, 2015, for the horizontal wells drilled by the company in Northeast Appalachia. The "pink curve" summarizes results for 137 wells in Bradford County, the "blue curve" reflects results for 231 wells in Susquehanna County, the "orange curve" shows the results for 25 wells in Lycoming County and the "green curve" averages the results for the 131 wells that have been put on production within the last 18 months. As a reminder, the pressure drawdown in the reservoir, hence the production rates from all of our wells in Northeast Appalachia, are managed to maximize the ultimate recovery from the wells. The impact of this program is exhibited in all of the curves with the relatively flat production for the first 365 days before the wells begin normal declines. Furthermore, the company continues to improve its completion design and the performance history from the most recent wells is beginning to reflect these improvements. The normalized production curves are intended to provide a qualitative indication of the company's Northeast Appalachia wells' performance and should not be used to estimate an individual well's estimated ultimate recovery. The 8, 10 and 12 Bcf type curves are shown solely for reference purposes and are not intended to be projections of the performance of the company's wells.

The company also made significant progress in proving up the northern part of our acreage in Tioga County during the third quarter of 2015. The Kohler 2H, a 4,000 foot lateral well drilled and completed by the previous operator in 2012, had a constant rate flow test of approximately 5 million cubic feet per day for two weeks with minimal bottom hole pressure drawdown. In conjunction with the Lepley 6H, which was announced last quarter and also tested at a 5 million cubic feet per day rate for two weeks from only 1,822 feet of the lateral, Southwestern's 29,000 net acres in Tioga County have been de-risked. Infrastructure development has been initiated and this acreage will be drilled beginning in 2016.

Southwestern also continued the delineation of Susquehanna County. The Colwell North 3H, the furthest eastern extension well in the county, flowed at an initial rate of over 4 million cubic feet per day without compression. Compression is expected to be added to the area during the fourth quarter of 2015. Even with limited data from this well during flowback, the eastern extent of our acreage in Susquehanna County looks even more encouraging.

Southwest Appalachia – During the third quarter of 2015, the company's net production from Southwest Appalachia was 37 Bcfe. In the 10 months of operating in this new area, the company has set a number of company records, including longest completed lateral, most proppant in a single well, most pounds of sand per foot and most stages per well.

During the third quarter, the company drilled 16 wells, with an average lateral length of 6,376 feet and average time to drill to total depth of 18 days from re-entry to re-entry. Southwestern placed 5 wells on production in Southwest Appalachia in the third quarter. Results from these wells are shown in the table below.

Compared to historical offsets, the company is achieving better results by drilling in a tighter target interval, enhancing the completion design and utilizing pressure drawdown management. For example, three new wells on the Charles Frye pad, which were placed on production in the third quarter, were drilled 100% in the target landing interval and were completed with over 2,000 pounds of sand per foot. The amount of proppant used on these wells represents an increase of over 55% when compared to the average of the offset wells. Normalized for lateral length, the average estimated ultimate recovery per lateral foot of the three new Charles Frye wells is 54% higher than the offset wells drilled and completed by the previous operator.

The company has received a permit for its first Utica well, located in Marshall County, West Virginia and has recently spud the well. The well is expected to be completed during the fourth quarter and placed on production in early 2016. Additional Utica wells are anticipated as part of the 2016 drilling program, with the number and location of these wells to be finalized as part of the 2016 budget process.

As of September 30, 2015, Southwestern had 281 operated horizontal wells on production and 43 operated horizontal wells in progress. Of the operated horizontal wells on production, approximately 85% were in the wet gas portion of the acreage. Of the 43 wells in progress, 19 were waiting on completion.

Fayetteville Shale – In the third quarter of 2015, Southwestern's net gas production from the Fayetteville Shale was 118 Bcf, compared to 126 Bcf in the third quarter of 2014 and 121 Bcf in the second quarter of 2015. Gross operated gas production in the Fayetteville Shale was approximately 1,856 MMcf per day at September 30, 2015.

The 50 horizontal wells that were placed on production during the third quarter of 2015 had an average initial production rate of 3,835 Mcf per day, average completed well cost of $2.7 million per well, average horizontal lateral length of 5,407 feet and average time to drill to total depth of 6.9 days from re-entry to re-entry. This compares to the 68 horizontal wells that the company placed on production in the second quarter of 2015 that had an average initial production rate of 4,405 Mcf per day, an average horizontal lateral length of 5,861 feet, average time to drill to total depth of 7.1 days from re-entry to re-entry and an average completed well cost of $2.8 million per well. The decrease in average initial production rate was primarily caused by shorter lateral lengths and well mix. In particular, the company drilled four wells that were drilled by the company in a joint interest partner's section, which is outside of our core acreage. Without these wells, the average initial production rate was 4,010 Mcf per day for the third quarter of 2015.

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. These non-GAAP performance measures often exclude items typically excluded by the investment community in published estimates to improve comparability.

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 and Midstream 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, 2015 and September 30, 2014. 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.

Southwestern management will host a teleconference call on Friday, October 23, 2015 at 10:00 a.m. Eastern to discuss its third quarter 2015 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 natural gas and oil exploration, development 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 fund the company's planned capital investments; 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 various areas and, in particular, the Fayetteville Shale, Northeast Appalachia and Southwest Appalachia as well as relative to other productive shale gas plays; the company's ability to realize the expected benefits from recent acquisitions; the impact of title and environmental defects and other matters on the value of the properties acquired in the company's recent acquisitions and any other future acquisitions; difficulties in integrating the company's operations as a result of any significant acquisitions; the impact of government regulation, including any legislation relating to hydraulic fracturing, the climate or over-the-counter derivatives; the costs and availability of oil field personnel services and drilling supplies, raw materials and equipment, including pressure pumping equipment and crews; the company's ability to determine the most effective and economic fracture stimulation; the company's future property acquisition or divestiture activities; the effects of weather; increased competition and regulation; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; the different risks and uncertainties associated with proposed activities in Canada; 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.

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