Southwestern Energy Announces Operational Update And 2016 Financial Results

HOUSTON, Feb. 23, 2017 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the fourth quarter and the year ended December 31, 2016. Calendar year 2016 highlights include:

• Net cash provided by operating activities of $498 million and net cash flow of $645 million;
• Net loss attributable to common stock of $2.8 billion, or $6.32 per diluted share, and adjusted net loss attributable to common stock of $7 million, or $0.01 per diluted share;
• Total net production of 875 Bcfe, including 498 Bcfe from the Appalachia Basin and 375 Bcf from the Fayetteville Shale;
• Encouraging results associated with Northeast Appalachia completion testing and production flow optimization, including an aggregate initial production rate of approximately 92 million cubic feet per day from five wells on the Cramer pad that were placed to sales in the fourth quarter;
• First sales successfully commenced in Tioga County, Pennsylvania;
• Positive early results from the Company's first drilled and completed Utica well in Marshall County, West Virginia;
• Upward proved reserves performance revisions of 683 Bcfe, reflecting the continued improvement in ultimate well recoveries and lower costs; and
• Proved Developed Producing (PDP) Finding and Development costs for the total company of $0.75 per Mcfe, a 15% improvement from prior year.

"The bold and decisive approach in which we tackled 2016 delivered remarkable results," said Bill Way, President and Chief Executive Officer of Southwestern Energy.  "The progress made in improving our financial strength and the operational excellence that facilitated our mid-year resumption of drilling and completion activities has the Company positioned well to create long-term value for our shareholders." 

The Company delivered on all of the initiatives promised at the beginning of 2016, which included strengthening the balance sheet and enhancing margins.  As a result, the Company extended its liquidity through 2020 and ended the year with total debt of $4.7 billion and net debt of $3.2 billion, reducing its net debt by $1.5 billion compared to the end of 2015.  Additionally, the Company was able to reduce cash operating costs, which includes lease operating expense, general and administrative expense and taxes other than income, by $0.04 per Mcfe through a relentless focus on margin enhancements and operational efficiencies.  Below is a summary of fourth quarter and full year 2016 results. 

Fourth Quarter of 2016 Financial Results

E&P Segment – The operating income from the Company's E&P segment was $82 million for the fourth quarter of 2016, improved from an operating loss of $2.6 billion during the fourth quarter of 2015 due to a $2.6 billion impairment of natural gas and oil properties during that quarter.  Excluding impairments and other one-time charges, adjusted operating income from the Company's E&P segment was $94 million for the fourth quarter of 2016, compared to an adjusted operating loss of $64 million for the same period in 2015. The increase in adjusted operating income was primarily due to lower operating costs and higher realized liquids prices partially offset by decreased production.  The decreased production was a result of limited activity in 2016 due to lower natural gas prices.

Midstream Segment – Operating income for the Company's Midstream segment, comprised of gathering and marketing activities, was $40 million for the fourth quarter of 2016, compared to $72 million for the same period in 2015.  The decrease in operating income was largely due to a decrease in volumes gathered, resulting from lower production volumes in the Fayetteville Shale.

Full Year 2016 Financial Results

E&P Segment – The operating loss from the Company's E&P segment was $2.4 billion for 2016, compared to an operating loss of $7.1 billion for 2015. The E&P segment recorded a $2.3 billion impairment of natural gas and oil properties for the year ended December 31, 2016 compared to a $7.0 billion impairment for the same period in 2015.  Excluding impairments, the improvement in operating loss was primarily due to lower operating costs and expenses and increasing NGL realizations, partially offset by lower realized natural gas prices and decreased production. Adjusted operating income from the Company's E&P segment was $3 million for 2016, compared to an adjusted operating loss of $159 million in 2015.

Midstream Services – Operating income for the Company's Midstream segment was $209 million for 2016, compared to $583 million for the same period in 2015. The decrease in operating income was primarily due to 2015 including a $277 million net gain on sale of assets divested. Adjusted operating income for the Company's Midstream segment was $212 million for 2016 compared to $306 million for the same period in 2015. The decrease in adjusted operating income was largely due to a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale and the sale of the Company's northeast Pennsylvania gathering assets.

Capital Investments – During 2016, Southwestern invested a total of $648 million.  This included approximately $623 million invested in its E&P business, $21 million invested in its Midstream segment and $4 million invested for corporate and other purposes.  Of the $648 million, approximately $152 million was associated with capitalized interest and $89 million was associated with capitalized expenses.

2016 Natural Gas and Oil Reserves

Southwestern's estimated proved natural gas and oil reserves totaled approximately 5,253 Bcfe at December 31, 2016, compared to 6,215 Bcfe at the end of 2015. The decrease in the Company's reserves in 2016 was primarily due to downward price revisions associated with decreased commodity prices and 2016 production, partially offset by upward performance revisions and the Company's successful development activity in Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale.  The average prices from the first day of each month from the previous twelve months utilized to value the Company's estimated proved natural gas and oil reserves at December 31, 2016 were $2.48 per MMBtu for natural gas, $39.25 per barrel for oil and $6.74 per barrel for NGLs, compared to $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82 per barrel for NGLs at December 31, 2015. Approximately 93% of the Company's estimated proved reserves were natural gas and 99% were classified as proved developed at year-end 2016, compared to 95% and 93%, respectively, at year-end 2015.

The following table details additional information relating to reserve estimates as of and for the year ended December 31, 2016:

The following table provides an overall and by category summary of the Company's natural gas, oil and NGL reserves as of December 31, 2016 and sets forth 2016 annual information related to production and capital investments for each of its operating areas:

The Company's 2016 and three-year average proved developed finding and development costs were $0.75 and $1.00 per Mcfe, respectively, when excluding the impact of capitalizing interest and portions of G&A costs in accordance with the full cost method of accounting. 

Proved developed finding and development costs – Proved developed (PDP) finding and development (F&D) costs are computed here by dividing exploration and development capital costs incurred, excluding capitalized interest and expenses, for the indicated period by PDP reserve additions and proved undeveloped (PUD) conversions for that same period.  At times, adjustments are made to this calculation in order to improve usefulness for investors.  For example, adjustments are made to exclude the differences between accounting methods to improve comparability. The following computes PDP F&D costs for the periods ending December 31, 2016, 2015 and 2014 and the three years ending December 31, 2016.  A breakdown is also shown detailing these amounts separately for Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale.

The Company believes that providing a measure of PDP 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 the financial statements, including the notes thereto, contained in Southwestern's Annual Report on Form 10-K. Due to various factors, including timing differences, PDP F&D costs do not necessarily reflect precisely the costs associated with particular reserves. 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 PDP F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its PDP F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern's PDP F&D costs may not be comparable to similar measures provided by other companies.

2016 Operational Review

During 2016, Southwestern invested a total of approximately $623 million in our E&P business, and participated in drilling 62 wells, completed 86 wells, placed 85 wells to sales and had 135 wells in progress. Of the 135 wells in progress at year-end, 73, 42 and 20 were located in our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale operating areas, respectively, and 35 of these wells are waiting on pipeline or production facilities.

Northeast Appalachia – In the fourth quarter of 2016, the Company placed 12 wells to sales that had an average lateral length of 6,075 feet and an average cost of $4.7 million per well.  The average rate for the first 30 days for wells online was 17,178 Mcf per day in the fourth quarter of 2016 compared to 4,796 Mcf per day in the fourth quarter of 2015.  The stronger early rates are a result of increased completion intensity and optimized flow techniques implemented during the second half of the year.  During the fourth quarter, Northeast Appalachia placed 11 wells to sales that were completed using increased completion intensity and optimized flow techniques, with all wells exhibiting encouraging early results.  One example is the Cramer pad in Susquehanna County, where the Company brought five wells to sales in the fourth quarter with a cumulative rate of approximately 92 million cubic feet per day.  Additionally, the Racine pad that was placed online in the third quarter of 2016 has continued to outperform offset wells, producing 75% more volumes in the first 125 days. While the Company continues to assess what portion of these increased volumes relate to incremental expected recovery and what portion relates to acceleration, these results clearly indicate additional value is being created with these new methods.

Additionally, the Company continued its delineation efforts in Tioga County, where initial infrastructure was installed, and it placed its first two well to sales in January 2017. The well results observed to date confirm the productivity of the acreage and the Company intends to further develop this area throughout 2017.

In 2016, Southwestern's operated horizontal wells had an average completed well cost of $5.3 million per well and an average horizontal lateral length of 6,142 feet. This compares to an average completed operated well cost of $5.4 million per well and an average horizontal lateral length of 5,403 feet in 2015. 

As of December 31, 2016, Southwestern had spud or acquired 568 operated wells, of which 447 were horizontal and on production and 73 were in progress. Of the 447 operated horizontal wells on production, 281 were located in Susquehanna County, 140 were located in Bradford County, 25 were located in Lycoming County, and one was located in Wyoming County. Of the 73 wells in progress, 46 were either waiting on completion or waiting to be placed to sales, including 36 in Susquehanna County, six in Bradford County and four wells in Sullivan, Tioga and Wyoming Counties, combined.

Southwest Appalachia – In the fourth quarter of 2016, Southwestern brought online seven wells in Southwest Appalachia, including the Company's first drilled and completed Utica well, the O.E. Burge 501H.  It was completed with a lateral length of 8,061 feet and is exhibiting the vast potential of this reservoir in the Company's Southwest Appalachia acreage.  With the encouraging results, the Company accelerated the timeline for drilling its next Utica test well, which began drilling earlier this month.

Additionally, completion intensity testing continued during the quarter with increased amounts of proppant being used in some wells.  In one group of wells, the Company tested one well using approximately 5,000 pounds per lateral foot of proppant and four wells using approximately 3,500 pounds per lateral foot, compared to the recent standard of 2,000 pounds per lateral foot.  These wells, along with other test wells, have recently been placed online and early results are expected to be available at the end of the first quarter.

In 2016, of the 18 wells brought to sales, 15 were drilled and completed by Southwestern, of which 14 targeted the Marcellus Shale.  The Marcellus wells had an average completed well cost of $5.4 million per well and an average horizontal lateral length of 5,316 feet. This compares to an average completed operated well cost of $6.9 million per well and an average horizontal lateral length of 6,985 feet in 2015.

The Company had a total of 299 horizontal and four vertical wells that the Company operated and that were on production as of December 31, 2016.  Additionally, there were 42 horizontal wells in progress at the end of 2016, of which 20 were waiting on pipeline or production facilities. 

Fayetteville Shale – During the fourth quarter of 2016, the Company placed 22 wells to sales with an average completed well cost of $2.8 million per well, and average horizontal lateral length of 5,547 feet. Of the 22 wells placed to sales, four were completed using increased proppant and tighter stage spacing.  These new completion methods indicate improved initial well productivity and the Company will continue to evaluate additional results to optimize economic value. 

During the fourth quarter of 2016, we continued delineation activity in the Moorefield, located just beneath the Fayetteville Shale.  Eight Moorefield wells were drilled during the quarter, with seven of these being completed in the first quarter of 2017.  These wells are expected to be placed to sales in March.

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, the results of its peers and of prior periods. 

One such non-GAAP financial measure is net cash flow. 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 debt, 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 position and performance are measured relative to the position and 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 throughout this release of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2016 and December 31, 2015, as applicable. 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.