SWN
$6.19
Southwestern Energy
($.07)
(1.12%)
Earnings Details
3rd Quarter September 2017
Thursday, October 26, 2017 4:30:00 PM
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Summary

Southwestern Energy Misses

Southwestern Energy (SWN) reported 3rd Quarter September 2017 earnings of $0.06 per share on revenue of $737.0 million. The consensus earnings estimate was $0.07 per share on revenue of $755.9 million. The Earnings Whisper number was $0.10 per share. Revenue grew 13.2% on a year-over-year basis.

Southwestern Energy Co is an energy company. It explores, develops, and produces natural gas and crude oil within the United States.

Results
Reported Earnings
$0.06
Earnings Whisper
$0.10
Consensus Estimate
$0.07
Reported Revenue
$737.0 Mil
Revenue Estimate
$755.9 Mil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Southwestern Energy Announces Third Quarter 2017 Financial And Operating Results

Southwestern Energy Company (SWN) today announced its financial and operating results for the quarter ended September 30, 2017, along with other recent developments. Highlights include:

Realized net income attributable to common stock of $43 million, or $0.09 per diluted share, and adjusted net income attributable to common stock of $29 million, or $0.06 per diluted share;

Achieved net cash provided by operating activities of $211 million and net cash flow of $248 million, up 23% and 43%, respectively, compared to the third quarter of 2016;

Total net production of 232 Bcfe, including 153 Bcfe from the Appalachian Basin, an increase of approximately 10% and 26%, respectively, compared to the third quarter of 2016, despite third party gathering downtime in Northeast Appalachia;

Achieved record exit production rate from the Appalachian Basin of almost 2.4 Bcfe per day, an increase of 42% compared to the third quarter of 2016;

Realized C3+ NGL prices of $27.82 per barrel, or 58% of West Texas Intermediate (WTI), and realized total NGL prices of $14.47 per barrel, or 30% of WTI (net of transportation costs), up 75% and 106%, respectively, compared to the third quarter of 2016;

Created incremental value of approximately $1.4 million per well from reduced processing rates in the lean gas acreage of Southwest Appalachia;

Commenced water infrastructure project in Southwest Appalachia that is expected to reduce well costs by approximately $500,000 per well beginning in late 2018;

Demonstrated repeated reservoir deliverability with second Company-drilled Utica well results in line with the Company’s first Utica well;

Progressed Tioga County development with first four-well pad delivering an initial production rate of over 80 MMcf per day;

Renegotiated Fayetteville firm transportation agreement, increasing expected cash flow by approximately $45 million in 2018 while securing flexible takeaway capacity at significantly reduced rates beyond 2020, subject to FERC approval;

Brought two additional encouraging Moorefield delineation wells online continuing to confirm our geologic and reservoir modeling of the play; and

Improved debt maturity profile through notes offering and tender, resulting in only $92 million in bond debt due prior to 2022.

"The execution of our strategy continued to deliver strong results in the third quarter," said Bill Way, President and Chief Executive Officer of Southwestern Energy. "Through technological advancements, strategic negotiation of transportation, processing and gathering agreements, and improving our debt maturity schedule, we are driving material shareholder value and positioning ourselves for additional value creation in 2018 and beyond."

Financial Results
For the three months ended For the nine months ended
September 30,
September 30,
2017
2016
2017
2016
(in millions, except per share amounts)
Operating income (loss)
$
110
$
(725)
$
564
$
(2,317)
Adjusted operating income (non-GAAP measure)
$
112
$
94
$
566
$
81
Net income (loss) attributable to common stock
$
43
$
(735)
$
548
$
(2,514)
Adjusted net income (loss) attributable to common stock (non-GAAP measure) $
29
$
12
$
156
$
(52)
Diluted earnings (loss) per share
$
0.09
$
(1.52)
$
1.10
$
(6.02)
Adjusted diluted earnings (loss) per share (non-GAAP measure)
$
0.06
$
0.03
$
0.31
$
(0.12)
Net cash provided by operating activities
$
211
$
172
$
789
$
337
Net cash flow (non-GAAP measure)
$
248
$
173
$
816
$
434
Exploration and Production Operating Results
For the three months ended For the nine months ended
September 30,
September 30,
2017
2016
2017
2016
Production
Fayetteville (Bcf)
78
90
241
289
Northeast Appalachia (Bcf)
101
84
285
268
Southwest Appalachia (Bcfe)
52
37
131
115
Other (Bcfe)
1
-
1
1
Total production (Bcfe)
232
211
658
673
% Natural Gas
88%
90%
89%
90%
Average unit costs per Mcfe
Lease operating expenses
$
0.91
$
0.86
$
0.90
$
0.87
General & administrative expenses(1)
$
0.23
$
0.23
$
0.22
$
0.21
Taxes, other than income taxes(2)
$
0.10
$
0.10
$
0.10
$
0.09
Full cost pool amortization
$
0.48
$
0.35
$
0.44
$
0.40
(1) Excludes $2 million and $71 million of restructuring charges for the three and nine months ended September 30, 2016, respectively.
(2) Excludes $3 million of restructuring charges for the nine months ended September 30, 2016.
Realized Prices
For the three months ended
For the nine months ended
September 30,
September 30,
2017
2016
2017
2016
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu)(1)
$
3.00
$
2.81
$
3.17
$
2.29
Discount to NYMEX(2)
(1.11)
(1.03)
(0.86)
(0.82)
Average realized gas price per Mcf, excluding hedges
$
1.89
$
1.78
$
2.31
$
1.47
Gain (loss) on settled financial basis derivatives ($/Mcf)
0.05
0.00
(0.04)
0.01
Gain (loss) on settled commodity derivatives ($/Mcf)
0.03
(0.05)
(0.05)
0.03
Average realized gas price per Mcf, including hedges
$
1.97
$
1.73
$
2.22
$
1.51
Oil Price:
WTI oil price ($/Bbl)
$
48.22
$
44.94
$
49.47
$
41.33
Discount to WTI
(7.73)
(9.53)
(7.99)
(12.80)
Average oil price per Bbl
$
40.49
$
35.41
$
41.48
$
28.53
NGL Price:
Average net realized NGL price per Bbl(3)
$
14.47
$
7.04
$
13.06
$
6.11
Percentage of WTI
30%
16%
26%
15%
(1) Based on last day settlement prices from monthly futures contracts.
(2) This discount includes a basis differential, physical basis sales, third-party transportation charges and fuel charges and excludes financial basis hedges.
(3) Includes the impact of transportation costs and $0.02 per Bbl of realized hedge gains for the three and nine months ended September 30, 2017 and $0.01 per Bbl of realized hedge gains for the three months ended September 30, 2016.

Third Quarter of 2017 Financial Results

E&P Segment - The operating income for the segment improved to $64 million for the third quarter of 2017, compared to an operating loss of $777 million during the third quarter of 2016 that included an $817 million impairment of natural gas and oil properties during this period last year. The increase in operating income was primarily due to the absence of impairments and restructuring charges and higher realized natural gas and liquids pricing, partially offset by higher operating costs.

Midstream Segment - Operating income for the segment, comprised of gathering and marketing activities, was $46 million for the third quarter of 2017, which included a $3 million gain on sale of equipment, compared to $52 million for the same period in 2016. The decrease in operating income was largely due to a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale.

First Nine Months of 2017 Financial Results

E&P Segment - The operating income for the segment improved to $435 million for the first nine months of 2017, compared to an operating loss of $2.5 billion during the first nine months of 2016, which was primarily due to the $2.3 billion impairment of natural gas and oil properties and $74 million in restructuring charges during this period last year. The increase in operating income in 2017 was primarily due to the absence of impairments and restructuring charges and higher realized natural gas and liquids pricing, partially offset by higher operating costs.

Midstream Segment - Operating income for the segment, comprised of gathering and marketing activities, was $129 million for the first nine months of 2017, which included a $3 million gain on sale of equipment, compared to $169 million for the same period in 2016, which included $3 million in restructuring charges. The decrease in operating income was largely due to a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale.

Capital Structure and Investments - At September 30, 2017, the Company had total debt of approximately $4.4 billion and $3.4 billion in net debt. In the third quarter, the Company completed a public offering of $650 million aggregate principal of its 7.50% senior notes due 2026 and $500 million aggregate principal of its 7.75% senior notes due 2027. The proceeds from this offering were used to repay $758 million of the Company’s 2020 Notes and to repay the outstanding balance of $327 million on the Company’s 2015 Term Loan. The Company now has only $92 million in bonds due prior to 2022. The undrawn revolver and the cash maintained on the balance sheet anchor the strong liquidity position the Company has built and intends to maintain as part of its disciplined financial plan.

During the first nine months of 2017, Southwestern invested a total of $946 million. This included approximately $921 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 $946 million, approximately $85 million was associated with capitalized interest and $77 million was associated with capitalized expenses.

Hedging Update

As of October 24, 2017, the Company had approximately 139 Bcf of its remaining 2017 forecasted gas production protected at an average swap or purchased put strike price of $3.01 per Mcf. Additionally, the Company had approximately 473 Bcf of its 2018 forecasted gas production protected at an average swap or purchased put strike price of $2.99 per Mcf, with upside exposure on approximately 62%, or 295 Bcf, of those protected volumes up to $3.39 per Mcf. The Company also had approximately 165 Bcf of its 2019 forecasted gas production protected at an average purchased put strike price or average swap price of $2.97 with upside exposure on approximately 66%, or 108 Bcf, of those protected volumes up to $3.32 per Mcf.

A detailed breakdown of the Company’s natural gas derivative financial instruments as of October 24, 2017 is shown below. Please refer to the Company’s quarterly report on Form 10-Q filed with the Securities and Exchange Commission for complete information on the Company’s commodity, basis and interest rate protection.

Weighted Average Price per MMBtu
Volume
Swaps
Sold Puts
Purchased
Sold Calls
(Bcf)
Puts
Financial protection on production
2017
Fixed price swaps
73
$
3.06
$
-
$
-
$
-
Two-way costless collars
32
-
-
2.96
3.38
Three-way costless collars
34
-
2.29
2.97
3.30
Total
139
2018
Fixed price swaps
178
$
3.02
$
-
$
-
$
-
Two-way costless collars
23
-
-
2.97
3.56
Three-way costless collars
272
-
2.40
2.97
3.37
Total
473
2019
Fixed price swaps
57
$
3.01
$
-
$
-
$
-
Three-way costless collars
108
$
-
$
2.50
$
2.95
$
3.32
Total
165
Sold call options
2017
22
$
-
$
-
$
-
$
3.68
2018
63
-
-
-
3.50
2019
52
-
-
-
3.50
2020
54
-
-
-
3.65
2021
35
-
-
-
3.51
Total
225
Note: Amounts may not sum due to rounding

As of October 24, 2017, the Company had also taken steps to mitigate the volatility of basis differentials by protecting basis on approximately 127 Bcf of its remaining 2017 forecasted natural gas production and 224 Bcf of its 2018 forecasted natural gas production at a basis differential to NYMEX natural gas prices of approximately ($0.53) per Mcf and ($0.29) per Mcf, respectively, which includes the impact of both physical and financial basis positions. A detailed breakdown of the Company’s financial basis positions as of October 24, 2017 is shown below:

Financial basis positions
Volume
Basis Differential
(excludes physical positions) (Bcf)
($/MMBTU)
2017
Dominion South
22.1
$
(1.16)
TETCO M3
10.2
(0.48)
Transco Z6 Non-NY
0.3
0.47
Total
32.6
$
(0.93)
2018
Dominion South
18.5
$
(1.17)
TETCO M3
7.3
1.08
Transco Z6 Non-NY
0.5
2.04
Total
26.2
$
(0.49)

E&P Operational Review

During the third quarter of 2017, Southwestern invested a total of approximately $320 million in the E&P business and participated in drilling 47 wells, completed 29 wells, and placed 37 wells to sales.

Three Months Ended Sept 30, 2017 E&P Division Results
Appalachia
Fayetteville
Northeast
Southwest
Shale
Production (Bcfe) (1)
101
52
78
Capital investments ($ in millions)
Exploratory and development drilling, including workovers $
104
$
90
$
20
Acquisition and leasehold
3
15
1
Seismic and other
4
2
5
Capitalized interest and expense
11
33
5
Total capital investments
$
122
$
140
$
31
Gross operated well count summary
Drilled
23
20
4
Completed
18
7
4
Wells to sales
15
18
3
Realized Price
NYMEX Henry Hub Price ($/MMBtu)
$
3.00
$
3.00
$
3.00
Discount to NYMEX ($/Mcf)(2)
$
(1.39)
$
(1.01)
$
(0.77)
Average realized gas price, excluding hedges ($/Mcf)
$
1.61
$
1.99
$
2.23
(1) Southwest Appalachia production consist of 25 Bcf of natural gas, 3,799 MBbls of NGLs and 639 MBbls of oil.
(2) This discount includes a basis differential, physical basis sales, third-party transportation charges and fuel charges and excludes financial basis hedges.

During the first nine months of 2017, Southwestern invested a total of approximately $921 million in the E&P business and participated in drilling 106 wells, completed 118 wells, and placed 130 wells to sales.

Nine Months Ended Sept 30, 2017 E&P Division Results
Appalachia
Fayetteville
Northeast
Southwest
Shale
Production (Bcfe) (1)
285
131
241
Gross operated production as of Sept 30, 2017 (MMcfe/d)
1,408
958
1,232
Capital investments ($ in millions)
Exploratory and development drilling, including workovers $
315
$
244
$
73
Acquisition and leasehold
12
46
1
Seismic and other
9
3
6
Capitalized interest and expense
31
97
17
Total capital investments
$
367
$
390
$
97
Gross operated well count summary
Drilled
56
36
13
Completed
57
38
22
Wells to sales
60
46
23
Realized Price
NYMEX Henry Hub Price ($/MMBtu)
$
3.17
$
3.17
$
3.17
Discount to NYMEX ($/Mcf)(2)
$
(0.95)
$
(0.78)
$
(0.78)
Average realized gas price, excluding hedges ($/Mcf)
$
2.22
$
2.39
$
2.39
(1) SW Appalachia production consisted of 60 Bcf of natural gas, 10,098 MBbls of NGLs and 1,673 MBbls of oil.
(2) This discount includes a basis differential, physical basis sales, third-party transportation charges and fuel charges and excludes financial basis hedges.

Southwest Appalachia - The Company’s net production from Southwest Appalachia was 52 Bcfe in the third quarter 2017, a 41% increase compared to the same quarter in 2016. Southwest Appalachia achieved record gross operated exit production rates of 958 MMcfe per day, a 54% increase compared to the third quarter of 2016. Southwestern brought online 18 wells in Southwest Appalachia in the third quarter, which included 17 Marcellus wells and one Utica well. The 17 Marcellus wells had an average lateral length of 6,958 feet and an average cost of $6.7 million per well. In Marshall County, Southwestern placed the four-well Gladys Briggs pad to sales in July with an average completed lateral length of 6,576 feet. The pad is currently producing at a rate of 58 MMcfe per day, comprised of 42% liquids, with an average flowing casing pressure of 2,250 psi. This productivity exceeds the Company’s lean gas type curve and results in an estimated pad finding and development costs of less than $0.25 per Mcfe.

During the third quarter of 2017, two key commercial development opportunities that expand margins and create significant long-term value were finalized in Southwest Appalachia.

In Marshall and Wetzel counties of West Virginia, the Company dedicated its dry gas Utica gathering rights to Williams Partners at competitive long-term gathering rates and concurrently expanded its wet gas Marcellus processing capacity optionality up to 660 net MMcf per day at immediately reduced processing rates. This agreement also provides connectivity options to several premium gas outlets and NGL hubs while reducing gathering fees. This new agreement is expected to add approximately $1.4 million in net present value per well for the Company’s lean gas wells.

Southwestern commenced a company-owned water infrastructure project in its Panhandle acreage in West Virginia to more efficiently transport water throughout the play. The project is expected to reduce completion costs by $500,000 per well beginning in late 2018 and reduce the break-even gas price by approximately $0.25 per Mcfe.

Southwestern continues to improve capital efficiency with drilling advancements, lowering costs and increasing recoveries. The Company set two drilling records in the third quarter. The first was on the John Hupp 3H in Brooke County, West Virginia, where 6,202 feet of lateral was drilled 100% in zone of a 15 foot target window, setting a new 24 hour drilling record. The second was on the William Rogers 405H well in Ohio County, West Virginia, which was drilled to a total depth of 13,927 feet in less than 10 days from rig release to rig release. These well results demonstrate how advanced technology is improving operational performance.

The Company’s second Utica well, the Marlin Funka 9H was placed online in August 2017. The well had a lateral length of 4,572 feet and was flowing at a rate of 23 MMcf per day prior to being shut in to perform additional tests. The well is expected to flow between 16 and 20 MMcf per day as part of its pressure management program when it is brought back online in the fourth quarter. The Company is encouraged with the initial results and the repeated deliverability demonstrated by its first two wells of the estimated 1,400 locations in its portfolio.

Northeast Appalachia - The Company’s net production from Northeast Appalachia was 101 Bcfe in the third quarter 2017, a 20% increase compared to the same quarter in 2016. Northeast Appalachia also achieved record gross operated exit production rates of 1,408 MMcfe per day, a 35% increase compared to the third quarter of 2016. In the third quarter of 2017, the Company placed 15 wells to sales, which had an average lateral length of 8,093 feet and an average cost of $7.2 million per well. The average rate for the first 30 days for the six wells that were online for at least 30 days was 15.7 MMcf per day.

The Company continued its delineation success utilizing enhanced completion designs in Tioga and western Susquehanna Counties, placing seven wells to sales with strong early results. For example, in Tioga County, the Company placed a four-well pad to sales with an average lateral length of approximately 7,500 feet and combined maximum rate of over 80 MMcf per day, flowing against 1,200 psi of line pressure. Additionally, the Company placed its first three-well pad to sales in the Susquehanna County acreage acquired in 2015 with an average lateral length of over 10,000 feet and combined maximum rate of over 62 MMcf per day. One of the wells on this pad utilized an advanced completion design and produced at 33 MMcf per day. The learnings from this well will be applied to future wells in this area.

The Company also generated an additional $0.09 per Mcf on its Northeast Appalachia volumes with its financial basis hedges in the third quarter as basis differentials widened as a result of increased production and delayed in-service dates on new takeaway projects. The current financial basis hedge position is expected to generate an additional $0.11 of benefit during the fourth quarter of 2017 based on current futures strip pricing, with the majority of protection being in October. The diversified firm transportation portfolio continues to position the Company to maximize realized pricing based on market dynamics, and the Company currently expects its 2018 price realizations in Northeast Appalachia to improve by over $0.25 per Mcf as additional infrastructure is placed into service.

Fayetteville Shale - During the third quarter of 2017, the Company placed three wells to sales, including two Moorefield delineation wells. The two Moorefield wells had an average lateral length of 7,495 feet and an average cost of $5.3 million per well. These two step-out wells incorporated learnings from previous well results, delivering an initial production rate of 5.4 MMcf per day and an average EUR of 5.5 Bcf. The Company plans to test two additional wells in the fourth quarter to further test the aerial extent of its Moorefield acreage.

Additionally, the Company successfully renegotiated its Fayetteville firm transportation agreement, subject to FERC approval, providing savings of approximately $70 million from 2017 through 2020, including $45 million in 2018. This agreement also secures flexible take-away capacity at reduced rates of approximately $0.10 per MMBtu after 2020, a reduction of over 60% compared to the current average rate of $0.26 per MMBtu. The Company is pursuing additional opportunities to further enhance margins and lower the break-even cost across the play.

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 nine months ended September 30, 2017 and September 30, 2016, and as of September 30, 2017 and December 31, 2016, 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.

3 Months Ended September 30,
2017
2016
(in millions)
Net income (loss) attributable to common stock:
Net income (loss) attributable to common stock
$
43
$
(735)
Add back:
Participating securities - mandatory convertible preferred stock
2
(2)
Impairment of natural gas and oil properties
--
817
Restructuring charges
--
2
(Gain) on certain derivatives
(31)
(81)
Loss on early extinguishment of debt(1)
59
57
Adjustments due to inventory valuation and other
--
(1)
Legal settlements
5
--
Adjustments due to discrete tax items(1)
(37)
256
Tax impact on adjustments
(12)
(301)
Adjusted net income attributable to common stock
$
29
$
12
(1) 2016 includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest changes.
(2) Primarily relates to the exclusion of certain discrete tax adjustments associated with the valuation allowance against deferred tax assets.
The Company expects its 2017 income tax rate to be 38.0% before the impacts of any valuation allowance.
9 Months Ended September 30,
2017
2016
(in millions)
Net income (loss) attributable to common stock:
Net income (loss) attributable to common stock
$
548
$
(2,514)
Add back:
Participating securities - mandatory convertible preferred stock
59
--
Impairment of natural gas and oil properties
--
2,321
Restructuring charges
--
77
(Gain) loss on certain derivatives
(350)
48
Gain on sale of assets, net
(3)
(2)
Loss on early extinguishment of debt(1)
70
57
Adjustments due to inventory valuation and other
(1)
3
Legal settlements
5
--
Adjustments due to discrete tax items(2)
(279)
903
Tax impact on adjustments
107
(945)
Adjusted net income (loss) attributable to common stock
$
156
$
(52)
(1) 2016 includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest changes.
(2) Primarily relates to the exclusion of certain discrete tax adjustments associated with the valuation allowance against deferred tax assets.
The Company expects its 2017 income tax rate to be 38.0% before the impacts of any valuation allowance.
3 Months Ended September 30,
2017
2016
Diluted earnings (loss) per share:
Diluted earnings (loss) per share
$
0.09
$
(1.52)
Add back:
Participating securities - mandatory convertible preferred stock
0.00
(0.00)
Impairment of natural gas and oil properties
--
1.69
Restructuring charges
--
0.01
(Gain) on certain derivatives
(0.06)
(0.17)
Loss on early extinguishment of debt(1)
0.12
0.12
Adjustments due to inventory valuation and other
--
(0.00)
Legal settlements
0.01
--
Adjustments due to discrete tax items(2)
(0.07)
0.53
Tax impact on adjustments
(0.03)
(0.63)
Adjusted diluted earnings per share
$
0.06
$
0.03
(1) 2016 includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest changes.
(2) Primarily relates to the exclusion of certain discrete tax adjustments associated with the valuation allowance against deferred tax assets.
The Company expects its 2017 income tax rate to be 38.0% before the impacts of any valuation allowance.
9 Months Ended September 30,
2017
2016
Diluted earnings (loss) per share:
Diluted earnings (loss) per share
$
1.10
$
(6.02)
Add back:
Participating securities - mandatory convertible preferred stock
0.12
--
Impairment of natural gas and oil properties
--
5.56
Restructuring charges
--
0.19
(Gain) loss on certain derivatives
(0.70)
0.12
Gain on sale of assets, net
(0.01)
(0.01)
Loss on early extinguishment of debt
0.14
0.14
Adjustments due to inventory valuation and other
(0.00)
0.01
Legal settlements
0.01
--
Adjustments due to discrete tax items(1)
(0.56)
2.16
Tax impact on adjustments
0.21
(2.27)
Adjusted diluted earnings (loss) per share
$
0.31
$
(0.12)
(1) 2016 includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest changes.
(2) Primarily relates to the exclusion of certain discrete tax adjustments associated with the valuation allowance against deferred tax assets.
The Company expects its 2017 income tax rate to be 38.0% before the impacts of any valuation allowance.
3 Months Ended September 30,
2017
2016
(in millions)
Cash flow from operating activities:
Net cash provided by operating activities
$
211
$
172
Add back:
Changes in operating assets and liabilities
37
--
Restructuring charges
--
1
Net Cash Flow
$
248
$
173
9 Months Ended September 30,
2017
2016
(in millions)
Cash flow from operating activities:
Net cash provided by operating activities
$
789
$
337
Add back:
Changes in operating assets and liabilities
27
50
Restructuring charges
--
47
Net Cash Flow
$
816
$
434
3 Months Ended September 30,
2017
2016
(in millions)
Operating income (loss):
Operating income (loss)
$
110
$
(725)
Add back:
Impairment of natural gas and oil properties
-
817
Restructuring charges and other charges
-
2
Legal settlements
5
-
Gain on sale of assets, net
(3)
-
Adjusted operating income
$
112
$
94
9 Months Ended September 30,
2017
2016
(in millions)
Operating income (loss):
Operating income (loss)
$
564
$
(2,317)
Add back:
Impairment of natural gas and oil properties
-
2,321
Restructuring charges and other charges
-
77
Legal settlements
5
-
Gain on sale of assets, net
(3)
-
Adjusted operating income
$
566
$
81
3 Months Ended September 30,
2017
2016
(in millions)
E&P segment operating income (loss):
E&P segment operating income (loss)
$
64
$
(777)
Add back:
Impairment of natural gas and oil properties
-
817
Restructuring charges and other charges
-
2
Legal settlements
5
-
Adjusted E&P segment operating income
$
69
$
42
9 Months Ended September 30,
2017
2016
(in millions)
E&P segment operating income (loss):
E&P segment operating income (loss)
$
435
$
(2,486)
Add back:
Impairment of natural gas and oil properties
-
2,321
Restructuring charges and other charges
-
74
Legal settlements
5
-
Adjusted E&P segment operating income (loss) $
440
$
(91)
September 30,
December 31,
2017
2016
(in millions)
Net debt:
Total debt
$
4,436
$
4,653
Subtract:
Cash and cash equivalents
(989)
(1,423)
Net debt
$
3,447
$
3,230

Southwestern management will host a teleconference call on Friday, October 27, 2017 at 10:00 a.m. Eastern to discuss its third quarter 2017 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.

This news release contains forward-looking statements. Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by terminology such as "anticipate," "intend," "plan," "project," "estimate," "continue," "potential," "should," "could," "may," "will," "objective," "guidance," "outlook," "effort," "expect," "believe," "predict," "budget," "projection," "goal," "forecast," "target" or similar words. Statements may be forward looking even in the absence of these particular words. Where, in any forward-looking statement, the Company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, changes in commodity prices; changes in expected levels of natural gas and oil reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; international monetary conditions; unexpected cost increases; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission. Unless legally required, Southwestern Energy Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Cautionary Note to U.S. Investors - The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. We use the term "EUR" in this release that the SEC’s guidelines prohibit us from including in filings with the SEC. The quarterly reserves data included in this release are estimates we prepared that have not been audited by our independent reserve engineers. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC. Copies are available from the SEC and from the Southwestern Energy Company website.

OPERATING STATISTICS (Unaudited)
Southwestern Energy Company and Subsidiaries
For the three months ended
For the nine months ended
September 30,
September 30,
2017
2016
2017
2016
Exploration & Production
Production
Gas production (Bcf)
205
189
587
605
Oil production (MBbls)
663
536
1,747
1,729
NGL production (MBbls)
3,810
3,068
10,134
9,580
Total production (Bcfe)
232
211
658
673
Commodity Prices
Average realized gas price per Mcf, including derivatives
$
1.97
$
1.73
$
2.22
$
1.51
Average realized gas price per Mcf, excluding derivatives
$
1.89
$
1.78
$
2.31
$
1.47
Average realized oil price per Bbl
$
40.49
$
35.41
$
41.48
$
28.53
Average realized NGL price per Bbl
$
14.47
$
7.04
$
13.06
$
6.11
Summary of Derivative Activity in the Statement of Operations
Settled commodity amounts included in
"Gain (Loss) on Derivatives" (in millions) (1) $
17
$
(9)
$
(52)
$
22
Unsettled commodity amounts included in "Gain (Loss) on Derivatives" (in millions)
$
30
$
81
$
349
$
(45)
Average unit costs per Mcfe
Lease operating expenses
$
0.91
$
0.86
$
0.90
$
0.87
General & administrative expenses (2)
$
0.23
$
0.23
$
0.22
$
0.21
Taxes, other than income taxes (3)
$
0.10
$
0.10
$
0.10
$
0.09
Full cost pool amortization
$
0.48
$
0.35
$
0.44
$
0.40
Midstream
Volumes marketed (Bcfe)
273
264
782
814
Volumes gathered (Bcf)
123
145
380
463
(1) Excludes $3 million amortization of premiums paid related to certain call options for the three and nine months ended September 30, 2017, which is included in gain (loss) on derivatives on the statements of operations (unaudited).
(2) Excludes $2 million and $71 million of restructuring charges for the three and nine months ended September 30, 2016, respectively.
(3) Excludes $3 million of restructuring charges for the nine months ended September 30, 2016.
STATEMENTS OF OPERATIONS (Unaudited)
Southwestern Energy Company and Subsidiaries
For the three months ended For the nine months ended
September 30,
September 30,
2017
2016
2017
2016
(in millions, except share/per share amounts)
Operating Revenues
Gas sales
$
394
$
340
$
1,368
$
906
Oil sales
27
19
73
50
NGL sales
55
22
132
59
Marketing
233
237
736
631
Gas gathering
28
33
85
106
737
651
2,394
1,752
Operating Costs and Expenses
Marketing purchases
236
234
740
627
Operating expenses
170
139
481
455
General and administrative expenses
62
61
170
171
Restructuring charges
-
2
-
77
Depreciation, depletion and amortization
135
99
364
349
Impairment of natural gas and oil properties
-
817
-
2,321
Taxes, other than income taxes
24
24
75
69
627
1,376
1,830
4,069
Operating Income (Loss)
110
(725)
564
(2,317)
Interest Expense
Interest on debt
58
59
175
168
Other interest charges
2
8
7
12
Interest capitalized
(29)
(41)
(85)
(123)
31
26
97
57
Gain (Loss) on Derivatives
45
71
295
(28)
Loss on Early Extinguishment of Debt
(59)
(51)
(70)
(51)
Other Income (Loss), Net
(2)
3
6
-
Income (Loss) Before Income Taxes
63
(728)
698
(2,453)
Benefit for Income Taxes
Current
(10)
-
(10)
-
Deferred
(4)
(20)
(4)
(20)
(14)
(20)
(14)
(20)
Net Income (Loss)
77
(708)
712
(2,433)
Mandatory convertible preferred stock dividend
27
27
81
81
Participating securities - mandatory convertible preferred stock
7
-
83
-
Net Income (Loss) Attributable to Common Stock
$
43
$
(735)
$
548
$
(2,514)
Earnings (Loss) Per Common Share
Basic
$
0.09
$
(1.52)
$
1.11
$
(6.02)
Diluted
$
0.09
$
(1.52)
$
1.10
$
(6.02)
Weighted Average Common Shares Outstanding
Basic
499,812,926
482,485,150
496,458,435
417,222,661
Diluted
502,290,779
482,485,150
498,527,671
417,222,661
BALANCE SHEETS (Unaudited)
Southwestern Energy Company and Subsidiaries
September 30,
December 31,
2017
2016
(in millions)
ASSETS
Current assets
$
1,476
$
1,872
Property and equipment
25,454
24,489
Less: Accumulated depreciation, depletion and amortization
(19,904)
(19,534)
Total property and equipment, net
5,550
4,955
Other long-term assets
176
249
Total assets
7,202
7,076
LIABILITIES AND EQUITY
Current liabilities
784
1,064
Long-term debt
4,396
4,612
Pension and other postretirement liabilities
46
49
Other long-term liabilities
324
434
Total liabilities
5,550
6,159
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 509,142,659 shares as of September 30, 2017 (does not include 3,346,703 shares issued on October 16, 2017 on account of a dividend declared on September 15, 2017) and 495,248,369 as of December 31, 2016
5
5
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of September 30, 2017 and December 31, 2016, conversion in January 2018
-
-
Additional paid-in capital
4,698
4,677
Accumulated deficit
(3,013)
(3,725)
Accumulated other comprehensive loss
(37)
(39)
Common stock in treasury; 31,269 shares as of September 30, 2017 and December 31, 2016
(1)
(1)
Total equity
1,652
917
Total liabilities and equity
$
7,202
$
7,076
STATEMENTS OF CASH FLOWS (Unaudited)
Southwestern Energy Company and Subsidiaries
For the nine months ended
September 30,
2017
2016
(in millions)
Cash Flows From Operating Activities
Net income (loss)
$
712
$
(2,433)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
364
349
Impairment of natural gas and oil properties
-
2,321
Amortization of debt issuance costs
7
12
Deferred income taxes
(4)
(20)
(Gain) loss on derivatives, unsettled
(350)
48
Stock-based compensation
19
24
Restructuring charges
-
30
Loss on early extinguishment of debt
70
51
Other
(2)
5
Change in assets and liabilities
(27)
(50)
Net cash provided by operating activities
789
337
Cash Flows From Investing Activities
Capital investments
(943)
(391)
Proceeds from sale of property and equipment
17
434
Other
5
-
Net cash provided by (used in) investing activities
(921)
43
Cash Flows From Financing Activities
Payments on short-term debt
(287)
(1)
Payments on long-term debt
(1,139)
(1,175)
Payments on revolving credit facility
-
(3,268)
Borrowings under revolving credit facility
-
3,152
Payments on commercial paper
-
(242)
Borrowings under commercial paper
-
242
Change in bank drafts outstanding
-
(19)
Proceeds from issuance of long-term debt
1,150
1,191
Debt issuance costs
(18)
(17)
Proceeds from issuance of common stock
-
1,247
Preferred stock dividend
(8)
(27)
Other
-
(4)
Net cash provided by (used in) financing activities
(302)
1,079
Increase (decrease) in cash and cash equivalents
(434)
1,459
Cash and cash equivalents at beginning of year
1,423
15
Cash and cash equivalents at end of period
$
989
$
1,474
SEGMENT INFORMATION (Unaudited)
Southwestern Energy Company and Subsidiaries
Exploration and Production
Midstream Services
Other
Eliminations
Total
(in millions)
Three months ended September 30, 2017
Revenues
$
470
$
734
$
-
$
(467)
$
737
Marketing purchases
-
645
-
(409)
236
Operating expenses
210
18
-
(58)
170
General and administrative expenses
54
8
-
-
62
Depreciation, depletion and amortization
120
15
-
-
135
Taxes, other than income taxes
22
2
-
-
24
Operating income
64
46
-
-
110
Capital investments (1)
320
9
2
-
331
Three months ended September 30, 2016
Revenues
$
378
$
682
$
-
$
(409)
$
651
Marketing purchases
-
578
-
(344)
234
Operating expenses
181
23
-
(65)
139
General and administrative expenses
50
11
-
-
61
Restructuring charges
2
-
-
-
2
Depreciation, depletion and amortization
83
16
-
-
99
Impairment of natural gas and oil properties
817
-
-
-
817
Taxes, other than income taxes
22
2
-
-
24
Operating income (loss)
(777)
52
-
-
(725)
Capital investments (1)
179
1
-
-
180
Nine months ended September 30, 2017
Revenues
$
1,559
$
2,414
$
-
$
(1,579)
$
2,394
Marketing purchases
-
2,141
-
(1,401)
740
Operating expenses
591
68
-
(178)
481
General and administrative expenses
147
23
-
-
170
Depreciation, depletion and amortization
317
47
-
-
364
Taxes, other than income taxes
69
6
-
-
75
Operating income
435
129
-
-
564
Capital investments (1)
921
21
4
-
946
Nine months ended September 30, 2016
Revenues
$
998
$
1,862
$
-
$
(1,108)
$
1,752
Marketing purchases
-
1,533
-
(906)
627
Operating expenses
586
71
-
(202)
455
General and administrative expenses
141
30
-
-
171
Restructuring charges
74
3
-
-
77
Depreciation, depletion and amortization
300
49
-
-
349
Impairment of natural gas and oil properties
2,321
-
-
-
2,321
Taxes, other than income taxes
62
7
-
-
69
Operating income (loss)
(2,486)
169
-
-
(2,317)
Capital investments (1)
372
3
1
-
376
(1) Capital investments includes a decrease of $2 million and an increase of $27 million for the three months ended September 30, 2017 and 2016, respectively, and decreases of $13 million and $24 million for the nine months ended September 30, 2017 and 2016, respectively, relating to the change in capital accruals between periods.

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SOURCE Southwestern Energy Company

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