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 and
Year-end 2016 Financial Results
|
Southwestern Energy
Company and Subsidiaries
|
|
For the three months
ended
|
|
For the year
ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
(in millions, except
per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
(loss)
|
$
|
122
|
|
$
|
(2,561)
|
|
$
|
(2,195)
|
|
$
|
(6,522)
|
Adjusted operating
income (non-GAAP measure)
|
$
|
134
|
|
$
|
8
|
|
$
|
215
|
|
$
|
146
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable
to common stock
|
$
|
(237)
|
|
$
|
(2,134)
|
|
$
|
(2,751)
|
|
$
|
(4,662)
|
Adjusted net income
(loss) attributable to common stock (non-GAAP measure)
|
$
|
39
|
|
$
|
(6)
|
|
$
|
(7)
|
|
$
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per
share
|
$
|
(0.48)
|
|
$
|
(5.58)
|
|
$
|
(6.32)
|
|
$
|
(12.25)
|
Adjusted earnings
(loss) per share (non-GAAP measure)
|
$
|
0.08
|
|
$
|
(0.02)
|
|
$
|
(0.01)
|
|
$
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operating activities
|
$
|
161
|
|
$
|
353
|
|
$
|
498
|
|
$
|
1,580
|
Net cash flow
(non-GAAP measure)
|
$
|
211
|
|
$
|
306
|
|
$
|
645
|
|
$
|
1,468
|
|
|
|
|
Exploration and
Production 2016 Financial Results
|
For the three months
ended
|
|
For the year
ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
Fayetteville
(Bcf)
|
|
86
|
|
|
112
|
|
|
375
|
|
|
465
|
Northeast Appalachia
(Bcf)
|
|
82
|
|
|
97
|
|
|
350
|
|
|
360
|
Southwest Appalachia
(Bcfe)
|
|
33
|
|
|
40
|
|
|
148
|
|
|
143
|
Other (Bcfe)
|
|
1
|
|
|
-
|
|
|
2
|
|
|
8
|
Total
production (Bcfe)
|
|
202
|
|
|
249
|
|
|
875
|
|
|
976
|
% Natural
Gas
|
|
90%
|
|
|
91%
|
|
|
90%
|
|
|
92%
|
|
|
|
|
|
|
|
|
|
|
|
|
Average unit costs
per Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
0.87
|
|
$
|
0.91
|
|
$
|
0.87
|
|
$
|
0.92
|
General &
administrative expenses(1)
|
$
|
0.27
|
|
$
|
0.20
|
|
$
|
0.22
|
|
$
|
0.21
|
Taxes, other than
income taxes(2)
|
$
|
0.11
|
|
$
|
0.09
|
|
$
|
0.10
|
|
$
|
0.10
|
Full cost pool
amortization
|
$
|
0.30
|
|
$
|
0.78
|
|
$
|
0.38
|
|
$
|
1.00
|
|
|
(1)
|
Excludes
restructuring and other one-time charges for the three months and
year ended December 31, 2016, respectively.
|
(2)
|
Excludes
restructuring charges for the year ended December 31,
2016.
|
|
|
|
|
Realized
Prices
|
For the three months
ended
|
|
For the year
ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Natural Gas
Price:
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Henry Hub Price
($/MMBtu)(1)
|
$
|
2.98
|
|
$
|
2.27
|
|
$
|
2.46
|
|
$
|
2.66
|
Discount to
NYMEX(2)
|
$
|
(0.98)
|
|
$
|
(0.79)
|
|
$
|
(0.87)
|
|
$
|
(0.75)
|
Average realized gas
price per Mcf, excluding hedges
|
$
|
2.00
|
|
$
|
1.48
|
|
$
|
1.59
|
|
$
|
1.91
|
Gain
(loss) on settled financial basis derivatives ($/Mcf)
|
$
|
0.09
|
|
$
|
0.02
|
|
$
|
0.03
|
|
$
|
(0.00)
|
Gain
(loss) on settled commodity derivatives ($/Mcf)
|
$
|
(0.02)
|
|
$
|
0.57
|
|
$
|
0.02
|
|
$
|
0.46
|
Average realized gas
price per Mcf, including hedges
|
$
|
2.07
|
|
$
|
2.07
|
|
$
|
1.64
|
|
$
|
2.37
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Price:
|
|
|
|
|
|
|
|
|
|
|
|
WTI oil price
($/Bbl)
|
$
|
49.29
|
|
$
|
42.18
|
|
$
|
43.32
|
|
$
|
48.80
|
Discount to
WTI
|
$
|
(8.11)
|
|
$
|
(14.82)
|
|
$
|
(12.12)
|
|
$
|
(15.55)
|
Average
oil price per Bbl
|
$
|
41.18
|
|
$
|
27.36
|
|
$
|
31.20
|
|
$
|
33.25
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL
Price:
|
|
|
|
|
|
|
|
|
|
|
|
Average net realized
NGL price per Bbl
|
$
|
12.08
|
|
$
|
7.62
|
|
$
|
7.46
|
|
$
|
6.80
|
Percentage of
WTI
|
|
25%
|
|
|
18%
|
|
|
17%
|
|
|
14%
|
|
|
(1)
|
Based on last day
settlement prices from monthly futures contracts.
|
(2)
|
This discount
includes a basis differential, physical basis hedges, third-party
transportation charges and fuel charges and excludes financial
basis hedges.
|
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:
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
Oil
|
|
NGL
|
|
Total
|
|
(Bcf)
|
|
(MBbls)
|
|
(MBbls)
|
|
(Bcfe)
|
|
|
|
|
|
|
|
|
Proved reserves,
beginning of year
|
5,917
|
|
8,753
|
|
40,947
|
|
6,215
|
Revisions of previous
estimates
|
(446)
|
|
1,564
|
|
13,794
|
|
(354)
|
Extensions, discoveries and other
additions
|
198
|
|
2,417
|
|
11,576
|
|
282
|
Production
|
(788)
|
|
(2,192)
|
|
(12,372)
|
|
(875)
|
Acquisition of reserves in
place
|
–
|
|
–
|
|
–
|
|
–
|
Disposition of reserves in
place
|
(15)
|
|
(19)
|
|
(14)
|
|
(15)
|
Proved reserves,
end of year
|
4,866
|
|
10,523
|
|
53,931
|
|
5,253
|
|
|
|
|
|
|
|
|
Proved developed
reserves:
|
|
|
|
|
|
|
|
Beginning of
year
|
5,474
|
|
8,753
|
|
40,947
|
|
5,772
|
End of
year
|
4,789
|
|
10,523
|
|
53,931
|
|
5,176
|
|
Note: Amounts may not
add due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 PROVED
RESERVES BY DIVISION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia
|
|
Fayetteville
|
|
|
|
|
|
|
Northeast
|
|
Southwest
|
|
Shale
|
|
Other
|
|
Total
|
Estimated Proved
Reserves (Bcfe):
|
|
|
|
|
|
|
|
|
|
|
Reserves, beginning of
year
|
|
2,319
|
|
611
|
|
3,281
|
|
4
|
|
6,215
|
Production
|
|
(350)
|
|
(148)
|
|
(375)
|
|
(2)
|
|
(875)
|
Extensions,
discoveries and other additions
|
|
81
|
|
157
|
|
44
|
|
–
|
|
282
|
Disposition of
reserves in place
|
|
–
|
|
(15)
|
|
–
|
|
–
|
|
(15)
|
Price
revisions
|
|
(794)
|
|
(127)
|
|
(116)
|
|
–
|
|
(1,037)
|
Performance &
production revisions
|
|
318
|
|
199
|
|
163
|
|
3
|
|
683
|
Reserves, end of year
|
|
1,574
|
|
677
|
|
2,997
|
|
5
|
|
5,253
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 PROVED
RESERVES BY CATEGORY AND SUMMARY OPERATING DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia
|
|
Fayetteville
|
|
|
|
|
|
|
Northeast
|
|
Southwest
|
|
Shale
|
|
Other
(1)
|
|
Total
|
Estimated Proved
Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
(Bcf)
|
|
1,540
|
|
|
293
|
|
|
2,954
|
|
|
2
|
|
|
4,789
|
Undeveloped
(Bcf)
|
|
34
|
|
|
–
|
|
|
43
|
|
|
–
|
|
|
77
|
|
|
1,574
|
|
|
293
|
|
|
2,997
|
|
|
2
|
|
|
4,866
|
Crude Oil
(MMBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
(MMBbls)
|
|
–
|
|
|
10.2
|
|
|
–
|
|
|
0.3
|
|
|
10.5
|
Undeveloped
(MMBbls)
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
10.2
|
|
|
–
|
|
|
0.3
|
|
|
10.5
|
Natural Gas Liquids
(MMBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
(MMBbls)
|
|
–
|
|
|
53.8
|
|
|
–
|
|
|
0.1
|
|
|
53.9
|
Undeveloped
(MMBbls)
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
53.8
|
|
|
–
|
|
|
0.1
|
|
|
53.9
|
Total Proved Reserves
(Bcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
(Bcfe)
|
|
1,540
|
|
|
677
|
|
|
2,954
|
|
|
5
|
|
|
5,176
|
Undeveloped
(Bcfe)
|
|
34
|
|
|
–
|
|
|
43
|
|
|
–
|
|
|
77
|
|
|
1,574
|
|
|
677
|
|
|
2,997
|
|
|
5
|
|
|
5,253
|
Percent of
Total
|
|
30%
|
|
|
13%
|
|
|
57%
|
|
|
0%
|
|
|
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent Proved
Developed
|
|
98%
|
|
|
100%
|
|
|
99%
|
|
|
100%
|
|
|
99%
|
Percent Proved
Undeveloped
|
|
2%
|
|
|
0%
|
|
|
1%
|
|
|
0%
|
|
|
1%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
(Bcfe)
|
|
350
|
|
|
148
|
|
|
375
|
|
|
2
|
|
|
875
|
Capital Investments
(millions)(2)
|
$
|
204
|
|
$
|
288
|
|
$
|
86
|
|
$
|
19
|
|
$
|
597
|
Total Gross Producing
Wells(3)
|
|
820
|
|
|
306
|
|
|
4,217
|
|
|
16
|
|
|
5,359
|
Total Net Producing
Wells(3)
|
|
439
|
|
|
216
|
|
|
2,932
|
|
|
13
|
|
|
3,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net
Acreage
|
|
245,805
|
|
|
321,563
|
|
|
918,535
|
|
|
3,023,386
|
|
|
4,509,289
|
Net Undeveloped
Acreage
|
|
146,096
|
|
|
161,607
|
|
|
285,692
|
|
|
3,010,908
|
|
|
3,604,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Tax
(millions)(4)
|
$
|
183
|
|
$
|
163
|
|
$
|
1,325
|
|
$
|
(6)
|
|
$
|
1,665
|
PV of Taxes
(millions)(4)
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
–
|
After-Tax
(millions)(4)
|
$
|
183
|
|
$
|
163
|
|
$
|
1,325
|
|
$
|
(6)
|
|
$
|
1,665
|
Percent of
Total
|
|
11%
|
|
|
10%
|
|
|
79%
|
|
|
0%
|
|
|
100%
|
Percent
Operated(5)
|
|
95%
|
|
|
100%
|
|
|
99%
|
|
|
100%
|
|
|
98%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Other consists
primarily of properties in Canada (which are subject to a
moratorium), Colorado and Louisiana.
|
(2)
|
Total and Other
capital investments excludes $26 million related to our E&P
service companies.
|
(3)
|
Represents all
producing wells, including wells in which we only have an
overriding royalty interest, as of December 31, 2016.
|
(4)
|
Pre-tax PV-10 (a
non-GAAP measure) is one measure of the value of a company's proved
reserves that we believe is used by securities analysts to compare
relative values among peer companies without regard to income
taxes. The reconciling difference in pre-tax PV-10 and the
after-tax PV-10, or standardized measure, is the discounted value
of future income taxes on the estimated cash flows from our proved
natural gas, oil and NGL reserves.
|
(5)
|
Based upon pre-tax
PV-10 of proved developed producing activities.
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL COMPANY PDP
F&D
|
|
|
|
Three-Year
|
|
12 Months Ended
December 31,
|
|
Average
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
Total PDP Adds
(Bcfe):
|
|
|
|
|
|
|
|
|
|
|
|
New PDP adds
|
|
257
|
|
|
416
|
|
|
531
|
|
|
1,204
|
PUD
conversions
|
|
220
|
|
|
1,044
|
|
|
790
|
|
|
2,054
|
Total PDP
Adds
|
|
477
|
|
|
1,460
|
|
|
1,321
|
|
|
3,258
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
acquisition costs
|
$
|
–
|
|
$
|
81
|
|
$
|
1,455
|
|
$
|
1,536
|
Unproved property
acquisition costs
|
|
171
|
|
|
692
|
|
|
3,934
|
|
|
4,797
|
Exploration
costs
|
|
17
|
|
|
50
|
|
|
232
|
|
|
299
|
Development
costs
|
|
433
|
|
|
1,417
|
|
|
1,600
|
|
|
3,450
|
Capitalized
Costs Incurred
|
$
|
621
|
|
$
|
2,240
|
|
$
|
7,221
|
|
$
|
10,082
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtract (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
acquisition costs
|
$
|
–
|
|
$
|
(81)
|
|
$
|
(1,455)
|
|
$
|
(1,536)
|
Unproved property
acquisition costs
|
|
(171)
|
|
|
(692)
|
|
|
(3,934)
|
|
|
(4,797)
|
Capitalized interest
and expense(1) associated with development and
exploration
|
|
(91)
|
|
|
(187)
|
|
|
(206)
|
|
|
(484)
|
PDP Costs
Incurred
|
$
|
359
|
|
$
|
1,280
|
|
$
|
1,626
|
|
$
|
3,265
|
|
|
|
|
|
|
|
|
|
|
|
|
PDP
F&D
|
$
|
0.75
|
|
$
|
0.88
|
|
$
|
1.23
|
|
$
|
1.00
|
|
Note: Amounts may not
add due to rounding
|
(1)
|
Adjusting for the
impacts of the full cost accounting method for
comparability.
|
|
|
|
|
DIVISION PDP
F&D
|
|
12 Months Ended
December 31, 2016
|
|
Appalachia
|
|
Fayetteville
|
|
|
|
|
|
Northeast
|
|
Southwest
|
|
Shale
|
|
Other
|
|
Total
|
Total PDP Adds
(Bcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New PDP adds
|
|
81
|
|
|
157
|
|
|
19
|
|
|
–
|
|
|
257
|
PUD
conversions
|
|
181
|
|
|
–
|
|
|
39
|
|
|
–
|
|
|
220
|
Total PDP
Adds
|
|
262
|
|
|
157
|
|
|
58
|
|
|
–
|
|
|
477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
acquisition costs
|
$
|
–
|
|
$
|
–
|
|
$
|
–
|
|
$
|
–
|
|
$
|
–
|
Unproved property
acquisition costs
|
|
11
|
|
|
149
|
|
|
3
|
|
|
8
|
|
|
171
|
Exploration
costs
|
|
8
|
|
|
8
|
|
|
1
|
|
|
–
|
|
|
17
|
Development
costs
|
|
178
|
|
|
133
|
|
|
86
|
|
|
36
|
|
|
433
|
Capitalized
Costs Incurred
|
$
|
197
|
|
$
|
290
|
|
$
|
90
|
|
$
|
44
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtract (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
acquisition costs
|
$
|
–
|
|
$
|
–
|
|
$
|
–
|
|
$
|
–
|
|
$
|
–
|
Unproved property
acquisition costs
|
|
(11)
|
|
|
(149)
|
|
|
(3)
|
|
|
(8)
|
|
|
(171)
|
Capitalized interest
and expense(1) associated with development and
exploration
|
|
(31)
|
|
|
(28)
|
|
|
(21)
|
|
|
(11)
|
|
|
(91)
|
PDP Costs
Incurred
|
$
|
155
|
|
$
|
113
|
|
$
|
66
|
|
$
|
25
|
|
$
|
359
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PDP
F&D
|
$
|
0.59
|
|
$
|
0.72
|
|
$
|
1.14
|
|
$
|
–
|
|
$
|
0.75
|
|
Note: Amounts may not
add due to rounding
|
(1)
|
Adjusting for the
impacts of the full cost accounting method for
comparability.
|
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.
|
|
|
|
|
|
|
For the years ended
December
31,
|
|
2016
|
|
2015
|
E&P Capital
Investments by Type
|
(in
millions)
|
Exploratory and
development drilling, including workovers
|
$
|
358
|
|
$
|
1,226
|
Acquisitions and
leasehold
|
|
23
|
|
|
607
|
Seismic
expenditures
|
|
1
|
|
|
6
|
Drilling rigs, sand
facility and other
|
|
2
|
|
|
40
|
Capitalized interest
and expense
|
|
239
|
|
|
379
|
Total E&P capital
investments
|
$
|
623
|
|
$
|
2,258
|
|
|
|
|
|
|
E&P Capital
Investments by Area
|
|
|
|
|
|
Northeast
Appalachia
|
$
|
165
|
|
$
|
652
|
Southwest
Appalachia
|
|
130
|
|
|
659
|
Fayetteville
Shale
|
|
65
|
|
|
496
|
New
Ventures
|
|
(2)
|
|
|
48
|
E&P Services &
Other
|
|
26
|
|
|
24
|
Capitalized interest
and expense
|
|
239
|
|
|
379
|
Total E&P capital
investments
|
$
|
623
|
|
$
|
2,258
|
|
|
|
|
|
|
|
|
|
Year-end 2016
E&P Division Results
|
|
|
|
|
|
|
|
|
|
Appalachia
|
|
Fayetteville
|
|
Northeast
|
|
Southwest
|
|
Shale
|
Production
(Bcfe)
|
|
350
|
|
|
148
|
|
|
375
|
Gross operated
production at year-end 2016 (Mmcfe/d)
|
|
1,138
|
|
|
577
|
|
|
1,377
|
|
|
|
|
|
|
|
|
|
Reserves:
|
|
|
|
|
|
|
|
|
Reserves
(Bcfe)
|
|
1,574
|
|
|
677
|
|
|
2,997
|
|
|
|
|
|
|
|
|
|
Capital
investments ($ in millions)
|
|
|
|
|
|
|
|
|
Exploratory and
development drilling, including workovers
|
$
|
160
|
|
$
|
111
|
|
$
|
63
|
Acquisition and
leasehold
|
|
3
|
|
|
18
|
|
|
2
|
Seismic and
other
|
|
2
|
|
|
1
|
|
|
-
|
Capitalized interest
and expense
|
|
39
|
|
|
158
|
|
|
21
|
Total capital
investments
|
$
|
204
|
|
$
|
288
|
|
$
|
86
|
|
|
|
|
|
|
|
|
|
Gross operated
well count summary
|
|
|
|
|
|
|
|
|
Drilled
|
|
37
|
|
|
15
|
|
|
10
|
Completed
|
|
33
|
|
|
17
|
|
|
36
|
Wells to
sales
|
|
24
|
|
|
18
|
|
|
43
|
Wells in
progress
|
|
73
|
|
|
42
|
|
|
20
|
Year-end drilled
uncompleted wells
|
|
46
|
|
|
40
|
|
|
13
|
|
|
|
|
|
|
|
|
|
Realized
price
|
|
|
|
|
|
|
|
|
NYMEX Henry Hub price
($/MMBtu)
|
$
|
2.46
|
|
$
|
2.46
|
|
$
|
2.46
|
Discount to NYMEX
($/Mcf)
|
$
|
(1.12)
|
|
$
|
(0.75)
|
|
$
|
(0.66)
|
Average realized gas
price, excluding hedges ($/Mcf)
|
$
|
1.34
|
|
$
|
1.71
|
|
$
|
1.80
|
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.
|
|
|
|
|
|
|
3 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Net income (loss)
attributable to common stock:
|
|
|
|
|
|
Net loss attributable
to common stock
|
$
|
(237)
|
|
$
|
(2,134)
|
Add back:
|
|
|
|
|
|
Participating securities - mandatory convertible preferred
stock
|
|
(6)
|
|
|
–
|
Impairment of natural
gas and oil properties
|
|
–
|
|
|
2,576
|
Restructuring and other
one-time charges
|
|
12
|
|
|
–
|
Gain on sale of assets,
net
|
|
–
|
|
|
(7)
|
Transaction
costs
|
|
–
|
|
|
1
|
Loss on certain
derivatives
|
|
324
|
|
|
50
|
Adjustments due to
inventory valuation
|
|
–
|
|
|
32
|
Adjustments due to
discrete tax items(1)
|
|
74
|
|
|
483
|
Tax impact on
adjustments
|
|
(128)
|
|
|
(1,007)
|
Adjusted net income
(loss) attributable to common stock
|
$
|
39
|
|
$
|
(6)
|
|
|
(1)
|
Primarily relates to
the exclusion of certain discrete tax adjustments in the fourth
quarter of 2016 due to an increase to the valuation allowance
against the Company's 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
December 31,
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Diluted earnings
(loss) per share:
|
|
|
|
|
|
Diluted loss per
share
|
$
|
(0.48)
|
|
$
|
(5.58)
|
Add back:
|
|
|
|
|
|
Participating
securities - mandatory convertible preferred stock
|
|
(0.01)
|
|
|
–
|
Impairment of natural
gas and oil properties
|
|
–
|
|
|
6.74
|
Restructuring and other
one-time charges
|
|
0.02
|
|
|
–
|
Gain on sale of assets,
net
|
|
–
|
|
|
(0.02)
|
Transaction
costs
|
|
–
|
|
|
0.00
|
Loss on certain
derivatives
|
|
0.66
|
|
|
0.13
|
Adjustments due to
inventory valuation
|
|
–
|
|
|
0.08
|
Adjustments due to
discrete tax items(1)
|
|
0.15
|
|
|
1.26
|
Tax impact on
adjustments
|
|
(0.26)
|
|
|
(2.63)
|
Adjusted diluted
earnings (loss) per share
|
$
|
0.08
|
|
$
|
(0.02)
|
|
|
(1)
|
Primarily relates to
the exclusion of certain discrete tax adjustments in the fourth
quarter of 2016 due to an increase to the valuation allowance
against the Company's deferred tax assets. The Company
expects its 2017 income tax rate to be 38.0% before the impacts of
any valuation allowance.
|
|
|
|
|
|
|
|
|
|
12 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Net income (loss)
attributable to common stock:
|
|
|
|
|
|
Net loss attributable
to common stock
|
$
|
(2,751)
|
|
$
|
(4,662)
|
Add back:
|
|
|
|
|
|
Participating
securities – mandatory convertible preferred stock
|
|
–
|
|
|
(13)
|
Impairment of natural
gas and oil properties
|
|
2,321
|
|
|
6,950
|
Restructuring and other
one-time charges
|
|
89
|
|
|
2
|
Gain on sale of assets,
net
|
|
(3)
|
|
|
(283)
|
Loss on early
extinguishment of debt and other(1)
|
|
57
|
|
|
–
|
Transaction
costs
|
|
–
|
|
|
54
|
Loss on certain
derivatives
|
|
373
|
|
|
155
|
Adjustments due to
inventory valuation
|
|
3
|
|
|
32
|
Adjustments due to
discrete tax items(2)
|
|
978
|
|
|
483
|
Tax impact on
adjustments
|
|
(1,074)
|
|
|
(2,647)
|
Adjusted net income
(loss) attributable to common stock
|
$
|
(7)
|
|
$
|
71
|
|
|
(1)
|
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 charges.
|
(2)
|
Primarily relates to
the exclusion of certain discrete tax adjustments due to an
increase to the valuation allowance against the Company's deferred
tax assets. The Company expects its 2017 income tax rate to
be 38.0% before the impacts of any valuation allowance.
|
|
|
|
|
|
|
|
|
|
12 Months
Ended December 31,
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Diluted earnings
(loss) per share:
|
|
|
|
|
|
Diluted loss per
share
|
$
|
(6.32)
|
|
$
|
(12.25)
|
Add back:
|
|
|
|
|
|
Participating
securities – mandatory convertible preferred stock
|
|
–
|
|
|
(0.03)
|
Impairment of natural
gas and oil properties
|
|
5.33
|
|
|
18.26
|
Restructuring and other
one-time charges
|
|
0.20
|
|
|
0.01
|
Gain on sale of assets,
net
|
|
(0.00)
|
|
|
(0.74)
|
Loss on early
extinguishment of debt and other(1)
|
|
0.13
|
|
|
–
|
Transaction
costs
|
|
–
|
|
|
0.14
|
Loss on certain
derivatives
|
|
0.86
|
|
|
0.41
|
Adjustments due to
inventory valuation
|
|
0.01
|
|
|
0.08
|
Adjustments due to
discrete tax items(2)
|
|
2.25
|
|
|
1.27
|
Tax impact on
adjustments
|
|
(2.47)
|
|
|
(6.96)
|
Adjusted diluted
earnings (loss) per share
|
$
|
(0.01)
|
|
$
|
0.19
|
|
|
(1)
|
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 charges.
|
(2)
|
Primarily relates to
the exclusion of certain discrete tax adjustments due to an
increase to the valuation allowance against the Company's 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
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Cash flow from
operating activities:
|
|
|
|
|
|
Net cash provided by
operating activities
|
$
|
161
|
|
$
|
353
|
Add back:
|
|
|
|
|
|
Changes in operating
assets and liabilities
|
|
49
|
|
|
(47)
|
Restructuring
charges
|
|
1
|
|
|
–
|
Net cash
flow
|
$
|
211
|
|
$
|
306
|
|
|
|
|
|
|
|
12 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Cash flow from
operating activities:
|
|
|
|
|
|
Net cash provided by
operating activities
|
$
|
498
|
|
$
|
1,580
|
Add back:
|
|
|
|
|
|
Changes in operating
assets and liabilities
|
|
99
|
|
|
(112)
|
Restructuring
charges
|
|
48
|
|
|
–
|
Net cash
flow
|
$
|
645
|
|
$
|
1,468
|
|
|
|
|
|
|
|
3 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Operating income
(loss):
|
|
|
|
|
|
Operating income
(loss)
|
$
|
122
|
|
$
|
(2,561)
|
Add back:
|
|
|
|
|
|
Impairment of natural
gas and oil properties
|
|
–
|
|
|
2,576
|
Gain on sale of assets,
net
|
|
–
|
|
|
(7)
|
Restructuring and other
one-time charges
|
|
12
|
|
|
–
|
Adjusted operating
income
|
$
|
134
|
|
$
|
8
|
|
|
|
|
|
|
|
12 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Operating income
(loss):
|
|
|
|
|
|
Operating
loss
|
$
|
(2,195)
|
|
$
|
(6,522)
|
Add back:
|
|
|
|
|
|
Impairment of natural
gas and oil properties
|
|
2,321
|
|
|
6,950
|
Gain on sale of assets,
net
|
|
–
|
|
|
(283)
|
Restructuring and other
one-time charges
|
|
89
|
|
|
1
|
Adjusted operating
income
|
$
|
215
|
|
$
|
146
|
|
|
|
|
|
|
|
3 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
E&P segment
operating income (loss):
|
|
|
|
|
|
E&P segment
operating income (loss)
|
$
|
82
|
|
$
|
(2,633)
|
Add back:
|
|
|
|
|
|
Impairment of natural
gas and oil properties
|
|
–
|
|
|
2,576
|
Gain on sale of assets,
net
|
|
–
|
|
|
(7)
|
Restructuring and other
one-time charges
|
|
12
|
|
|
–
|
Adjusted E&P
segment operating income (loss)
|
$
|
94
|
|
$
|
(64)
|
|
|
|
|
|
|
|
12 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
E&P segment
operating income (loss):
|
|
|
|
|
|
E&P segment
operating loss
|
$
|
(2,404)
|
|
$
|
(7,104)
|
Add back:
|
|
|
|
|
|
Impairment of natural
gas and oil properties
|
|
2,321
|
|
|
6,950
|
Gain on sale of assets,
net
|
|
–
|
|
|
(6)
|
Restructuring and other
one-time charges
|
|
86
|
|
|
1
|
Adjusted E&P
segment operating income (loss)
|
$
|
3
|
|
$
|
(159)
|
|
|
|
|
|
|
|
12 Months Ended
December 31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Midstream segment
operating income:
|
|
|
|
|
|
Midstream segment
operating income
|
$
|
209
|
|
$
|
583
|
Add back:
|
|
|
|
|
|
Restructuring
charges
|
|
3
|
|
|
–
|
Gain on sale of assets,
net
|
|
–
|
|
|
(277)
|
Adjusted Midstream
segment operating income
|
$
|
212
|
|
$
|
306
|
|
|
|
|
|
|
|
December
31,
|
|
2016
|
|
2015
|
|
(in
millions)
|
Net
debt:
|
|
|
|
|
|
Total debt
|
$
|
4,653
|
|
$
|
4,705
|
Subtract:
|
|
|
|
|
|
Cash and cash
equivalents
|
|
(1,423)
|
|
|
(15)
|
Net debt
|
$
|
3,230
|
|
$
|
4,690
|
Southwestern management will host a teleconference call on
Friday, February 24, 2016 at
10:00 a.m. Eastern to discuss its
fourth quarter and year-end 2016 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
STATISTICS (Unaudited)
|
|
Southwestern Energy
Company and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three
months
ended
|
|
For the years
ended
|
|
|
December
31,
|
|
December
31,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Exploration &
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas production
(Bcf)
|
|
|
183
|
|
|
226
|
|
|
788
|
|
|
899
|
Oil production
(MBbls)
|
|
|
463
|
|
|
569
|
|
|
2,192
|
|
|
2,265
|
NGL production
(MBbls)
|
|
|
2,792
|
|
|
3,328
|
|
|
12,372
|
|
|
10,702
|
Total production
(Bcfe)
|
|
|
202
|
|
|
249
|
|
|
875
|
|
|
976
|
Commodity
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized gas
price per Mcf, including derivatives
|
|
$
|
2.07
|
|
$
|
2.07
|
|
$
|
1.64
|
|
$
|
2.37
|
Average realized gas
price per Mcf, excluding derivatives
|
|
$
|
2.00
|
|
$
|
1.48
|
|
$
|
1.59
|
|
$
|
1.91
|
Average realized oil
price per Bbl
|
|
$
|
41.18
|
|
$
|
27.36
|
|
$
|
31.20
|
|
$
|
33.25
|
Average realized NGL
price per Bbl
|
|
$
|
12.08
|
|
$
|
7.62
|
|
$
|
7.46
|
|
$
|
6.80
|
Summary of
Derivative Activity in the Statement of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Settled commodity
amounts included in "Operating Revenues" (in millions)
|
|
$
|
–
|
|
$
|
64
|
|
$
|
–
|
|
$
|
209
|
Settled commodity
amounts included in "Gain (Loss) on Derivatives" (in
millions)
|
|
$
|
14
|
|
$
|
69
|
|
$
|
36
|
|
$
|
206
|
Unsettled commodity
amounts included in "Gain (Loss) on Derivatives" (in
millions)
|
|
$
|
(330)
|
|
$
|
(50)
|
|
$
|
(375)
|
|
$
|
(153)
|
Average unit costs
per Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
|
$
|
0.87
|
|
$
|
0.91
|
|
$
|
0.87
|
|
$
|
0.92
|
General &
administrative expenses (1)
|
|
$
|
0.27
|
|
$
|
0.20
|
|
$
|
0.22
|
|
$
|
0.21
|
Taxes, other than
income taxes (2)
|
|
$
|
0.11
|
|
$
|
0.09
|
|
$
|
0.10
|
|
$
|
0.10
|
Full cost pool
amortization
|
|
$
|
0.30
|
|
$
|
0.78
|
|
$
|
0.38
|
|
$
|
1.00
|
Midstream
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes marketed
(Bcfe)
|
|
|
248
|
|
|
290
|
|
|
1,062
|
|
|
1,127
|
Volumes gathered
(Bcf)
|
|
|
138
|
|
|
179
|
|
|
601
|
|
|
799
|
|
|
(1)
|
Excludes $12 million
and $83 million of restructuring and other one-time charges for the
three months and year ended December 31, 2016,
respectively.
|
(2)
|
Excludes $3 million
of restructuring charges for the year ended December 31,
2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF
OPERATIONS (Unaudited)
|
|
Southwestern Energy
Company and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months
ended
|
|
For the years
ended
|
|
|
December
31,
|
|
December
31,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
(in millions, except
share/per share amounts)
|
Operating
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
367
|
|
$
|
406
|
|
$
|
1,273
|
|
$
|
1,946
|
Oil sales
|
|
|
19
|
|
|
16
|
|
|
69
|
|
|
76
|
NGL sales
|
|
|
33
|
|
|
26
|
|
|
92
|
|
|
73
|
Marketing
|
|
|
233
|
|
|
200
|
|
|
864
|
|
|
863
|
Gas
gathering
|
|
|
32
|
|
|
39
|
|
|
138
|
|
|
175
|
|
|
|
684
|
|
|
687
|
|
|
2,436
|
|
|
3,133
|
Operating Costs
and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
purchases
|
|
|
237
|
|
|
198
|
|
|
864
|
|
|
852
|
Operating
expenses
|
|
|
137
|
|
|
182
|
|
|
592
|
|
|
689
|
General and
administrative expenses
|
|
|
76
|
|
|
58
|
|
|
247
|
|
|
246
|
Restructuring
charges
|
|
|
1
|
|
|
–
|
|
|
78
|
|
|
–
|
Depreciation, depletion
and amortization
|
|
|
87
|
|
|
215
|
|
|
436
|
|
|
1,091
|
Impairment of natural
gas and oil properties
|
|
|
–
|
|
|
2,576
|
|
|
2,321
|
|
|
6,950
|
Gain on sale of assets,
net
|
|
|
–
|
|
|
(7)
|
|
|
–
|
|
|
(283)
|
Taxes, other than
income taxes
|
|
|
24
|
|
|
26
|
|
|
93
|
|
|
110
|
|
|
|
562
|
|
|
3,248
|
|
|
4,631
|
|
|
9,655
|
Operating Income
(Loss)
|
|
|
122
|
|
|
(2,561)
|
|
|
(2,195)
|
|
|
(6,522)
|
Interest
Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on
debt
|
|
|
58
|
|
|
47
|
|
|
226
|
|
|
200
|
Other interest
charges
|
|
|
2
|
|
|
6
|
|
|
14
|
|
|
60
|
Interest
capitalized
|
|
|
(29)
|
|
|
(49)
|
|
|
(152)
|
|
|
(204)
|
|
|
|
31
|
|
|
4
|
|
|
88
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) on
Derivatives
|
|
|
(311)
|
|
|
17
|
|
|
(339)
|
|
|
47
|
Loss on Early
Extinguishment of Debt
|
|
|
–
|
|
|
–
|
|
|
(51)
|
|
|
–
|
Other Income
(Loss), Net
|
|
|
1
|
|
|
(32)
|
|
|
1
|
|
|
(30)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Income
Taxes
|
|
|
(219)
|
|
|
(2,580)
|
|
|
(2,672)
|
|
|
(6,561)
|
Income Tax
benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(7)
|
|
|
(9)
|
|
|
(7)
|
|
|
(2)
|
Deferred
|
|
|
(2)
|
|
|
(464)
|
|
|
(22)
|
|
|
(2,003)
|
|
|
|
(9)
|
|
|
(473)
|
|
|
(29)
|
|
|
(2,005)
|
Net
Loss
|
|
|
(210)
|
|
|
(2,107)
|
|
|
(2,643)
|
|
|
(4,556)
|
Mandatory convertible
preferred stock dividend
|
|
|
27
|
|
|
27
|
|
|
108
|
|
|
106
|
Net Loss
Attributable to Common Stock
|
|
$
|
(237)
|
|
$
|
(2,134)
|
|
$
|
(2,751)
|
|
$
|
(4,662)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Per Common
Share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.48)
|
|
$
|
(5.58)
|
|
$
|
(6.32)
|
|
$
|
(12.25)
|
Diluted
|
|
$
|
(0.48)
|
|
$
|
(5.58)
|
|
$
|
(6.32)
|
|
$
|
(12.25)
|
Weighted Average
Common Shares Outstanding
|
Basic
|
|
|
489,287,827
|
|
|
382,334,978
|
|
|
435,337,402
|
|
|
380,521,039
|
Diluted
|
|
|
489,287,827
|
|
|
382,334,978
|
|
|
435,337,402
|
|
|
380,521,039
|
|
|
|
|
|
|
|
BALANCE SHEETS
(Unaudited)
|
|
Southwestern Energy
Company and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016
|
|
December
31, 2015
|
|
|
(in
millions)
|
ASSETS
|
|
|
|
|
|
|
Current
assets
|
|
$
|
1,872
|
|
$
|
393
|
Property and
equipment
|
|
|
24,489
|
|
|
24,364
|
Less: Accumulated
depreciation, depletion and amortization
|
|
|
(19,534)
|
|
|
(16,821)
|
Total property
and equipment, net
|
|
|
4,955
|
|
|
7,543
|
Other long-term
assets
|
|
|
249
|
|
|
150
|
Total assets
|
|
|
7,076
|
|
|
8,086
|
|
|
|
|
|
|
|
LIABILITIES AND
EQUITY
|
|
|
|
|
|
|
Current
liabilities
|
|
|
1,064
|
|
|
707
|
Long-term
debt
|
|
|
4,612
|
|
|
4,704
|
Pension and other
postretirement liabilities
|
|
|
49
|
|
|
50
|
Other long-term
liabilities
|
|
|
434
|
|
|
343
|
Total
liabilities
|
|
|
6,159
|
|
|
5,804
|
Equity:
|
|
|
|
|
|
|
Common stock, $0.01 par
value; 1,250,000,000 shares authorized; issued 495,248,369 shares
as of December 31, 2016 (does not include 2,751,410 shares issued
on January 17, 2017 on account of a dividend declared on December
12, 2016) and 390,138,549 as of December 31, 2015
|
|
|
5
|
|
|
4
|
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 December 31, 2016 and 2015,
conversion in January 2018
|
|
|
–
|
|
|
–
|
Additional paid-in
capital
|
|
|
4,677
|
|
|
3,409
|
Accumulated
deficit
|
|
|
(3,725)
|
|
|
(1,082)
|
Accumulated other
comprehensive loss
|
|
|
(39)
|
|
|
(48)
|
Common stock in
treasury; 31,269 shares as of December 31, 2016 and 47,149 as of
December 31, 2015, respectively
|
|
|
(1)
|
|
|
(1)
|
Total
equity
|
|
|
917
|
|
|
2,282
|
Total liabilities and equity
|
|
$
|
7,076
|
|
$
|
8,086
|
|
|
|
|
|
|
|
STATEMENTS OF CASH
FLOWS (Unaudited)
|
|
Southwestern Energy
Company and Subsidiaries
|
|
|
|
|
|
|
|
For the years
ended
|
|
|
December
31,
|
|
|
2016
|
|
2015
|
|
|
(in
millions)
|
Cash Flows From
Operating Activities:
|
|
|
|
|
|
|
Net loss
|
|
$
|
(2,643)
|
|
$
|
(4,556)
|
Adjustments to
reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
436
|
|
|
1,092
|
Impairment of
natural gas and oil properties
|
|
|
2,321
|
|
|
6,950
|
Amortization of
debt issuance costs
|
|
|
14
|
|
|
53
|
Deferred income
taxes
|
|
|
(22)
|
|
|
(2,003)
|
Loss on
derivatives, net of settlement
|
|
|
373
|
|
|
155
|
Stock-based
compensation
|
|
|
29
|
|
|
26
|
Gain on sales
of assets, net
|
|
|
–
|
|
|
(283)
|
Restructuring
charges
|
|
|
30
|
|
|
–
|
Loss on early
extinguishment of debt
|
|
|
51
|
|
|
–
|
Other
|
|
|
8
|
|
|
34
|
Change in assets and
liabilities
|
|
|
(99)
|
|
|
112
|
Net cash provided by
operating activities
|
|
|
498
|
|
|
1,580
|
|
|
|
|
|
|
|
Cash Flows From
Investing Activities:
|
|
|
|
|
|
|
Capital
investments
|
|
|
(593)
|
|
|
(1,798)
|
Acquisitions
|
|
|
–
|
|
|
(579)
|
Proceeds from sale of
property and equipment
|
|
|
430
|
|
|
729
|
Other
|
|
|
1
|
|
|
10
|
Net cash used in
investing activities
|
|
|
(162)
|
|
|
(1,638)
|
|
|
|
|
|
|
|
Cash Flows From
Financing Activities:
|
|
|
|
|
|
|
Payments on current
portion of long-term debt
|
|
|
(1)
|
|
|
(1)
|
Payments on long-term
debt
|
|
|
(1,175)
|
|
|
(500)
|
Payments on short-term
debt
|
|
|
–
|
|
|
(4,500)
|
Payments on revolving
credit facility
|
|
|
(3,268)
|
|
|
(3,024)
|
Borrowings under
revolving credit facility
|
|
|
3,152
|
|
|
2,840
|
Payments on commercial
paper
|
|
|
(242)
|
|
|
(7,988)
|
Borrowings under
commercial paper
|
|
|
242
|
|
|
7,988
|
Change in bank drafts
outstanding
|
|
|
(20)
|
|
|
12
|
Proceeds from issuance
of long-term debt
|
|
|
1,191
|
|
|
2,950
|
Debt issuance
costs
|
|
|
(17)
|
|
|
(20)
|
Proceeds from issuance
of common stock
|
|
|
1,247
|
|
|
669
|
Proceeds from issuance
of mandatory convertible preferred stock
|
|
|
–
|
|
|
1,673
|
Preferred stock
dividend
|
|
|
(27)
|
|
|
(79)
|
Cash paid for tax
withholding
|
|
|
(9)
|
|
|
–
|
Other
|
|
|
(1)
|
|
|
–
|
Net cash provided by
financing activities
|
|
|
1,072
|
|
|
20
|
|
|
|
|
|
|
|
Increase (decrease)
in cash and cash equivalents
|
|
|
1,408
|
|
|
(38)
|
Cash and cash
equivalents at beginning of year
|
|
|
15
|
|
|
53
|
Cash and cash
equivalents at end of year
|
|
$
|
1,423
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEGMENT
INFORMATION (Unaudited)
|
|
Southwestern Energy
Company and Subsidiaries
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
|
|
Midstream
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
Services
|
|
Other
|
|
Eliminations
|
|
Total
|
|
|
(in
millions)
|
Three months ended
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
415
|
|
$
|
707
|
|
$
|
–
|
|
$
|
(438)
|
|
$
|
684
|
Marketing
purchases
|
|
|
–
|
|
|
612
|
|
|
–
|
|
|
(375)
|
|
|
237
|
Operating
expenses
|
|
|
175
|
|
|
25
|
|
|
–
|
|
|
(63)
|
|
|
137
|
General and
administrative expenses
|
|
|
63
|
|
|
13
|
|
|
–
|
|
|
–
|
|
|
76
|
Restructuring
charges
|
|
|
1
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
1
|
Depreciation,
depletion and amortization
|
|
|
71
|
|
|
16
|
|
|
–
|
|
|
–
|
|
|
87
|
Taxes, other than
income taxes
|
|
|
23
|
|
|
1
|
|
|
–
|
|
|
–
|
|
|
24
|
Operating
income
|
|
|
82
|
|
|
40
|
|
|
–
|
|
|
–
|
|
|
122
|
Capital
investments (1)
|
|
|
251
|
|
|
18
|
|
|
3
|
|
|
–
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
441
|
|
$
|
668
|
|
$
|
(1)
|
|
$
|
(421)
|
|
$
|
687
|
Marketing
purchases
|
|
|
–
|
|
|
541
|
|
|
–
|
|
|
(343)
|
|
|
198
|
Operating
expenses
|
|
|
229
|
|
|
33
|
|
|
(2)
|
|
|
(78)
|
|
|
182
|
General and
administrative expenses
|
|
|
49
|
|
|
9
|
|
|
–
|
|
|
–
|
|
|
58
|
Depreciation,
depletion and amortization
|
|
|
204
|
|
|
10
|
|
|
1
|
|
|
–
|
|
|
215
|
Impairment of natural
gas and oil properties
|
|
|
2,576
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
2,576
|
Gain on sale of
assets, net
|
|
|
(7)
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
(7)
|
Taxes, other than
income taxes
|
|
|
23
|
|
|
3
|
|
|
–
|
|
|
–
|
|
|
26
|
Operating income
(loss)
|
|
|
(2,633)
|
|
|
72
|
|
|
–
|
|
|
–
|
|
|
(2,561)
|
Capital investments
(1)
|
|
|
378
|
|
|
3
|
|
|
2
|
|
|
–
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,413
|
|
$
|
2,569
|
|
$
|
–
|
|
$
|
(1,546)
|
|
$
|
2,436
|
Marketing
purchases
|
|
|
–
|
|
|
2,145
|
|
|
–
|
|
|
(1,281)
|
|
|
864
|
Operating
expenses
|
|
|
761
|
|
|
96
|
|
|
–
|
|
|
(265)
|
|
|
592
|
General and
administrative expenses
|
|
|
204
|
|
|
43
|
|
|
–
|
|
|
–
|
|
|
247
|
Restructuring
charges
|
|
|
75
|
|
|
3
|
|
|
–
|
|
|
–
|
|
|
78
|
Depreciation,
depletion and amortization
|
|
|
371
|
|
|
65
|
|
|
–
|
|
|
–
|
|
|
436
|
Impairment of
natural gas and oil properties
|
|
|
2,321
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
2,321
|
Taxes, other than
income taxes
|
|
|
85
|
|
|
8
|
|
|
–
|
|
|
–
|
|
|
93
|
Operating income
(loss)
|
|
|
(2,404)
|
|
|
209
|
|
|
–
|
|
|
–
|
|
|
(2,195)
|
Capital
investments (1)
|
|
|
623
|
|
|
21
|
|
|
4
|
|
|
–
|
|
|
648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December
31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
2,074
|
|
$
|
3,119
|
|
$
|
–
|
|
$
|
(2,060)
|
|
$
|
3,133
|
Marketing
purchases
|
|
|
–
|
|
|
2,566
|
|
|
–
|
|
|
(1,714)
|
|
|
852
|
Operating
expenses
|
|
|
899
|
|
|
136
|
|
|
–
|
|
|
(346)
|
|
|
689
|
General and
administrative expenses
|
|
|
207
|
|
|
39
|
|
|
–
|
|
|
–
|
|
|
246
|
Depreciation,
depletion and amortization
|
|
|
1,028
|
|
|
62
|
|
|
1
|
|
|
–
|
|
|
1,091
|
Impairment of natural
gas and oil properties
|
|
|
6,950
|
|
|
–
|
|
|
–
|
|
|
–
|
|
|
6,950
|
Gain on sale of
assets, net
|
|
|
(6)
|
|
|
(277)
|
|
|
–
|
|
|
–
|
|
|
(283)
|
Taxes, other than
income taxes
|
|
|
100
|
|
|
10
|
|
|
–
|
|
|
–
|
|
|
110
|
Operating income
(loss)
|
|
|
(7,104)
|
|
|
583
|
|
|
(1)
|
|
|
–
|
|
|
(6,522)
|
Capital investments
(1)
|
|
|
2,258
|
|
|
167
|
|
|
12
|
|
|
–
|
|
|
2,437
|
|
|
(1)
|
Capital investments
includes an increase of $67 million and a decrease of $28 million
for the three months ended December 31, 2016 and 2015,
respectively, and an increase of $43 million and a decrease of $33
million for the years ended December 31, 2016 and 2015,
respectively, relating to the change in accrued expenditures
between periods.
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/southwestern-energy-announces-operational-update-and-2016-financial-results-300412899.html
SOURCE Southwestern Energy Company