Southwestern Energy Announces 2017 Operational And Financial Results
HOUSTON, March 1, 2018 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the fourth quarter and the year ended December 31, 2017. The Company met or exceeded its guidance and delivered on each of its commitments in the fourth quarter. Fiscal year 2017 highlights include:
-- Net cash provided by operating activities of $1,097 million and net cash
flow of $1,138 million, an increase of approximately 120% and 76%,
respectively compared to 2016;
-- Net income attributable to common stock of $815 million, or $1.63 per
diluted share, and adjusted net income attributable to common stock of
$219 million, or $0.44 per diluted share;
-- Total net production of 897 Bcfe, including 578 Bcfe from the
Appalachian Basin and 316 Bcf from the Fayetteville Shale
-- Comprised of 89% natural gas and 11% NGLs and condensate;
-- Record Appalachian Basin gross operated exit rate production of 2.35
Bcfe per day, a 40% increase compared to December 2016;
-- Realized C3+ NGL prices of $30.08 per barrel, or 59% of West Texas
Intermediate (WTI), and realized total NGL prices of $14.48 per barrel,
or 28% of WTI (net of transportation costs), up 69% and 94%,
respectively, compared to 2016;
-- Record total proved reserves of approximately 14.8 Tcfe, including 11.1
Tcfe from the Appalachian Basin, up 181% and 393%, respectively,
compared to 2016
-- Comprised of 75% natural gas and 25% NGLs and condensate at year-end
2017, compared to 93% and 7% in 2016, respectively;
-- 46% proved undeveloped at year-end 2017
-- Reserve life index increased to more than 16 years at year-end 2017, an
increase of approximately 175% compared to year-end 2016;
-- Increase in pre-tax PV10 reserve value to approximately $5.8 billion, up
247% compared to year-end 2016, including $3.8 billion from the
Appalachian Basin;
-- Proved Developed (PD) Finding and Development (F&D) costs for the total
company of $0.72 per Mcfe, 4% better than 2016 and demonstrating
continued improved capital efficiency; and
-- Further optimized drilling and completion techniques resulting in
increased type curves and improved economics in the Appalachian Basin.
"Southwestern Energy delivered solid financial and operational results in 2017. There is clear evidence of upside in our assets, as the value of our PV10 reserves alone is well above current enterprise value," said Bill Way, President and Chief Executive Officer. "Our focus in 2018 will be on exploring strategic alternatives for Fayetteville Shale assets, accelerating development in Appalachia and reducing structural costs as we reposition the Company to compete and win in any commodity price environment for years to come. Building on the momentum from our leading technical and operational expertise and our demonstrated financial discipline, underpinned by our Formula that guides everything we do, we are well positioned to drive increasing value for our shareholders."
The Company invested within cash flow (supplemented by the previously announced remaining $200 million from its 2016 equity offering as planned) while investing in its highest return projects. Below is a summary of fourth quarter and full year 2017 results.
Financial For the three months
Results ended For the year ended
December 31, December 31,
2017 2016 2017 2016
---- ---- ---- ----
(in millions,
except per
share
amounts)
Operating
income (loss) $167 $122 $731 $(2,195)
Adjusted
operating
income (non-
GAAP measure) $169 $134 $735 $215
Net income
(loss)
attributable
to common
stock $267 $(237) $815 $(2,751)
Adjusted net
income (loss)
attributable
to common
stock (non-
GAAP measure) $63 $39 $219 $(7)
Diluted
earnings
(loss) per
share $0.53 $(0.48) $1.63 $(6.32)
Adjusted
diluted
earnings
(loss) per
share (non-
GAAP measure) $0.12 $0.08 $0.44 $(0.01)
Net cash
provided by
operating
activities $308 $161 $1,097 $498
Net cash flow
(non-GAAP
measure) $322 $211 $1,138 $645
Exploration and
Production Financial
Results For the three months ended For the year ended
December 31, December 31,
2017 2016 2017 2016
---- ---- ---- ----
Production
Fayetteville (Bcf) 75 86 316 375
Northeast Appalachia
(Bcf) 110 82 395 350
Southwest Appalachia
(Bcfe) 52 33 183 148
Other (Bcfe) 2 1 3 2
--- --- --- ---
Total production (Bcfe) 239 202 897 875
% Natural Gas 88% 90% 89% 90%
Average unit costs per
Mcfe
Lease operating
expenses $0.91 $0.87 $0.90 $0.87
General &
administrative
expenses(1) $0.22 $0.27 $0.22 $0.22
Taxes, other than
income taxes(2) $0.07 $0.11 $0.10 $0.10
Full cost pool
amortization $0.48 $0.30 $0.45 $0.38
(1) Excludes legal settlements for
the year ended December 31,
2017 and restructuring and
other one-time charges for the
three months and year ended
December 31, 2016,
respectively.
(2) Excludes restructuring charges
for the year ended December 31,
2016.
Realized Prices For the three months ended For the year ended
December 31, December 31,
2017 2016 2017 2016
---- ---- ---- ----
Natural Gas Price:
NYMEX Henry Hub
Price
($/MMBtu)(1) $2.93 $2.98 $3.11 $2.46
Discount to
NYMEX(2) (0.93) (0.98) (0.88) (0.87)
----- ----- ----- -----
Average realized
gas price per
Mcf, excluding
hedges $2.00 $2.00 $2.23 $1.59
Gain (loss) on
settled financial
basis derivatives
($/Mcf) 0.07 0.09 (0.01) 0.03
Gain (loss) on
settled commodity
derivatives
($/Mcf) 0.05 (0.02) (0.03) 0.02
---- ----- ----- ----
Average realized
gas price per
Mcf, including
hedges $2.12 $2.07 $2.19 $1.64
Oil Price:
WTI oil price
($/Bbl) $55.40 $49.29 $50.96 $43.32
Discount to WTI (7.35) (8.11) (7.84) (12.12)
Average oil price
per Bbl $48.05 $41.18 $43.12 $31.20
NGL Price:
Average net
realized NGL
price per Bbl(3) $17.98 $12.08 $14.48 $7.46
Percentage of WTI 32% 25% 28% 17%
Average net
realized C3+ NGL
price per Bbl $39.38 $27.91 $30.08 $17.75
Percentage of WTI 71% 57% 59% 41%
(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 $0.01 per
Bbl and $0.02 per Bbl of realized
hedge gains for the three and
twelve months ended December 31,
2017.
Fourth Quarter 2017 Financial Results
E&P Segment -Operating income for the segment improved to $114 million for the fourth quarter of 2017, compared to operating income of $82 million during the fourth quarter of 2016. The increase in operating income was primarily due to higher production and liquids pricing, partially offset by higher operating costs.
Midstream Segment - Operating income for the segment, comprised of gathering and marketing activities, was $54 million for the fourth quarter of 2017, compared to $40 million for the same period in 2016. The increase in operating income was primarily a result of $14 million minimum volume commitment shortfall payment from a third-party customer to the Company's gathering segment and increase in the Company's marketing margin. The increase was offset by a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale.
Full Year 2017 Financial Results
E&P Segment - Operating income for the segment improved to $549 million for 2017, compared to an operating loss of approximately $2.4 billion for 2016, which was primarily due to the $2.3 billion impairment of natural gas and oil properties and $75 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.
Midstream Segment - Operating income for the segment, comprised of gathering and marketing activities, was $183 million for 2017, which included a $6 million gain on sale of equipment, compared to $209 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 December 31, 2017, the Company had total debt of approximately $4.4 billion and cash and cash equivalents of $916 million, resulting in net debt of $3.5 billion. Net debt to adjusted EBITDA ratio improved 38% to 2.8 times, compared to 4.5 times at December 31, 2016. During 2017, the Company took steps to improve its maturity schedule and 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 2017, Southwestern invested a total of $1.3 billion in capital. This included approximately $1.25 billion invested in its E&P business, $32 million invested in its Midstream segment and $13 million invested for corporate and other purposes. Of the $1.3 billion, approximately $113 million was associated with capitalized interest and $104 million was associated with capitalized expenses.
2017 Operational Review
During the fourth quarter of 2017, Southwestern invested a total of approximately $327 million in the E&P business and drilled 28 wells, completed 35 wells, and placed 36 wells to sales.
Three Months
Ended Dec
31, 2017
E&P
Division
Results Appalachia Fayetteville
----------
Northeast Southwest Shale
--------- --------- -----
Production
(Bcfe) (1) 110 52 75
Capital
investments
($ in
millions)
Exploratory
and
development
drilling,
including
workovers $105 $109 $9
Acquisition
and
leasehold 2 13 -
Seismic and
other 4 1 3
Capitalized
interest
and expense 11 34 5
--- --- ---
Total
capital
investments $122 $157 $17
Gross
operated
well count
summary
Drilled 11 17 -
Completed 22 12 1
Wells to
sales 23 11 2
Realized
Price
NYMEX Henry
Hub Price
($/MMBtu) $2.93 $2.93 $2.93
Discount to
NYMEX
($/Mcf)(2) $(1.08) $(0.93) $(0.71)
------ ------ ------
Average
realized gas
price,
excluding
hedges
($/Mcf) $1.85 $2.00 $2.22
(1) Southwest Appalachia production
included 25 Bcf of natural gas,
4,095 MBbls of NGLs and 555 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 2017, Southwestern invested a total of approximately $1.25 billion in the E&P business, and drilled 134 wells, completed 151 wells, placed 166 wells to sales and had 92 wells in progress at year-end. Of these 92 wells, 52 and 40 were located in our Northeast Appalachia and Southwest Appalachia, respectively, and 19 of these wells are waiting on pipeline or production facilities.
Year-end
2017 E&P
Division
Results Appalachia Fayetteville
----------
Northeast Southwest Shale
--------- --------- -----
Production
(Bcfe) (1) 395 183 316
Gross
operated
production
at year-end
2017 (Mmcfe/
d)(2) 1,446 901 1,170
Reserves
(Bcfe) 4,126 6,962 3,679
Capital
investments
($ in
millions)
Exploratory
and
development
drilling,
including
workovers $420 $353 $82
Acquisition
and
leasehold 14 59 1
Seismic and
other 13 4 9
Capitalized
interest and
expense 42 131 22
--- --- ---
Total capital
investments $489 $547 $114
Gross
operated
well count
summary
Drilled 67 53 13
Completed 77 50 23
Wells to
sales 83 57 25
Wells in
progress 52 40 -
Year-end
drilled
uncompleted
wells 30 36 -
Realized
price
NYMEX Henry
Hub price
($/MMBtu) $3.11 $3.11 $3.11
Discount to
NYMEX
($/Mcf) (3) $(1.00) $(0.83) $(0.76)
------ ------ ------
Average
realized gas
price,
excluding
hedges
($/Mcf) $2.11 $2.28 $2.35
----- ----- -----
(1) SW Appalachia production included
85 Bcf of natural gas, 14,193
MBbls of NGLs and 2,228 MBbls of
oil.
(2) Based on average rates for the
month of December 2017.
(3) This discount includes a basis
differential, physical basis
sales, third-party transportation
charges and fuel charges and
excludes financial basis hedges.
For the years ended December
31,
-----------------------------
2017 2016
---- ----
E&P Capital Investments
by Type (in millions)
Exploratory and
development drilling,
including workovers $878 $358
Acquisitions and
leasehold 86 23
Seismic expenditures 7 1
Drilling rigs, sand
facility, water
infrastructure and
other 65 2
Capitalized interest
and other expenses 212 239
--- ---
Total E&P capital
investments $1,248 $623
E&P Capital Investments
by Area
Northeast Appalachia $447 $165
Southwest Appalachia 416 130
Fayetteville Shale 92 65
Exploration 24 (2)
E&P Services & Other 57 26
Capitalized interest
and other expenses 212 239
--- ---
Total E&P capital
investments $1,248 $623
Southwest Appalachia - Southwest Appalachia's gross operated exit production rate increased by 56%, compared to December 2016, to approximately 901 MMcfe per day. Southwestern brought online 57 wells in Southwest Appalachia in 2017, which included 46 Marcellus wells drilled and completed by Southwestern. The 46 wells included 27 targeting the rich gas window, 16 targeting the lean gas window and 3 targeting dry gas Marcellus. The 46 wells had an average lateral length of 7,451 feet and an average cost of $7.4 million per well. This compares to an average completed operated well cost of $5.4 million per well and an average horizontal lateral length of 5,275 feet in 2016. In 2017, the Company continued its completion optimization efforts to improve well performance. Southwest Appalachia increased stage density and sand loading by 20% and 14%, respectively in 2017 and increased its average horizontal lateral length by over 2,000 feet, or 41%, compared to 2016. These efforts on drilling longer laterals, driving down costs and increasing operational efficiency were able to more than offset the additional cost of higher intensity completions, yielding higher well productivity and higher well level returns. The Company will focus on further extending lateral lengths on future wells to create additional value that has been demonstrated on the long lateral wells drilled to date.
Operational Highlights:
-- Brought online 11 wells in the fourth quarter, which included 7 wells
drilled and completed by Southwestern and 4 wells that were drilled by
the previous operator and were waiting on infrastructure. The 7 wells
drilled and completed by the Company had an average lateral length of
7,801 feet and an average cost of $8.8 million per well, which included
additional costs for enhanced completion testing;
-- Improved well recoveries in the lean gas window, as evidenced by the
4-well Gladys Briggs pad in Marshall County that was brought online in
July 2017 and has an average EUR per well of 25 Bcfe, or 3.8 Bcfe/1,000
feet, and F&D costs of $0.24 per Mcfe, a 20% improvement compared to the
Company's lean gas type curve;
-- Expanded the Company's prospective rich gas footprint by placing its
northern most pad to sales in Brooke County, which has produced 7.9
Bcfe, comprised of 68% liquids from four wells after 240 days online.
The productivity of these wells continues to improve capital efficiency
and returns with average F&D costs of $0.50 per Mcfe and a break-even
gas price of less than $1.00 with oil prices of approximately $55 per
Bbl; and
-- Increased type curves as a result of the continued well outperformance
from enhanced drilling and completion designs.
Northeast Appalachia - Northeast Appalachia's gross operated exit production rate increased 32% compared to December 2016, to approximately 1,446 MMcfe per day. In 2017, the Company's operated horizontal wells had an average completed well cost of $5.9 million per well and an average horizontal lateral length of 6,185 feet. This compares to an average completed operated well cost of $5.3 million per well and an average horizontal lateral length of 6,142 feet in 2016. The increased costs were primarily due to increased activity in delineation areas. The increase in costs were more than offset by efficiency and productivity gains, resulting in a 7% improvement in finding & development costs.
Operational Highlights:
-- In the fourth quarter of 2017, the Company placed 23 wells to sales,
which had an average lateral length of 5,754 feet and an average cost of
$5.4 million per well. The average rate for the first 30 days for the 15
wells that were online for at least 30 days was 16.9 MMcf per day per
well;
-- Placed two wells to sales in eastern Susquehanna County, with an average
lateral length of over 9,600 feet, delivering a Susquehanna County
company record average IP rate of over 34 MMcf per day per well;
-- Commenced development on its 28,000 acre Tioga area with gross
production increasing to 73 MMcf per day at year-end 2017, adding the
first phase of compression during the fourth quarter; and
-- Increased type curves due to the demonstrated continued well
outperformance from enhanced completion designs, resulting in an
approximately 75% increase in cumulative production in the first year of
production.
Fayetteville Shale - The Company generated approximately $400 million in positive cash flow from operations, net of capital investments from its Fayetteville E&P and midstream gathering assets in 2017.
Operational Highlights:
-- Identified significant opportunity for additional future value in the
Fayetteville shale via the redevelopment of legacy areas with latest
generation drilling and completion techniques coupled with selective
application of longer laterals, which has applications across the
Company's vast position concentrated in the core of the play
-- First redevelopment well in the Fayetteville shale tested with a 40%
improvement in initial production rates over historical wells; and
-- Additional activity is being undertaken to further define this
opportunity set.
-- Unlocked additional future value with positive Moorefield delineation
efforts increasing the derisked productive Moorefield acreage to
approximately 36,000 net acres of the almost 100,000 net acres
prospective in the play
-- The first step out well, located in the southwest portion of the
play, used engineered completion design that delivered encouraging
results with an average 30-day rate of 6.2 MMcf per day; and
-- The second step out well produced higher water volumes than
expected, an identified pre-drill risk in this portion of the field.
2017 Natural Gas and Oil Reserves
Southwestern's estimated proved natural gas and oil reserves, audited by an independent petroleum engineering firm, increased by 181% to approximately 14,775 Bcfe at December 31, 2017. The following tables detail additional information relating to reserve estimates as of and for the year ended December 31, 2017:
Proved Reserves Summary For the years ended December 31,
--------------------------------
2017 2016
---- ----
Proved reserves (in Bcfe) 14,775 5,253
Prices used
Natural gas (per Mcf) $2.98 $2.48
Oil (per barrel) $47.79 $39.25
NGL (per barrel) $14.41 $6.74
PV-10:
Pre-Tax (millions) $5,784 $1,665
PV of Taxes (millions) (222) -
---- ---
After-Tax (millions) $5,562 $1,665
------ ------
Percent of estimated proved
reserves that are:
Natural gas 75% 93%
Proved developed 54% 99%
2017 Proved
Reserves by
Commodity Natural Gas Oil NGL Total
(Bcf) (MBbls) (MBbls) (Bcfe)
---- ------ ------ -----
Proved reserves,
beginning of year 4,866 10,523 53,931 5,253
Revisions of
previous estimates 1,898 1,668 70,549 2,332
Extensions,
discoveries and
other additions(1) 5,159 55,772 432,220 8,087
Production (797) (2,327) (14,245) (897)
Acquisition of
reserves in place - - - -
Disposition of
reserves in place - - - -
--- --- --- ---
Proved reserves,
end of year 11,126 65,636 542,455 14,775
====== ====== ======= ======
Proved developed
reserves:
Beginning of year 4,789 10,523 53,931 5,176
End of year 6,979 14,513 142,213 7,920
Note: Amounts may not add due to rounding
(1) The 2017 PUD additions are
primarily associated with
the increase in commodity
prices.
2017 Proved Reserves by
Division Appalachia Fayetteville
----------
Northeast Southwest Shale Other Total
--------- --------- ----- ----- -----
Estimated Proved
Reserves (Bcfe):
Reserves, beginning of
year 1,574 677 2,997 5 5,253
Production (395) (183) (316) (3) (897)
Extensions, discoveries
and other additions(1) 1,890 5,605 591 1 8,087
Price revisions 903 738 49 1 1,691
Performance & production
revisions 154 125 358 4 641
--- --- --- --- ---
Reserves, end of year 4,126 6,962 3,679 8 14,775
===== ===== ===== === ======
(1) The 2017 PUD additions are
primarily associated with
the increase in commodity
prices.
2017 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA
Appalachia Fayetteville
----------
Northeast Southwest Shale Other (1) Total
--------- --------- ----- -------- -----
Estimated Proved Reserves:
Natural Gas (Bcf):
Developed (Bcf) 3,007 833 3,135 4 6,979
Undeveloped (Bcf) 1,119 2,484 544 - 4,147
----- ----- --- --- -----
4,126 3,317 3,679 4 11,126
Crude Oil (MMBbls):
Developed (MMBbls) - 14.2 - 0.3 14.5
Undeveloped (MMBbls) - 51.1 - - 51.1
--- ---- --- --- ----
- 65.3 - 0.3 65.6
Natural Gas Liquids
(MMBbls):
Developed (MMBbls) - 141.9 - 0.3 142.2
Undeveloped (MMBbls) - 400.2 - - 400.2
--- ----- --- --- -----
- 542.1 - 0.3 542.4
Total Proved Reserves
(Bcfe) (2):
Developed (Bcfe) 3,007 1,770 3,135 8 7,920
Undeveloped (Bcfe) 1,119 5,192 544 - 6,855
----- ----- --- --- -----
4,126 6,962 3,679 8 14,775
----- ----- ----- --- ------
Percent of Total 28% 47% 25% 0% 100%
Percent Proved Developed 73% 25% 85% 100% 54%
Percent Proved Undeveloped 27% 75% 15% 0% 46%
Production (Bcfe) 395 183 316 3 897
Capital Investments (in
millions) (3) $489 $547 $114 $41 $1,191
Total Gross Producing
Wells (4) 983 364 4,191 20 5,558
Total Net Producing Wells
(4) 516 255 2,921 17 3,709
Total Net Acreage 191,226 290,291 917,842 386,304 (5) 1,785,663
Net Undeveloped Acreage 87,927 219,709 424,858 369,236 (5) 1,101,730
PV-10:
Pre-Tax (in millions) (6) $2,085 $1,718 $1,978 $3 $5,784
PV of Taxes (in millions)
(6) 80 66 76 - 222
--- --- --- --- ---
After-Tax (in millions)
(6) $2,005 $1,652 $1,902 $3 $5,562
------ ------ ------ --- ------
Percent of Total 36% 30% 34% 0% 100%
Percent Operated (7) 99% 100% 99% 100% 99%
(1) Other consists primarily of
properties in Canada, Colorado and
Louisiana.
(2) We have no reserves from synthetic
gas, synthetic oil or nonrenewable
natural resources intended to be
upgraded into synthetic gas or oil.
We used standard engineering and
geoscience methods, or a
combination of methodologies in
determining estimates of material
properties, including performance
and test date analysis offset
statistical analogy of performance
data, volumetric evaluation,
including analysis of petrophysical
parameters (including porosity, net
pay, fluid saturations (i.e.,
water, oil and gas) and
permeability) in combination with
estimated reservoir parameters
(including reservoir temperature
and pressure, formation depth and
formation volume factors),
geological analysis, including
structure and isopach maps and
seismic analysis, including review
of 2-D and 3-D data to ascertain
faults, closure and other factors.
(3) Total and Other capital investments
excludes $57 million related to our
E&P service companies, of which $37
million related to water
infrastructure.
(4) Represents producing wells,
including 400 wells in which we
only have an overriding royalty
interest in Northeast Appalachia,
used in the December 31, 2017
reserves calculation.
(5) Excludes exploration licenses for
2,518,519 net acres in New
Brunswick, Canada, which have been
subject to a moratorium since 2015.
(6) 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.
(7) Based upon pre-tax PV-10 of proved
developed producing activities.
The Company's 2017 and three-year average proved developed finding and development (PD F&D) costs were $0.72 and $0.80 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.
Total Company PD F&D Three-Year
12 Months Ended December 31, Total
2017 2016 2015 2017
---- ---- ---- ----
Total PD Adds (Bcfe):
New PD adds 1,258 257 416 1,931
PUD conversions 46 220 1,044 1,310
--- --- ----- -----
Total PD Adds 1,304 477 1,460 3,241
----- --- ----- -----
Costs Incurred (in
millions):
Proved property
acquisition costs $ - $ - $81 $81
Unproved property
acquisition costs 194 171 692 1,057
Exploration costs 22 17 50 89
Development costs 1,024 433 1,417 2,874
----- --- ----- -----
Capitalized Costs
Incurred $1,240 $621 $2,240 $4,101
------ ---- ------ ------
Subtract (in millions):
Proved property
acquisition costs $ - $ - $(81) $(81)
Unproved property
acquisition costs (194) (171) (692) (1,057)
Capitalized interest
and expense(1)
associated with
development and
exploration (103) (91) (187) (381)
---- --- ---- ----
PD Costs Incurred $943 $359 $1,280 $2,582
---- ---- ------ ------
PD F&D $0.72 $0.75 $0.88 $0.80
----- ----- ----- -----
Note: Amounts may not add due to rounding
(1) Adjusting for the impacts of the
full cost accounting method for
comparability.
Division PD F&D 12 Months Ended December 31, 2017
---------------------------------
Appalachia Fayetteville
----------
Northeast Southwest Shale Other Total
--------- --------- ----- ----- -----
Total PD Adds (Bcfe):
New PD adds 790 419 48 1 1,258
PUD conversions 17 - 29 - 46
--- --- --- --- ---
Total PD Adds 807 419 77 1 1,304
--- --- --- --- -----
Costs Incurred (in
millions):
Proved property
acquisition costs $ - $ - $ - $ - $ -
Unproved property
acquisition costs 20 154 1 19 194
Exploration costs 8 3 - 11 22
Development costs 471 402 125 26 1,024
--- --- --- --- -----
Capitalized Costs
Incurred $499 $559 $126 $56 $1,240
---- ---- ---- --- ------
Subtract (in millions):
Proved property
acquisition costs $ - $ - $ - $ - $ -
Unproved property
acquisition costs (20) (154) (1) (19) (194)
Capitalized interest
and expense(1)
associated with
development and
exploration (36) (38) (18) (11) (103)
--- --- --- --- ----
PD Costs Incurred $443 $367 $107 $26 $943
---- ---- ---- --- ----
PD F&D $0.55 $0.88 $1.39 $ - $0.72
----- ----- ----- --- --- -----
Note: Amounts may not add due to rounding
(1) Adjusting for the impacts of the
full cost accounting method for
comparability.
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, 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.
Proved developed finding and development costs - Proved developed (PD) 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 PD 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 PD F&D costs for the periods ending December 31, 2017, 2016 and 2015 and the three years ending December 31, 2017.
The Company believes that providing a measure of PD 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, PD 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 PD F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its PD F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern's PD F&D costs may not be comparable to similar measures provided by other companies.
3 Months Ended December
31,
------------------------
2017 2016
---- ----
(in millions)
Net income (loss)
attributable to common
stock:
Net income (loss)
attributable to common
stock $267 $(237)
Add back:
Participating securities -
mandatory convertible
preferred stock 31 (6)
Impairment of natural gas
and oil properties - -
Restructuring and other
one-time charges - 12
Gain on sale of assets,
net (1) -
Loss on early
extinguishment of debt
and other bank fees 3 -
(Gain) loss on certain
derivatives (101) 324
Adjustments due to
inventory valuation and
other (1) -
Loss on foreign currency
adjustment 6 -
Adjustments due to
discrete tax items(1) (176) 74
Tax impact on adjustments 35 (128)
--- ----
Adjusted net income
attributable to common
stock $63 $39
=== ===
(1) Primarily relates to the
exclusion of certain discrete
tax adjustments associated
with the valuation allowance
against deferred tax assets.
The Company expects its 2018
income tax rate to be 24.5%
before the impacts of any
valuation allowance.
3 Months Ended December
31,
------------------------
2017 2016
---- ----
Diluted earnings (loss)
per share:
Diluted earnings (loss)
per share $0.53 $(0.48)
Add back:
Participating securities
-mandatory convertible
preferred stock 0.06 (0.01)
Impairment of natural
gas and oil properties - -
Restructuring and other
one-time charges - 0.02
Gain on sale of assets,
net (0.00) -
Loss on early
extinguishment of debt
and other bank fees 0.01 -
(Gain) loss on certain
derivatives (0.20) 0.66
Adjustments due to
inventory valuation and
other (0.00) -
Loss on foreign currency
adjustment 0.01 -
Adjustments due to
discrete tax items(1) (0.36) 0.15
Tax impact on
adjustments 0.07 (0.26)
---- -----
Adjusted diluted
earnings per share $0.12 $0.08
===== =====
(1) Primarily relates to the
exclusion of certain discrete
tax adjustments associated
with the valuation allowance
against deferred tax assets.
The Company expects its 2018
income tax rate to be 24.5%
before the impacts of any
valuation allowance.
12 Months Ended December
31,
-------------------------
2017 2016
---- ----
(in millions)
Net income (loss)
attributable to common
stock:
Net income (loss)
attributable to common
stock $815 $(2,751)
Add back:
Participating
securities - mandatory
convertible preferred
stock 90 -
Impairment of natural
gas and oil properties - 2,321
Restructuring and other
one-time charges - 89
Gain on sale of assets,
net (4) (3)
Loss on early
extinguishment of debt
and other bank fees(1) 73 57
Legal settlements 5 -
(Gain) loss on certain
derivatives (451) 373
Loss on foreign
currency adjustment 6 -
Adjustments due to
inventory valuation
and other (2) 3
Adjustments due to
discrete tax items(2) (455) 978
Tax impact on
adjustments 142 (1,074)
--- ------
Adjusted net income
(loss) attributable to
common stock $219 $(7)
==== ===
(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
charges.
(2) Primarily relates to the
exclusion of certain discrete
tax adjustments associated with
the valuation allowance against
deferred tax assets. The
Company expects its 2018 income
tax rate to be 24.5% before the
impacts of any valuation
allowance.
12 Months Ended December
31,
-------------------------
2017 2016
---- ----
Diluted earnings (loss)
per share:
Diluted earnings (loss)
per share $1.63 $(6.32)
Add back:
Participating
securities - mandatory
convertible preferred
stock 0.18 -
Impairment of natural
gas and oil properties - 5.33
Restructuring and other
one-time charges - 0.20
Gain on sale of assets,
net (0.01) (0.00)
Loss on early
extinguishment of debt
and other bank fees(1) 0.15 0.13
Legal settlements 0.01 -
(Gain) loss on certain
derivatives (0.90) 0.86
Loss on foreign
currency adjustment 0.01 -
Adjustments due to
inventory valuation
and other (0.00) 0.01
Adjustments due to
discrete tax items(2) (0.91) 2.25
Tax impact on
adjustments 0.28 (2.47)
---- -----
Adjusted diluted
earnings (loss) per
share $0.44 $(0.01)
===== ======
(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 associated with
the valuation allowance against
deferred tax assets. The
Company expects its 2018 income
tax rate to be 24.5% before the
impacts of any valuation
allowance.
3 Months Ended December 31,
---------------------------
2017 2016
---- ----
(in millions)
Cash flow from
operating
activities:
Net cash provided by
operating
activities $308 $161
Add back:
Changes in operating
assets and
liabilities 14 49
Restructuring
charges - 1
--- ---
Net cash flow $322 $211
==== ====
12 Months Ended December
31,
-------------------------
2017 2016
---- ----
(in millions)
Cash flow from
operating
activities:
Net cash provided by
operating
activities $1,097 $498
Add back:
Changes in operating
assets and
liabilities 41 99
Restructuring
charges - 48
--- ---
Net cash flow $1,138 $645
====== ====
3 Months Ended December 31,
---------------------------
2017 2016
---- ----
(in millions)
Operating income:
Operating income $167 $122
Add back:
Impairment of
natural gas and oil
properties - -
Gain on sale of
assets, net (1) -
Loss on early
extinguishment of
debt and other bank
fees 3 -
Restructuring and
other one-time
charges - 12
--- ---
Adjusted operating
income $169 $134
==== ====
12 Months Ended December
31,
-------------------------
2017 2016
---- ----
(in millions)
Operating income
(loss):
Operating income
(loss) $731 $(2,195)
Add back:
Impairment of
natural gas and oil
properties - 2,321
Gain on sale of
assets, net (4) -
Legal settlements 5 -
Loss on early
extinguishment of
debt and other bank
fees 3 -
Restructuring and
other one-time
charges - 89
--- ---
Adjusted operating
income $735 $215
==== ====
3 Months Ended December 31,
---------------------------
2017 2016
---- ----
(in millions)
E&P segment
operating income:
E&P segment
operating income $114 $82
Add back:
Impairment of
natural gas and oil
properties - -
Restructuring and
other one-time
charges - 12
Loss on early
extinguishment of
debt and other bank
fees 3 -
Adjusted E&P segment
operating income $117 $94
==== ===
12 Months Ended December
31,
-------------------------
2017 2016
---- ----
(in millions)
E&P segment
operating income
(loss):
E&P segment
operating income
(loss) $549 $(2,404)
Add back:
Impairment of
natural gas and oil
properties - 2,321
Legal settlements 5 -
Loss on early
extinguishment of
debt and other bank
fees 3 -
Restructuring and
other one-time
charges - 86
--- ---
Adjusted E&P segment
operating income $557 $3
==== ===
December 31,
2017 2016
---- ----
(in millions)
Net debt:
Total debt $4,391 $4,653
Subtract:
Cash and cash
equivalents (916) (1,423)
---- ------
Net debt $3,475 $3,230
====== ======
12 Months Ended December
31,
-------------------------
2017 2016
---- ----
(in millions)
EBITDA:
Net income (loss) $1,046 $(2,643)
Add back:
Interest expense 135 88
Income tax benefit (93) (29)
Depreciation,
depletion and
amortization 504 436
Impairment of
natural gas and oil
properties - 2,321
Restructuring and
other one-time
charges - 89
Gain on sale of
assets, net (4) (3)
Loss on early
extinguishment of
debt and other bank
fees 73 51
Legal settlements 5 -
(Gain) loss on
certain derivatives (451) 373
Loss on foreign
currency adjustment 6 -
Adjustments due to
inventory valuation
and other (2) 3
Stock based
compensation
expense 28 35
Adjusted EBITDA $1,247 $721
====== ====
Southwestern management will host a teleconference call on Friday, March 2, 2018 at 10:00 a.m. Eastern to discuss its fourth quarter and year-end 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 years ended
December 31, December 31,
2017 2016 2017 2016
---- ---- ---- ----
Exploration & Production
------------------------
Production
Gas production (Bcf) 210 183 797 788
Oil production (MBbls) 580 463 2,327 2,192
NGL production (MBbls) 4,111 2,792 14,245 12,372
Total production (Bcfe) 239 202 897 875
Commodity Prices
Average realized gas price per
Mcf, including derivatives $2.12 $2.07 $2.19 $1.64
Average realized gas price per
Mcf, excluding derivatives $2.00 $2.00 $2.23 $1.59
Average realized oil price per
Bbl $48.05 $41.18 $43.12 $31.20
Average realized NGL price per
Bbl, including derivatives $17.98 $12.08 $14.48 $7.46
Average realized NGL price per
Bbl, excluding derivatives $17.97 $12.08 $14.46 $7.46
Summary of Derivative Activity
in the Statement of
Operations
Settled commodity amounts
included in "Gain (Loss) on
Derivatives" (in millions) $25 $14 $(27) $36
Unsettled commodity amounts
included in "Gain (Loss) on
Derivatives" (in millions) $100 $(330) $449 $(375)
Average unit costs per Mcfe
Lease operating expenses $0.91 $0.87 $0.90 $0.87
General & administrative
expenses (1) $0.22 $0.27 $0.22 $0.22
Taxes, other than income taxes
(2) $0.07 $0.11 $0.10 $0.10
Full cost pool amortization $0.48 $0.30 $0.45 $0.38
Midstream
---------
Volumes marketed (Bcfe) 285 248 1,067 1,062
Volumes gathered (Bcf) 119 138 499 601
(1) Excludes $5 million of one-time
legal charges for the year
ended December 31, 2017.
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,
2017 2016 2017 2016
---- ---- ---- ----
(in millions, except share/per share amounts)
Operating Revenues
Gas sales $425 $367 $1,793 $1,273
Oil sales 29 19 102 69
NGL sales 74 33 206 92
Marketing 236 233 972 864
Gas gathering 41 32 126 138
Other 4 - 4 -
--- --- --- ---
809 684 3,203 2,436
--- --- ----- -----
Operating Costs and Expenses
Marketing purchases 236 237 976 864
Operating expenses 190 137 671 592
General and administrative
expenses 63 76 233 247
Restructuring charges - 1 - 78
Depreciation, depletion and
amortization 140 87 504 436
Impairment of natural gas and oil
properties - - - 2,321
Gain on sale of assets, net (6) - (6) -
Taxes, other than income taxes 19 24 94 93
--- --- --- ---
642 562 2,472 4,631
--- --- ----- -----
Operating Income (Loss) 167 122 731 (2,195)
--- --- --- ------
Interest Expense
Interest on debt 64 58 239 226
Other interest charges 2 2 9 14
Interest capitalized (28) (29) (113) (152)
--- --- ---- ----
38 31 135 88
Gain (Loss) on Derivatives 127 (311) 422 (339)
Loss on Early Extinguishment of
Debt - - (70) (51)
Other Income, Net (1) 1 5 1
--- --- --- ---
Income (Loss) Before Income Taxes 255 (219) 953 (2,672)
Benefit for Income Taxes
Current (12) (7) (22) (7)
Deferred (67) (2) (71) (22)
--- --- --- ---
(79) (9) (93) (29)
--- --- --- ---
Net Income (Loss) 334 (210) 1,046 (2,643)
Mandatory convertible preferred
stock dividend 27 27 108 108
Participating securities -
mandatory convertible preferred
stock 40 - 123 -
--- --- --- ---
Net Income (Loss) Attributable to
Common Stock $267 $(237) $815 $(2,751)
==== ===== ==== =======
Income (Loss) Per Common Share
Basic $0.53 $(0.48) $1.64 $(6.32)
===== ====== ===== ======
Diluted $0.53 $(0.48) $1.63 $(6.32)
===== ====== ===== ======
Weighted Average Common Shares Outstanding
Basic 503,614,377 489,287,827 498,264,321 435,337,402
=========== =========== =========== ===========
Diluted 507,137,867 489,287,827 500,804,297 435,337,402
=========== =========== =========== ===========
BALANCE SHEETS
(Unaudited)
Southwestern Energy
Company and
Subsidiaries
December 31, December 31,
2017 2016
---- ----
(in millions)
ASSETS
Current assets $1,509 $1,872
Property and equipment 25,769 24,489
Less: Accumulated
depreciation,
depletion and
amortization (19,997) (19,534)
------- -------
Total property and
equipment, net 5,772 4,955
Other long-term assets 240 249
--- ---
Total assets $7,521 $7,076
====== ======
LIABILITIES AND EQUITY
Current liabilities $780 $1,064
Long-term debt 4,391 4,612
Pension and other
postretirement
liabilities 58 49
Other long-term
liabilities 313 434
--- ---
Total liabilities 5,542 6,159
----- -----
Equity:
Common stock, $0.01
par value;
1,250,000,000 shares
authorized; issued
512,134,311 shares as
of December 31, 2017
and 495,248,369 as of
December 31, 2016 5 5
Preferred stock, $0.01
par value, 10,000,000 2016, converted to
shares authorized, common stock in
6.25% Series B January 2018
Mandatory
Convertible, $1,000
per share liquidation
preference, 1,725,000
shares issued and
outstanding as of
December 31, 2017 and - -
Additional paid-in
capital to common
stock 4,698 4,677
Accumulated deficit (2,679) (3,725)
Accumulated other
comprehensive loss (44) (39)
Common stock in
treasury; 31,269
shares as of December
31, 2017 and 2016 (1) (1)
--- ---
Total equity 1,979 917
----- ---
Total liabilities and
equity $7,521 $7,076
====== ======
STATEMENTS OF CASH FLOWS
(Unaudited)
Southwestern Energy Company
and Subsidiaries
For the years ended
December 31,
2017 2016
---- ----
(in millions)
Cash Flows From Operating
Activities:
Net income (loss) $1,046 $(2,643)
Adjustments to reconcile net
income (loss) to net cash
provided by operating
activities:
Depreciation, depletion and
amortization 504 436
Impairment of natural gas
and oil properties - 2,321
Amortization of debt
issuance costs 9 14
Deferred income taxes (71) (22)
(Gain) loss on derivatives,
net of settlement (451) 373
Stock-based compensation 24 29
Gain on sales of assets, net (6) -
Restructuring charges - 30
Loss on early extinguishment
of debt 70 51
Other 13 8
Change in assets and
liabilities (41) (99)
--- ---
Net cash provided by
operating activities 1,097 498
----- ---
Cash Flows From Investing
Activities:
Capital investments (1,268) (593)
Proceeds from sale of
property and equipment 10 430
Other 6 1
--- ---
Net cash used in investing
activities (1,252) (162)
------ ----
Cash Flows From Financing
Activities:
Payments on current portion
of long-term debt (328) (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 9 (20)
Proceeds from issuance of
long-term debt 1,150 1,191
Payment of debt issuance
costs (24) (17)
Proceeds from issuance of
common stock - 1,247
Preferred stock dividend (16) (27)
Cash paid for tax
withholding (2) (9)
Other (2) (1)
--- ---
Net cash provided by (used
in) financing activities (352) 1,072
---- -----
Increase (decrease) in cash
and cash equivalents (507) 1,408
Cash and cash equivalents at
beginning of year 1,423 15
----- ---
Cash and cash equivalents at
end of year $916 $1,423
==== ======
SEGMENT INFORMATION (Unaudited)
Southwestern Energy
Company and
Subsidiaries Exploration
and Midstream
(in millions) Production Services Other Eliminations Total
---------- -------- ----- ------------ -----
Three months ended
December 31, 2017
------------------
Revenues $527 $784 $ - $(502) $809
Marketing purchases - 683 - (447) 236
Operating expenses 218 24 - (55) 187
General and
administrative
expenses 55 8 - - 63
Depreciation,
depletion and
amortization 123 17 - - 140
Taxes, other than
income taxes 17 1 1 - 19
Gain on sale of
assets, net - (3) - - (3)
Operating income
(loss) 114 54 (1) - 167
Capital investments(1) 327 11 9 - 347
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
Twelve months ended
December 31, 2017
-------------------
Revenues $2,086 $3,198 $ - $(2,081) $3,203
Marketing purchases - 2,824 - (1,848) 976
Operating expenses 809 95 - (233) 671
General and
administrative
expenses 202 31 - - 233
Depreciation,
depletion and
amortization 440 64 - - 504
Gain on sale of asset,
net - (6) - - (6)
Taxes, other than
income taxes 86 7 1 - 94
Operating income
(loss) 549 183 (1) - 731
Capital investments(1) 1,248 32 13 - 1,293
Twelve months 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
(1) Capital investments includes
increases of $13 million and
$67 million for the three
months ended December 31, 2017
and 2016, respectively, and an
increase of $43 million for the
year ended December 31, 2016
relating to the change in
accrued expenditures between
periods. There was no impact to
the year ended December 31,
2017.
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SOURCE Southwestern Energy Company
