Raises full year 2018 production guidance with
no increase to capital investment guidance Expects portfolio to
generate modest free cash flow in 2018
Southwestern Energy Company (NYSE: SWN) today announced its
second quarter financial and operating results. Unless noted,
results are compared to the second quarter of 2017.
“This quarter’s strong performance reflects increased margins,
improved capital efficiency, and higher production growth,” said
Bill Way, President and Chief Executive Officer of Southwestern
Energy. “Our strategy of delivering growing value from our
high-return Appalachia assets, and shift towards greater liquids
while achieving greater operational efficiencies, are creating
enhanced returns for our shareholders. This is underscored by our
assets’ projected ability to generate modest free cash flow in 2018
without raising capital guidance.”
Second Quarter Highlights
- Generated net cash provided by
operating activities of $300 million and net cash flow of $280
million, up 13% and 12%, respectively
- Delivered on previously announced cost
initiatives, saving over $110 million annually (beginning in 2019)
through G&A and interest reductions
- Realized NGL and oil pricing, including
hedges, of $15.05 and $59.22 per barrel, up 34% and 46%,
respectively
- Increased margins in Southwest
Appalachia by 76% to $1.60 per Mcfe
- Exceeded production guidance, reporting
net production of 234 Bcfe, up 5%
- Delivered a 19% increase in Appalachia
Basin net production of 167 Bcfe or 1.8 Bcfe per day, including 20%
liquids production
- Produced 44% higher natural gas liquids
and oil of 61,370 barrels per day
- Improved well development efficiency
driven by leading operational execution, completing 56 wells, 13
ahead of original development plan
- Added extended lateral inventory in the
Tioga development area through a joint development arrangement
- Reported net income attributable to
common stock of $51 million, or $0.09 per diluted share, and
adjusted net income attributable to common stock of $105 million,
or $0.18 per diluted share
Full Year Update
- Maintaining full-year $1.15 - $1.25
billion capital investment guidance; second quarter capital
investment of $403 million, consistent with front end loaded
plan
- Expecting existing portfolio to
generate modest cash flow above full year capital investment at
current prices, with any excess cash applied to outstanding
borrowings on the revolving bank facility
- Raising net production guidance to 955
- 970 Bcfe, up from 930 - 965 Bcfe (see Production Guidance table
below)
- Increasing Appalachia Basin net
production guidance to 695 - 707 Bcfe, up 21% (based on midpoints)
compared to 2017
The Company will invest within its original full-year capital
investment guidance of $1.15 to $1.25 billion. Capital investment
for the second quarter totaling $403 million was consistent with
the Company’s planned capital program, including $311 million
related to drilling and completion operations, primarily in the
Appalachia Basin. Improved operational efficiency gains and
successful operational execution have positively affected the pace
of activity. The Company has been able to accelerate completion of
an additional 13 wells in the second quarter compared to the
original plan, which will result in a production benefit throughout
the year. The Company now expects to be toward the high end of its
total 2018 well count guidance of 105 to 125 completed wells. The
Company is progressing its previously announced water project in
Southwest Appalachia, which is expected to be operational by year
end with the majority of the capital to be invested during the
second half of the year.
The Company is raising full-year net production guidance to 955
- 970 Bcfe, driven by liquids growth in Southwest Appalachia and
production improvements in Northeast Appalachia. In Southwest
Appalachia, the Company continues to focus on liquids production
and has raised total NGL and oil barrels guidance by 5% (based on
midpoints), or 2,700 barrels per day, compared to original
guidance. Northeast Appalachia production is expected to increase
by 15 Bcf (based on midpoints) due to the continued benefit from
well outperformance, operational execution and gathering capacity
improvements.
Production Guidance (1)
1st Quarter 2nd Quarter 3rd Quarter
4th Quarter Total Year Guidance: Natural Gas
(Bcf) 197 201 213 – 218 210 – 217 821 – 833 NGLs (MBbls) 4,230
4,862 4,900 – 5,100 5,250 – 5,400 19,242 – 19,592 Oil (MBbls) 613
723 900 – 1,000 900 – 1,000 3,136 – 3,336
Total Production
(Bcfe) 226 234 248 – 255 247 – 255
955 – 970 Total Production (MMcfe/d) 2,511
2,571 2,696 – 2,772 2,685 – 2,772 2,616 –
2,658 Full-Year Production by Division
Production (Bcfe) Northeast Appalachia 459 – 465
Southwest Appalachia 236 – 242 Fayetteville Shale 260 – 263
Total 955 – 970 (1) Consistent with
original guidance, the updated guidance excludes any impact from
Fayetteville strategic alternatives announced in February 2018.
Second Quarter 2018 Financial
Results
FINANCIAL STATISTICS (Unaudited) For the three months For
the six months ended ended June 30, June 30,
2018 2017
2018 2017
Financial Results (in millions, except per
share amounts) Net income attributable to common stock
$
51 $ 224
$ 257 $ 505 Adjusted net income
attributable to common stock (non-GAAP measure)
$ 105
$ 40
$ 267 $ 127 Adjusted EBITDA (non-GAAP measure)
$ 317 $ 281
$ 713 $ 631 Net cash
provided by operating activities
$ 300 $ 266
$
664 $ 578 Net cash flow (non-GAAP measure)
$
280 $ 250
$ 638 $ 568 Total capital
investments
$ 403 $ 325
$ 741 $ 615
Southwestern Energy recorded net income attributable to common
stock of $51 million or $0.09 per diluted share. Compared to the
second quarter of 2017, net income attributable to common stock was
lower primarily due to an unrealized marked to market loss
(non-cash) on hedging positions of $56 million in 2018 compared to
a $173 million gain in 2017.
Adjusted net income attributable to common stock was $105
million, or $0.18 per diluted share for the second quarter of 2018
and adjusted earnings before interest, taxes and amortization
(“adjusted EBITDA”) was $317 million, a 13% increase compared to
the second quarter of 2017. The primary components of adjusted
EBITDA included $195 million from Appalachia operations, $56
million from Fayetteville operations, and $45 million from
Midstream operations. The increase in adjusted EBITDA was primarily
due to a 44% increase in liquids production along with stronger
realized oil and NGL pricing and a 1% increase in gas production,
partially offset by lower natural gas prices.
Weighted average realized pricing, including derivatives,
transportation and the benefit of higher NGL and oil pricing, was
$2.30 per Mcfe compared to a NYMEX gas price of $2.80 per Mcf. The
Company was able to mitigate the effect of a $0.38 per Mcf lower
NYMEX gas price compared to the same period in 2017 through
improvement in differentials, growth in liquids pricing and
production, along with a realized hedge gain of $0.09 per Mcfe in
2018.
At June 30, 2018, the Company had liquidity of $1.5 billion and
debt of $3.6 billion. During the quarter, the Company’s credit
ratings were upgraded one notch by S&P and Moody’s to BB and
Ba2, respectively.
Southwestern Energy continues to execute a disciplined hedging
program with physical, financial and basis hedges on its forecasted
natural gas, natural gas liquids and oil production. In line with
the Company’s focus on increased liquids exposure, the majority of
hedging activity during the quarter was focused on ethane and
propane fixed price swaps. A summary of the Company’s financial
hedging position is provided in the attached financial tables.
Additional information on physical derivatives, natural gas liquids
and oil financial derivatives can be found in the 10-Q.
E&P Operational
Review
Improvement in operational cycle times, increased gathering
capacity and stronger well results drove higher net production
volumes of 234 Bcfe, including 5,585 MBbls, or 61,370 barrels per
day, from natural gas liquids and condensate. Liquids production
exceeded the top end of guidance by 9%. Appalachia Basin production
totaled 167 Bcfe, a 19% increase. The Company invested $396 million
in E&P capital and drilled 37 wells, completed 56 wells and
placed 45 wells to sales.
OPERATING STATISTICS For the three months ended For the six
months ended June 30, June 30,
2018 2017
2018 2017
Production Gas production (Bcf)
201 199
398
382 Oil production (MBbls)
723 565
1,336 1,084 NGL
production (MBbls)
4,862 3,316
9,092 6,324 Total
production (Bcfe)
234 222
460 426
Division
Production Northeast Appalachia (Bcf)
112 97
220
184 Southwest Appalachia (Bcfe)
55 43
106 79
Fayetteville Shale (Bcf)
67 82
134 163
Average unit costs per Mcfe Lease operating expenses
$ 0.91 $ 0.89
$ 0.93 $ 0.89 General
& administrative expenses(1)
$ 0.19 $ 0.23
$ 0.20 $ 0.22 Taxes, other than income taxes(2,3)
$ 0.06 $ 0.10
$ 0.07 $ 0.11 Full cost
pool amortization
$ 0.50 $ 0.44
$ 0.49
$ 0.42 (1) Excludes $15 million of
restructuring charges and $7.9 million of legal settlement charges
for the three and six months ended June 30, 2018.
(2)
Excludes $1 million of restructuring
charges for the three and six months ended June 30, 2018.
(3)
Decrease primarily due to an $8 million
severance tax refund related to a favorable assessment on
deductible expenses in Southwest Appalachia for the three and six
months ended June 30, 2018.
COMMODITY PRICES For the three months ended For the
six months ended June 30, June 30,
2018 2017
2018
2017
Natural Gas Price: NYMEX Henry Hub Price ($/MMBtu) (1)
$ 2.80 $ 3.18
$ 2.90 $ 3.25 Discount to
NYMEX (2)
(0.81 ) (0.83 )
(0.55 ) (0.72
) Average realized gas price per Mcf, excluding derivatives
$ 1.99 $ 2.35
$ 2.35 $ 2.53 Gain (loss)
on settled financial basis derivatives ($/Mcf)
(0.01
) (0.15 )
(0.06 ) (0.08 ) Gain (loss) on
settled commodity derivatives ($/Mcf)
0.13 (0.05 )
0.10 (0.10 ) Average realized gas price per Mcf, including
derivatives
$ 2.11 $ 2.15
$ 2.39 $ 2.35
Oil Price: WTI oil price ($/Bbl)
$ 67.88 $
48.28
$ 65.37 $ 50.10 Discount to WTI
(7.73
) (7.72 )
(7.12 ) (8.02 ) Average oil price
per Bbl, excluding derivatives
$ 60.15 $ 40.56
$ 58.25 $ 42.08 Average oil price per Bbl, including
derivatives
$ 59.22 $ 40.56
$ 57.74 $
42.08
NGL Price: Average net realized NGL price per Bbl,
excluding derivatives
$ 15.37 $ 11.21
$
15.39 $ 12.19 Average net realized NGL price per Bbl,
including derivatives
$ 15.05 $ 11.25
$
15.22 $ 12.22 Percentage of WTI
23 % 23 %
24 % 24 % Average net realized C3+ price per Bbl,
excluding derivatives
$ 33.11 $ 21.62
$
34.49 $ 25.68 Average net realized C3+ price per Bbl,
including derivatives
$ 32.32 $ 21.62
$
34.07 $ 25.68 Percentage of WTI
49 % 45 %
53 % 51 %
Total Weighted Average Realized
Price: Excluding derivatives ($/Mcfe)
$ 2.21 $
2.37
$ 2.51 $ 2.55 Including derivatives ($/Mcfe)
$ 2.30 $ 2.20
$ 2.53 $ 2.39
(1) Based on last day monthly futures settlement
prices
(2)
This discount includes a basis
differential, a heating content adjustment, physical basis sales,
third-party transportation charges and fuel charges, and excludes
financial basis derivatives.
Three Months
Ended June 30, 2018 E&P Division Results Appalachia
Fayetteville Northeast Southwest Shale
Production (Bcfe)(1) 112 55 67 Gross operated production as of June
2018 (MMcfe/d) 1,563 992 1,065 Net operated production as of June
2018 (MMcfe/d) 1,304 615 705
Capital investments ($ in
millions) Exploratory and development drilling, including
workovers $ 135 $ 168 $ 4 Acquisition and leasehold 3 12 – Seismic
and other 1 2 2 Capitalized interest and expense 10
38 4 Total capital investments $ 149 $
220 $ 10
Gross operated well activity summary Drilled
17 20 – Completed 25 30 1 Wells to sales 17 26 2 Average
completed well cost (in millions) $ 8.2
(2)
$ 8.9 $ 5.6 Average lateral length (in ft) 7,748 7,851 6,793
Realized Natural Gas Price NYMEX Henry Hub Price ($/MMBtu) $
2.80 $ 2.80 $ 2.80 Discount to NYMEX (3) (0.90 )
(0.57 ) (0.72 ) Average realized gas price per Mcf,
excluding derivatives $ 1.90 $ 2.23 $ 2.08
Total weighted average realized price per Mcfe, excluding
derivatives $ 1.90 $ 3.00 $ 2.08 (1) Southwest
Appalachia production included 22 Bcf of natural gas, 4,850 MBbls
of NGLs and 707 MBbls of oil.
(2)
Average well costs includes amounts for
delineation and science.
(3)
This discount includes a basis
differential, a heating content adjustment, physical basis sales,
third-party transportation charges and fuel charges, and excludes
financial basis derivatives.
Northeast Appalachia – Total net production of 112 Bcf,
or 1.2 Bcf per day, was 15% higher than the second quarter of 2017.
The Company placed 17 wells to sales in the second quarter, 11 of
which were online for at least 30 days and utilized the latest
completion and flowback design and had an average 30-day rate of
17.2 MMcf per day.
The Company has expanded its core position in Tioga to 37,500
net acres. In July, the Company entered into a joint development
agreement with a private firm, adding 23 future drilling locations
with projected lateral lengths averaging 11,000 feet.
The Company is continuing to enhance returns in Tioga, by
coupling additional cost savings with improving well results. In
the second quarter, a three-well pad in Tioga utilized water from
the previously announced water project and benefited from eight
completion stages per day, reducing completion costs by 12%
compared to the first development pad in that area. Eight wells
were placed to sales and are outperforming historical offsets due
to operational improvements including optimized completion designs,
targeted drilling zones and the benefit of field-wide compression.
Of note, a two-well pad had an average lateral length of 7,250 feet
and an average 30-day rate of 23.9 MMcf per day, outperforming the
initial Tioga development pad by 49%.
Southwest Appalachia – Total net production was 55 Bcfe,
or 604 MMcfe per day, including 60% liquids. Natural gas liquids
and oil production averaged 53,300 and 7,800 barrels per day,
respectively, representing increases of 47% and 31% compared to the
second quarter of 2017.
During the quarter, the Company continued to focus on the rich
gas area in West Virginia, which provides some of the highest
margins in the Company, bringing 26 wells online. Southwest
Appalachia’s margin in the second quarter of 2018 was 76% higher,
at $1.60 per Mcfe, compared to the same period in 2017. The margin
improvement was primarily driven by higher liquids production and
prices, which provided a $0.77 per Mcfe uplift in realized pricing.
The weighted average realized price was $3.00 per Mcfe compared to
a realized natural gas prices of $2.23 per Mcf.
The Company’s rich gas wells account for approximately 75% of
the Company’s drilling efforts in Southwest Appalachia in 2018. Two
wells on a recently developed pad are still producing 1,500 barrels
of condensate per day after 90 days of production and are among the
highest condensate producers reported in the Basin.
The Company continues to realize the benefits of improving
capital efficiencies as evidenced by a three-well pad that was
drilled and completed at approximately $940 per foot. The pad
benefited from increased completion stages pumped per day and
reduced cycle times, which decreased costs and accelerated
production. The three wells averaged an extended lateral length of
over 10,700 feet and proppant loading of 2,500 pounds per foot with
an average cost of $10.1 million per well.
Fayetteville Shale – During the second quarter of 2018,
the Company produced 67 Bcf of natural gas from the Fayetteville
Shale, compared to 82 Bcf in the second quarter of 2017, while
generating positive net cash provided by operating activities, net
of capital investments, of $78 million for its E&P and
midstream business.
The Company placed two redevelopment wells online in mid-April,
which utilize advanced completion designs and optimized landing
zones. These wells have been online over 90 days, and in addition
the initial redevelopment well has been online over 275 days. All
of these wells continue to outperform offset well EURs by 25% to
50%. In addition, the Company is continuing to focus on its base
production optimization efforts to manage the impact of natural
decline.
Conference Call
Southwestern management will host a conference call and webcast
on Friday, August 3, 2018 at 9:00 a.m. Central to discuss second
quarter 2018 results. To participate, dial US toll-free
877-883-0383, or international 412-902-6505 and enter access code
6510656. The conference call will webcast live at 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
our website: 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, or the execution or realization of any
specific strategic alternative, which the Company has previously
announced it is exploring for its Fayetteville Shale assets;
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.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
For the three months ended For the six months
ended June 30, June 30,
2018 2017
2018
2017 (in millions, except share/per share amounts)
Operating Revenues Gas sales
$ 407 $ 471
$ 947 $ 974 Oil sales
44 23
79 46 NGL
sales
75 37
140 77 Marketing
265 250
518 503 Gas gathering
24 30
48 57 Other
1 –
4 –
816 811
1,736 1,657
Operating Costs and
Expenses Marketing purchases
265 253
520 504
Operating expenses
193 164
382 311 General and
administrative expenses
59 58
114 108 Restructuring
charges
18 –
18 – Depreciation, depletion and
amortization
142 123
285 229 Taxes, other than income
taxes
15 25
38
51
692 623
1,357 1,203
Operating
Income 124 188
379 454
Interest Expense
Interest on debt
59 59
124 117 Other interest charges
2 3
4 5 Interest capitalized
(29
) (28 )
(57 ) (56 )
32 34
71 66
Gain (Loss) on Derivatives
(1) (36 ) 134
(43 ) 250
Loss
on Early Extinguishment of Debt (8 ) (10 )
(8 ) (11 )
Other Income, Net 3
6
2 8
Income Before Income Taxes 51 284
259
635
Provision (Benefit) for Income Taxes Deferred
– –
– –
– –
–
–
Net Income $ 51
$ 284
$ 259 $ 635
Mandatory
convertible preferred stock dividend – 27
– 54
Participating securities - mandatory convertible preferred
stock – 33
2
76
Net Income Attributable to Common
Stock $ 51 $ 224
$
257 $ 505
Income Per Common
Share Basic
$ 0.09 $ 0.45
$
0.45 $ 1.02 Diluted
$ 0.09
$ 0.45
$ 0.44 $ 1.02
Weighted Average Common Shares Outstanding Basic
581,159,200
496,419,815
576,255,744
494,753,391 Diluted
582,878,106
498,224,599
578,222,740
496,627,843
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December
31,
2018 2017
ASSETS (in millions) Current assets:
Cash and cash equivalents
$ 37 $ 916 Accounts
receivable, net
416 428 Derivative assets
71 130
Other current assets
43 35 Total
current assets
567 1,509 Natural gas and oil properties,
using the full cost method, including $1,835 million as of June 30,
2018 and $1,817 million as of December 31, 2017 excluded from
amortization
24,611 23,890 Gathering systems
1,322
1,315 Other
576 564 Less: Accumulated depreciation,
depletion and amortization
(20,276 )
(19,997 ) Total property and equipment, net
6,233 5,772
Other long-term assets
242 240
TOTAL ASSETS
$ 7,042 $ 7,521
LIABILITIES AND EQUITY Current liabilities: Accounts payable
$ 642 $ 533 Taxes payable
58 62 Interest
payable
68 70 Dividends payable
– 27 Derivative
liabilities
66 64 Other current liabilities
24
24 Total current liabilities
858 780
Long-term debt
3,570 4,391 Pension and other postretirement
liabilities
55 58 Other long-term liabilities
309 313 Total long-term liabilities
3,934 4,762 Equity: Common stock, $0.01 par value;
1,250,000,000 shares authorized; issued 586,430,101 shares as of
June 30, 2018 and 512,134,311 as of December 31, 2017
6 5
Preferred stock, $0.01 par value, 10,000,000 shares authorized,
6.25% Series B Mandatory Convertible, $1,000 per share liquidation
preference, 1,725,000 shares issued and outstanding as of December
31, 2017, converted to common stock on January 12, 2018
– –
Additional paid-in capital
4,709 4,698 Accumulated deficit
(2,420 ) (2,679 ) Accumulated other comprehensive
loss
(44 ) (44 ) Common stock in treasury; 31,269
shares as of June 30, 2018 and December 31, 2017, respectively
(1 ) (1 ) Total equity
2,250 1,979 TOTAL LIABILITIES AND
EQUITY
$ 7,042 $ 7,521
SOUTHWESTERN ENERGY COMPANY AND
SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) For the six months ended June 30, 2018 2017 (in
millions)
Cash Flows From Operating Activities: Net income
$ 259 $ 635 Adjustments to reconcile net income to
net cash provided by operating activities: Depreciation, depletion
and amortization
285 229 Amortization of debt issuance costs
4 4 (Gain) loss on derivatives, unsettled
54 (319 )
Stock-based compensation
9 12 Loss on early extinguishment
of debt
8 11 Other
1 (4 ) Change in assets and
liabilities
44 10 Net cash
provided by operating activities
664
578
Cash Flows From Investing Activities:
Capital investments
(684 ) (619 ) Proceeds from sale
of property and equipment
6 12 Other
3
1 Net cash used in investing activities
(675 ) (606 )
Cash Flows From
Financing Activities: Payments on long-term debt
(1,191
) (287 ) Payments on revolving credit facility
(645
) – Borrowings under revolving credit facility
1,005
– Change in bank drafts outstanding
– 3 Debt issuance costs
(9 ) – Preferred stock dividend
(27 ) –
Cash paid for tax withholding
(1 ) –
Net cash used in financing activities
(868
) (284 ) Decrease in cash and cash equivalents
(879 ) (312 ) Cash and cash equivalents at beginning
of year
916 1,423 Cash and cash
equivalents at end of period
$ 37 $ 1,111
SOUTHWESTERN ENERGY COMPANY AND
SUBSIDIARIES SEGMENT INFORMATION (Unaudited)
Exploration
and Midstream Production
Services Other Eliminations Total (in
millions)
Three months
ended June 30, 2018
Revenues $ 520 $ 797 $
– $ (501 ) $ 816
Marketing purchases – 716 – (451
) 265 Operating expenses 215 28
– (50 ) 193 General and
administrative expenses 53
(1)
6 – – 59 Restructuring charges
16 2 – – 18 Depreciation,
depletion and amortization 126 16 –
– 142 Taxes, other than income taxes 13
2 – – 15 Operating income
97 27 – – 124 Capital
investments (2) 396 5 2 –
403
Three months ended
June 30, 2017
Revenues $ 526 $ 822 $ – $ (537 ) $ 811 Marketing purchases – 731 –
(478 ) 253 Operating expenses 200 23 – (59 ) 164 General and
administrative expenses 50 8 – – 58 Depreciation, depletion and
amortization 107 16 – – 123 Taxes, other than income taxes 23 2 – –
25 Operating income 146 42 – – 188 Capital investments (2) 318 6 1
– 325
Six months ended
June 30, 2018
Revenues $ 1,157 $ 1,693
$ – $ (1,114 ) $
1,736 Marketing purchases – 1,535
– (1,015 ) 520 Operating
expenses 428 53 – (99 )
382 General and administrative expenses 101
(1)
13 – – 114 Restructuring charges
16 2 – – 18 Depreciation,
depletion and amortization 243 42
(3)
– – 285 Taxes, other than income taxes
34 4 – – 38 Operating
income 335 44 – – 379
Capital investments (2) 730 9 2
– 741
Six months ended
June 30, 2017
Revenues $ 1,089 $ 1,680 $ – $ (1,112 ) $ 1,657 Marketing purchases
– 1,496 – (992 ) 504 Operating expenses 381 50 – (120 ) 311 General
and administrative expenses 93 15 – – 108 Depreciation, depletion
and amortization 197 32 – – 229 Taxes, other than income taxes 47 4
– – 51 Operating income 371 83 – – 454 Capital investments (2) 601
12 2 – 615 (1) Includes $7.9 million of legal
settlement charges.
(2)
Capital investments include increases of
$19 million and $41 million for the three months ended June 30,
2018 and 2017, respectively, and an increase of $52 million and a
decrease of $11 million for the six months ended June 30, 2018 and
2017, respectively, relating to the change in capital accruals
between periods.
(3)
Includes a $10 million impairment related
to certain non-core gathering assets.
Hedging Summary
A detailed breakdown of the Company’s natural gas derivative
financial instruments and financial basis positions as of July 31,
2018 is shown below. Please refer to our quarterly report on Form
10-Q to be filed with the Securities and Exchange Commission for
complete information on the Company’s commodity, basis and interest
rate protection.
Financial protection on production Weighted
Average Price per MMBtu Volume Sold
Purchased Sold (Bcf) Swaps Puts
Puts Calls Natural Gas
2018
Sold fixed price swaps 156 $ 2.96 $ – $ – $ – Two-way costless
collars 6 – – 2.90 3.27 Three-way costless collars 143 – 2.40 2.97
3.37
Total
305
2019
Sold fixed price swaps 147 $ 2.93 $ – $ – $ – Two-way costless
collars 53 – – 2.80 2.98 Three-way costless collars 133 – 2.49 2.93
3.34
Total
333
2020
Sold fixed price swaps 2 $ 2.77 $ – $ – $ – Three-way costless
collars 47 – 2.43 2.80 3.09 Total 49
Other Derivative Contracts Weighted Average
Volume Strick Price per (Bcf) MMBtu
Purchased Call Options - Natural Gas
2020
68 $ 3.63
2021
57 3.52 Total 125
Sold Call Options - Natural Gas
2018
31 $ 3.50
2019
52 3.50
2020
137 3.39
2021
114 3.33 Total 334
Financial basis positions Volume
Basis Differential
(excludes physical positions) (Bcf)
($/MMBTU) Q3 2018 Dominion South 16.8 $ (0.65 ) TETCO
M3 11.5 (0.51 ) Total 28.3 $ (0.60 ) 2018 Dominion
South 26.6 $ (0.65 ) TETCO M3 17.8 (0.48 ) Total 44.4 $
(0.58 ) 2019 Dominion South 1.0 $ (0.63 ) TETCO M3 9.7
1.44 Total 10.7 $ 1.24
Note: 2018 includes Q3 2018 positions
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
six months ended June 30, 2018 and June 30, 2017, 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 June 30,
2018 2017 (in millions)
Net income attributable to
common stock: Net income attributable to common stock $ 51 $
224 Add back: Participating securities – mandatory convertible
preferred stock − 27 Restructuring charges 18 − (Gain) loss on
certain derivatives 56 (173 ) Gain on sale of assets, net − (2 )
Loss on early extinguishment of debt 8 10 Legal settlement charges
8 − Adjustments due to inventory valuation and other (1 ) (1 )
Adjustments due to discrete tax items(1) (13 ) (108 ) Tax impact on
adjustments (22 ) 63 Adjusted net income
attributable to common stock $ 105 $ 40
(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.
6 Months Ended June 30,
2018 2017 (in millions)
Net income attributable to
common stock: Net income attributable to common stock $ 257 $
505 Add back: Participating securities – mandatory convertible
preferred stock − 57 Impairment of non-core gathering assets 10 −
Restructuring charges 18 − (Gain) loss on certain derivatives 54
(319 ) Gain on sale of assets, net (1 ) (3 ) Loss on early
extinguishment of debt 8 11 Legal settlement charges 8 −
Adjustments due to inventory valuation and other 2 (1 ) Adjustments
due to discrete tax items(1) (64 ) (242 ) Tax impact on adjustments
(25 ) 119 Adjusted net income attributable to
common stock $ 267 $ 127 (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 June 30,
2018 2017 Diluted earnings per share: Diluted
earnings per share $ 0.09 $ 0.45 Add back: Participating securities
- mandatory convertible preferred stock − 0.06 Restructuring
charges 0.03 − (Gain) loss on certain derivatives 0.10 (0.36 ) Gain
on sale of assets, net − (0.00 ) Loss on early extinguishment of
debt 0.01 0.02 Legal settlement charges 0.01 − Adjustments due to
inventory valuation and other (0.00 ) (0.00 ) Adjustments due to
discrete tax items(1) (0.02 ) (0.22 ) Tax impact on adjustments
(0.04 ) 0.13 Adjusted diluted earnings per
share $ 0.18 $ 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.
6 Months Ended June 30,
2018 2017 Diluted earnings per share: Diluted
earnings per share $ 0.44 $ 1.02 Add back: Participating securities
- mandatory convertible preferred stock − 0.11 Impairment of
non-core gathering assets 0.02 − Restructuring charges 0.03 −
(Gain) loss on certain derivatives 0.09 (0.64 ) Gain on sale of
assets, net (0.00 ) (0.00 ) Loss on early extinguishment of debt
0.02 0.02 Legal settlement charges 0.01 − Adjustments due to
inventory valuation and other 0.00 (0.00 ) Adjustments due to
discrete tax items(1) (0.11 ) (0.49 ) Tax impact on adjustments
(0.04 ) 0.24 Adjusted diluted earnings per
share $ 0.46 $ 0.26 (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 June 30,
2018 2017 (in millions)
Net cash flow provided by
operating activities: Net cash provided by operating activities
$ 300 $ 266 Add back: Changes in operating assets and liabilities
(38 ) (16 ) Restructuring charges 18 −
Net Cash Flow $ 280 $ 250
6 Months Ended
June 30, 2018 2017 (in millions)
Net cash
provided by operating activities: Net cash provided by
operating activities $ 664 $ 578 Add back: Changes in operating
assets and liabilities (44 ) (10 ) Restructuring charges 18
− Net Cash Flow $ 638 $ 568
3 Months Ended June 30, 2018 2017 (in
millions)
EBITDA: Net income $ 51 $ 284 Add back: Interest
expense 32 34 Income tax expense – – Depreciation, depletion and
amortization 142 123 Restructuring charges 18 – Gain on sale of
assets, net – (2 ) Loss on early extinguishment of debt 8 10 Legal
settlement charges 8 – (Gain) loss on certain derivatives 56 (173 )
Adjustments due to inventory valuation and other (1 ) (1 ) Stock
based compensation expense 3 6 Adjusted
EBITDA $ 317 $ 281
6 Months Ended June
30, 2018 2017 (in millions)
EBITDA: Net
income
$
259 $ 635 Add back: Interest expense 71 66 Income tax benefit – –
Depreciation, depletion and amortization 285 229 Restructuring
charges 18 – Gain on sale of assets, net (1 ) (3 ) Loss on early
extinguishment of debt and other bank fees 8 11 Legal settlement
charges 8 – (Gain) loss on certain derivatives 54 (319 )
Adjustments due to inventory valuation and other 2 (1 ) Stock based
compensation expense 9 13 Adjusted
EBITDA $ 713 $ 631
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Southwestern Energy CompanyPaige Penchas,
832-796-4068Vice President, Investor
Relationspaige_penchas@swn.com
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