Reduced debt by over $1.0 billion in 2022,
improving financial strength and enhancing resilience through
commodity cycles
Southwestern Energy Company (NYSE: SWN) (the “Company” or
“Southwestern Energy”) today announced financial and operating
results for the fourth quarter and full-year 2022 and provided 2023
guidance.
“In 2022, the Company delivered results that both strengthened
its financial position and demonstrated the tangible benefits of
its expanded and improved asset base. Financially, we repaid over
$1 billion of debt, lowering leverage into our target range, and
secured upgrades to one-notch below investment grade from all three
agencies while also initiating a share repurchase program.
Operationally, we delivered results above plan including successful
integration of our Haynesville assets and performance improvements
in our first year of operations,” said Bill Way, Southwestern
Energy President and Chief Executive Officer.
“Given near-term market conditions, we have proactively
moderated activity, resulting in slightly lower expected production
for 2023, and have the flexibility and optionality in our business
to adjust as needed. In addition, we expect to drive improved
capital efficiency and cost reductions across our operations. We
believe the Company’s deep, high-quality inventory, advantaged
access to growing demand centers including LNG, and financial
strength position it to capitalize on structurally supportive
longer-term natural gas fundamentals and generate sustainable free
cash flow through the cycle,” continued Way.
2022 Highlights
- Generated $3.2 billion net cash provided by operating
activities, $1.8 billion net income and $1.5 billion adjusted net
income (non-GAAP) - Adjusted EBITDA (non-GAAP) of $3.3 billion and
free cash flow (non-GAAP) of $848 million
- Reduced total debt by over $1.0 billion, including the
repayment of Term Loan B in December 2022, lowering leverage to
1.3x net debt to adjusted EBITDA (non-GAAP)
- Repurchased $125 million of common stock
- Received ratings upgrades to one-notch below investment grade
from all three credit agencies; positive outlook by Fitch in August
2022 and S&P in January 2023
- Reported proved reserves of 21.6 Tcfe; post-tax PV-10 of $37.6
billion and pre-tax PV-10 (non-GAAP) of $46.4 billion using SEC
prices
- Produced 1.7 Tcfe, or 4.7 Bcfe per day, including 4.2 Bcf per
day of natural gas and 97 MBbls per day of liquids
- Successfully integrated Haynesville acquisitions and delivered
performance improvements in first year of operations
- Announced a longer-term GHG reduction target and achieved
responsibly sourced gas certification for all production
2023 Guidance
The Company’s 2023 plan continues to optimize economic returns
and cash flow and maintain financial strength through the cycle.
The Company expects to deliver further operational efficiencies and
cost reductions to partially offset the anticipated inflationary
environment. Highlights are presented below; full guidance is
available in the attachments to this press release and on the
Company’s website.
- Production of approximately 4.6 Bcfe per day, including
approximately 4.0 Bcf per day of natural gas and 100 MBbls per day
of liquids
- Capital investment of $2.2 to $2.5 billion inclusive of $200 to
$220 million in capitalized interest and expense
- Expect to average 10 – 11 rigs and 4 – 5 frac fleets, down from
13 rigs and 5 fleets in 2022
- Estimate 138 to 148 gross operated wells to sales including 70
to 75 in the Haynesville with an average lateral length of
approximately 8,500 feet and 68 to 73 in Appalachia with an average
lateral length of greater than 15,000 feet
- Basis protected for approximately 90% of expected natural gas
production - Haynesville protected through firm sales and
transportation to Gulf Coast and LNG corridor - Appalachia natural
gas basis protected from in-basin basis exposure through
transportation portfolio, firm sales agreements, and financial
basis hedges
2022 Fourth Quarter and Full Year Results
Results include the impacts of the Indigo and GEP acquisitions,
which closed on September 1, 2021 and December 31, 2021,
respectively.
FINANCIAL STATISTICS
For the three months ended
For the years ended
December 31,
December 31,
(in millions)
2022
2021
2022
2021
Net income (loss)
$
2,901
$
2,361
$
1,849
$
(25
)
Adjusted net income (non-GAAP)
$
287
$
318
$
1,479
$
831
Diluted earnings (loss) per share
$
2.63
$
2.31
$
1.66
$
(0.03
)
Adjusted diluted earnings per share
(non-GAAP)
$
0.26
$
0.31
$
1.33
$
1.05
Adjusted EBITDA (non-GAAP)
$
732
$
671
$
3,283
$
1,779
Net cash provided by operating
activities
$
958
$
533
$
3,154
$
1,363
Net cash flow (non-GAAP)
$
677
$
633
$
3,057
$
1,655
Total capital investments (1)
$
537
$
292
$
2,209
$
1,108
Free cash flow (non-GAAP)
$
140
$
341
$
848
$
547
(1)
Capital investments on the cash flow
statement include an increase of $44 million and an increase of $7
million for the three months ended December 31, 2022 and 2021,
respectively, and an increase of $88 million and an increase of $70
million for the years ended December 31, 2022 and 2021,
respectively, relating to the change in accrued expenditures
between periods.
Fourth Quarter 2022 Financial Results
For the quarter ended December 31, 2022, Southwestern Energy
recorded net income of $2.9 billion, or $2.63 per diluted share.
Adjusting for the impact of the Company’s unsettled derivatives,
tax valuation allowance and other one-time items, adjusted net
income (non-GAAP) was $287 million, or $0.26 per diluted share, and
adjusted EBITDA (non-GAAP) was $732 million. Net cash provided by
operating activities was $958 million, net cash flow (non-GAAP) was
$677 million, and free cash flow (non-GAAP) was $140 million.
As indicated in the table below, fourth quarter 2022 weighted
average realized price, including $0.26 per Mcfe of transportation
expenses, was $5.45 per Mcfe, excluding the impact of derivatives.
Including derivatives, the weighted average realized price for the
quarter was up 2% from $2.81 per Mcfe in 2021 to $2.88 per Mcfe in
2022 primarily due to higher commodity prices, including a 7%
increase in NYMEX and a 7% increase in WTI, partially offset by the
impact of settled derivatives. Fourth quarter 2022 weighted average
realized price before transportation expense and excluding
derivatives was $5.71 per Mcfe.
Full Year 2022 Financial Results
For the year ended December 31, 2022, the Company recorded net
income of $1,849 million, or $1.66 per diluted share. Adjusting for
the impact of the Company’s tax valuation allowance and other
one-time items, adjusted net income (non-GAAP) was $1,479 million,
or $1.33 per diluted share, and adjusted EBITDA (non-GAAP) was
$3,283 million. Net cash provided by operating activities was
$3,154 million, net cash flow (non-GAAP) was $3,057 million, and
free cash flow (non-GAAP) was $848 million.
In 2022, the Company primarily utilized free cash flow generated
to reduce its debt balance. As of December 31, 2022, Southwestern
Energy had total debt of $4.4 billion and net debt to adjusted
EBITDA (non-GAAP) of 1.3x. This compares to total debt of $5.4
billion as of December 31, 2021. At the end of 2022, the Company
had $250 million of borrowings under its revolving credit facility
and $110 million in outstanding letters of credit.
On December 30, 2022, the Company repaid its Term Loan B using
cash on hand and borrowings on its revolving credit facility. On
January 27, 2023 the Company delivered notice to the holders of its
7.75% Senior Notes due 2027 that it intends to redeem such notes on
February 26, 2023, utilizing cash on hand and borrowings under its
revolving credit facility.
The Company is currently one-notch below an investment grade
credit rating by all three credit agencies. In January 2023,
S&P updated Southwestern Energy to positive outlook, joining
Fitch, which updated the Company to positive outlook in August
2022.
In 2022, the Company repurchased 17.3 million shares of its
common stock for a total cost of approximately $125 million. In the
fourth quarter of 2022, the Company repurchased 3.6 million shares
of its common stock for a total cost of approximately $25
million.
As indicated in the table below, for the full year 2022,
weighted average realized price, including $0.25 per Mcfe of
transportation expenses, was $6.10 per Mcfe, excluding the impact
of derivatives. Including derivatives, the weighted average
realized price for the quarter was up 21% from $2.53 per Mcfe in
2021 to $3.06 per Mcfe in 2022 primarily due to higher commodity
prices, including a 73% increase in NYMEX and a 39% increase in
WTI, partially offset by the impact of settled derivatives. In
2022, the weighted average realized price before transportation
expense and excluding derivatives was $6.35 per Mcfe.
Realized Prices
For the three months ended
For the years ended
(includes transportation costs)
December 31,
December 31,
2022
2021
2022
2021
Natural Gas Price:
NYMEX Henry Hub price ($/MMBtu) (1)
$
6.26
$
5.83
$
6.64
$
3.84
Discount to NYMEX (2)
(0.79
)
(0.73
)
(0.66
)
(0.53
)
Realized gas price, excluding derivatives
($/Mcf)
$
5.47
$
5.10
$
5.98
$
3.31
Gain on settled financial basis
derivatives ($/Mcf)
0.17
0.05
0.08
0.09
Loss on settled commodity derivatives
($/Mcf)
(2.98
)
(2.55
)
(3.27
)
(1.12
)
Realized gas price, including derivatives
($/Mcf)
$
2.66
$
2.60
$
2.79
$
2.28
Oil Price:
WTI oil price ($/Bbl) (3)
$
82.65
$
77.19
$
94.23
$
67.92
Discount to WTI (4)
(7.71
)
(8.27
)
(7.28
)
(9.12
)
Realized oil price, excluding derivatives
($/Bbl)
$
74.94
$
68.92
$
86.95
$
58.80
Realized oil price, including derivatives
($/Bbl)
$
46.15
$
42.03
$
50.83
$
40.48
NGL Price, per Bbl:
Realized NGL price, excluding derivatives
($/Bbl)
$
25.52
$
36.79
$
34.35
$
28.72
Realized NGL price, including derivatives
($/Bbl)
$
23.40
$
21.44
$
26.52
$
18.20
Percentage of WTI, excluding
derivatives
31
%
48
%
36
%
42
%
Total Weighted Average Realized
Price:
Excluding derivatives ($/Mcfe)
$
5.45
$
5.36
$
6.10
$
3.74
Including derivatives ($/Mcfe)
$
2.88
$
2.81
$
3.06
$
2.53
(1)
Based on last day settlement prices from
monthly futures contracts.
(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.
(3)
Based on the average daily settlement
price of the nearby month futures contract over the period.
(4)
This discount primarily includes location
and quality adjustments.
Operational Results
Total production for the quarter ended December 31, 2022 was 427
Bcfe, comprised of 87% natural gas, 11% NGLs and 2% oil. Production
totaled 1.7 Tcfe for the year ended December 31, 2022.
Capital investments in the fourth quarter of 2022 were $537
million, bringing full year capital investment to $2,209 million.
The Company brought 133 wells to sales, drilled 138 wells and
completed 139 wells during the year.
For the three months ended
For the years ended
December 31,
December 31,
2022
2021
2022
2021
Production
Gas production (Bcf)
372
331
1,520
1,015
Oil production (MBbls)
1,187
1,388
4,993
6,610
NGL production (MBbls)
8,001
7,685
30,446
30,940
Total production (Bcfe)
427
385
1,733
1,240
Average unit costs per Mcfe
Lease operating expenses (1)
$
1.00
$
0.96
$
0.98
$
0.95
General & administrative expenses
(2)(3)
$
0.10
$
0.08
$
0.09
$
0.10
Taxes, other than income taxes
$
0.16
$
0.12
$
0.15
$
0.11
Full cost pool amortization
$
0.72
$
0.53
$
0.67
$
0.42
(1)
Includes post-production costs such as
gathering, processing, fractionation and compression.
(2)
Excludes $27 million in merger-related
expenses for the year ended December 31, 2022.
(3)
Excludes $37 million and $76 million in
merger-related expenses for the three months and year ended
December 31, 2021, respectively. Excludes $7 million in
restructuring charges for the year ended December 31, 2021.
Appalachia – In the fourth quarter, total production was
259 Bcfe, with NGL production of 87 MBbls per day and oil
production of 13 MBbls per day. The Company drilled 15 wells,
completed 12 wells, and placed 15 wells to sales with an average
lateral length of 16,081 feet and average well cost of $857 per
lateral foot.
In 2022, Appalachia’s total production was 1.1 Tcfe, including
97 MBbls per day of liquids. During 2022, the Company drilled 67
wells, completed 67 wells, and placed 63 wells to sales, with an
average lateral length of 14,587 feet. At year-end, the Company had
24 drilled but uncompleted wells in Appalachia. During 2022,
Appalachia well costs averaged $821 per lateral foot for wells
placed to sales.
Haynesville – In the fourth quarter, total production was
168 Bcf. There were 18 wells drilled, 19 wells completed, and 13
wells placed to sales in the quarter with an average lateral length
of 9,065 feet and average well cost of $1,927 per lateral foot.
Production for the year was 679 Bcf in Haynesville. The Company
drilled 71 wells, completed 72 wells, and brought 70 wells to
sales, with an average lateral length of 8,984 feet. The Company
had 29 drilled but uncompleted wells at year-end. During 2022,
Haynesville well costs averaged $1,758 per lateral foot for wells
placed to sales.
E&P Division Results
For the three months ended
December 31, 2022
For the year ended December 31,
2022
Appalachia
Haynesville
Appalachia
Haynesville
Gas production (Bcf)
204
168
841
679
Liquids production
Oil (MBbls)
1,181
5
4,967
20
NGL (MBbls)
8,001
—
30,445
—
Production (Bcfe)
259
168
1,054
679
Capital investments ($ in
millions)
Drilling and completions, including
workovers
$
181
$
262
$
758
$
1,130
Land acquisition and other
23
6
68
20
Capitalized interest and expense
33
19
127
79
Total capital investments
$
237
$
287
$
953
$
1,229
Gross operated well activity
summary
Drilled
15
18
67
71
Completed
12
19
67
72
Wells to sales
15
13
63
70
Total weighted average realized price
per Mcfe, excluding derivatives
$
5.19
$
5.85
$
5.99
$
6.27
Wells to sales summary
For the three months ended
December 31, 2022
For the year ended December 31,
2022
Gross wells to sales
Average lateral length
Gross wells to sales
Average lateral length
Appalachia
Super Rich Marcellus
3
18,900
20
15,198
Rich Marcellus
7
14,711
17
12,983
Dry Gas Utica
2
12,366
12
12,665
Dry Gas Marcellus
3
18,935
14
17,311
Haynesville(1)
13
9,065
70
8,984
Total
28
133
(1)
Gross wells to sales and average lateral
length for the year ended December 31, 2022 includes wells drilled
and completed by previous operators.
2022 Proved Reserves
The Company increased its total proved reserves to 21.6 Tcfe at
year-end 2022, up from 21.1 Tcfe at year-end 2021. The increase was
primarily related to extensions, discoveries and other additions,
partially offset by production.
The after-tax PV-10 (standardized measure) of the Company’s
reserves was $37.6 billion. The PV-10 value before the impact of
taxes (non-GAAP) was $46.4 billion, including $31.4 billion from
Appalachia and $15.0 billion from Haynesville. SEC prices used for
the Company’s reported 2022 reserves were $6.36 per Mcf NYMEX Henry
Hub, $93.67 per Bbl WTI, and $34.35 per Bbl NGLs.
Proved Reserves Summary
For the years ended December
31,
2022
2021
Proved reserves (in Bcfe)
21,625
21,148
PV-10: (in millions)
Pre-tax
$
46,435
$
22,420
PV of taxes
(8,847
)
(3,689
)
After-tax (in millions)
$
37,588
$
18,731
Percent of estimated proved reserves that
are:
Natural gas
80
%
82
%
NGLs and oil
20
%
18
%
Proved developed
56
%
54
%
2022 Proved Reserves by Division
(Bcfe)
Appalachia
Haynesville
Total
Proved reserves, beginning of
year
15,527
5,621
21,148
Price revisions
(4
)
59
55
Performance revisions
381
136
517
Infill revisions
577
—
577
Changes in development plan
(991
)
(333
)
(1,324
)
Performance and production revisions
(33
)
(197
)
(230
)
Extensions, discoveries and other
additions
1,273
1,155
2,428
Production
(1,054
)
(679
)
(1,733
)
Acquisition of reserves in place
—
—
—
Disposition of reserves in place
(43
)
—
(43
)
Proved reserves, end of year
15,666
5,959
21,625
The Company reported 2022 proved developed finding and
development (“PD F&D”) costs of $0.75 per Mcfe when excluding
the impact of capitalized interest and portions of capitalized
G&A costs in accordance with the full cost method of
accounting. The 2022 PD F&D for Appalachia was $0.50 per Mcfe
and Haynesville was $1.17 per Mcfe.
Proved Developed Finding and
Development (1)
12 Months Ended
December 31,
Total PD Adds (Bcfe):
2022
New PD adds
406
PUD conversions
2,160
Total PD Adds
2,566
Costs Incurred (in millions):
Unproved property acquisition costs
$
202
Exploration costs
—
Development costs
2,021
Capitalized Costs Incurred
$
2,223
Subtract (in millions):
Proved property acquisition costs
$
—
Unproved property acquisition costs
(202
)
Capitalized interest and expense
associated with development and exploration (2)
(85
)
PD Costs Incurred
$
1,936
PD F&D (PD Cost Incurred / Total PD
Adds)
$
0.75
Note: Amounts may not add due to
rounding
(1)
Includes Appalachia and Haynesville.
(2)
Adjusting for the impacts of the full cost
accounting method for comparability.
Conference Call
Southwestern Energy will host a conference call and webcast on
Friday, February 24, 2023 at 10:00 a.m. Central to discuss fourth
quarter and fiscal year 2022 results. To participate, dial US
toll-free 877-883-0383, or international 412-902-6506 and enter
access code 1822604. The conference call will webcast live at
www.swn.com.
A replay will also be available on SWN’s website at www.swn.com
following the call.
About Southwestern Energy
Southwestern Energy Company (NYSE: SWN) is a leading U.S.
producer and marketer of natural gas and natural gas liquids
focused on responsibly developing large-scale energy assets in the
nation’s most prolific shale gas basins. SWN’s returns-driven
strategy strives to create sustainable value for its stakeholders
by leveraging its scale, financial strength and operational
execution. For additional information, please visit www.swn.com and
www.swncrreport.com.
Forward Looking Statement
This news release contains “forward-looking statements” within
the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Exchange Act of 1934, as amended.
These statements are based on current expectations. The words
“anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,”
“potential,” “should,” “could,” “may,” “will,” “objective,”
“guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,”
“budget,” “projection,” “goal,” “forecast,” “model,” “target”,
“seek”, “strive,” “would,” “approximate,” and similar words are
intended to identify forward-looking statements. Statements may be
forward looking even in the absence of these particular words.
Examples of forward-looking statements include, but are not
limited to, the expectations of plans, business strategies,
objectives and growth and anticipated financial and operational
performance, including guidance regarding our strategy to develop
reserves, drilling plans and programs (including the number of rigs
and frac crews to be used), estimated reserves and inventory
duration, projected production and sales volume and growth rates,
projected commodity prices, basis and average differential, impact
of commodity prices on our business, projected average well costs,
generation of free cash flow, our return of capital strategy,
including the amount and timing of any redemptions, repayments or
repurchases of our common stock, outstanding debt securities or
other debt instruments, leverage targets, our ability to maintain
or improve our credit ratings, leverage levels and financial
profile, our hedging strategy, our environmental, social and
governance (ESG) initiatives and our ability to achieve anticipated
results of such initiatives, expected benefits from acquisitions,
potential acquisitions and strategic transactions, the timing
thereof and our ability to achieve the intended operational,
financial and strategic benefits of any such transactions or other
initiatives. These forward-looking statements are based on
management’s current beliefs, based on currently available
information, as to the outcome and timing of future events. All
forward-looking statements speak only as of the date of this news
release. The estimates and assumptions upon which forward-looking
statements are based are inherently uncertain and involve a number
of risks that are beyond our control. Although we believe the
expectations expressed in such forward-looking statements are based
on reasonable assumptions, such statements are not guarantees of
future performance, and we cannot assure you that such statements
will be realized or that the events and circumstances they describe
will occur. Therefore, you should not place undue reliance on any
of the forward-looking statements contained herein.
Factors that could cause our actual results to differ materially
from those indicated in any forward-looking statement are subject
to all of the risks and uncertainties incident to the exploration
for and the development, production, gathering and sale of natural
gas, NGLs and oil, most of which are difficult to predict and many
of which are beyond our control. These risks include, but are not
limited to, commodity price volatility, inflation, the costs and
results of drilling and operations, lack of availability of
drilling and production equipment and services, the ability to add
proved reserves in the future, environmental risks, drilling and
other operating risks, legislative and regulatory changes, the
uncertainty inherent in estimating natural gas and oil reserves and
in projecting future rates of production, the quality of technical
data, cash flow and access to capital, the timing of development
expenditures, a change in our credit rating, an increase in
interest rates, our ability to increase commitments under our
revolving credit facility, our hedging and other financial
contracts, our ability to maintain leases that may expire if
production is not established or profitably maintained, our ability
to transport our production to the most favorable markets or at
all, any increase in severance or similar taxes, the impact of the
adverse outcome of any material litigation against us or judicial
decisions that affect us or our industry generally, the effects of
weather or power outages, increased competition, the financial
impact of accounting regulations and critical accounting policies,
the comparative cost of alternative fuels, credit risk relating to
the risk of loss as a result of non-performance by our
counterparties, impacts of world health events, including the
COVID-19 pandemic, cybersecurity risks, geopolitical and business
conditions in key regions of the world, our ability to realize the
expected benefits from acquisitions and strategic transactions, our
ability to achieve our GHG emission reduction goals and the costs
associated therewith, and any other factors described or referenced
under Item 7. “Management's Discussion and Analysis of Financial
Condition and Results of Operations” and under Item 1A. “Risk
Factors” of our Annual Report on Form 10-K for the year ended
December 31, 2022.
We have no obligation and make no undertaking to publicly update
or revise any forward-looking statements, except as required by
applicable law. All written and oral forward-looking statements
attributable to us are expressly qualified in their entirety by
this cautionary statement.
2023 Guidance
1st Quarter
Total Year
PRODUCTION
Gas production (Bcf)
344 – 354
1,430 – 1,500
Liquids (% of production)
~13.5%
~13.0%
Total (Bcfe)
398 – 410
1,650 – 1,725
CAPITAL BY DIVISION (in
millions)
Appalachia
40 – 45%
Haynesville
55 – 60%
Total D&C capital (includes land)
$1,970 – $2,230
Other
$30 – $50
Capitalized interest and expense
$200 – $220
Total capital investments
$2,200 – $2,500
PRICING
Natural gas discount to NYMEX including
transportation (1)
$0.30 – $0.40 per Mcf
$0.55 – $0.70 per Mcf
Oil discount to West Texas Intermediate
(WTI) including transportation
$9.00 – $11.00 per Bbl
$12.00 – $15.00 per Bbl
Natural gas liquids realization as a % of
WTI including transportation (2)
28% – 36%
27% – 35%
EXPENSES
Lease operating expenses
$1.05 – $1.11 per Mcfe
General & administrative expense
$0.08 – $0.12 per Mcfe
Taxes, other than income taxes
$0.16 – $0.20 per Mcfe
Income tax rate (~100% deferred)
23.0%
GROSS OPERATED WELL COUNT (3)
Drilled
Completed
Wells To Sales
Ending DUC Inventory
Appalachia
53 – 58
64 – 69
68 – 73
8 – 13
Haynesville
60 – 65
64 – 69
70 – 75
15 – 20
Total Well Count
113 – 123
128 – 138
138 – 148
23 – 33
(1)
Includes impact of transportation costs
and expected ($0.07) — ($0.09) per Mcf impact (loss) and ($0.02) —
($0.04) per Mcf impact (loss) from financial basis hedges for the
first quarter and full year of 2023, respectively.
(2)
Annual guidance based on $74 per Bbl
WTI.
(3)
Based on the midpoint of capital
investment guidance.
SOUTHWESTERN ENERGY COMPANY
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
OPERATIONS
(Unaudited)
For the three months ended
For the years ended
December 31,
December 31,
(in millions, except share/per share
amounts)
2022
2021
2022
2021
Operating Revenues:
Gas sales
$
2,040
$
1,704
$
9,101
$
3,412
Oil sales
90
97
439
394
NGL sales
204
283
1,046
890
Marketing
1,048
861
4,419
1,963
Other
(2
)
2
(3
)
8
3,380
2,947
15,002
6,667
Operating Costs and Expenses:
Marketing purchases
1,026
848
4,392
1,957
Operating expenses
410
365
1,616
1,170
General and administrative expenses
50
34
170
138
Merger-related expenses
—
37
27
76
Restructuring charges
—
—
—
7
Depreciation, depletion and
amortization
313
212
1,174
546
Impairments
—
—
—
6
Taxes, other than income taxes
71
46
269
132
1,870
1,542
7,648
4,032
Operating Income
1,510
1,405
7,354
2,635
Interest Expense:
Interest on debt
74
66
292
220
Other interest charges
3
4
13
13
Interest capitalized
(32
)
(29
)
(121
)
(97
)
45
41
184
136
Gain (Loss) on Derivatives
1,450
1,025
(5,259
)
(2,436
)
Loss on Early Extinguishment of
Debt
(8
)
(34
)
(14
)
(93
)
Other Income, Net
4
6
3
5
Income (Loss) Before Income
Taxes
2,911
2,361
1,900
(25
)
Provision (Benefit) for Income
Taxes:
Current
10
—
51
—
Deferred
—
—
—
—
10
—
51
—
Net Income (Loss)
$
2,901
$
2,361
$
1,849
$
(25
)
Earnings (Loss) Per Common
Share
Basic
$
2.63
$
2.32
$
1.67
$
(0.03
)
Diluted
$
2.63
$
2.31
$
1.66
$
(0.03
)
Weighted Average Common Shares
Outstanding:
Basic
1,101,245,262
1,015,779,264
1,110,564,839
789,657,776
Diluted
1,103,844,154
1,020,130,445
1,113,184,254
789,657,776
SOUTHWESTERN ENERGY COMPANY
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
December 31, 2022
December 31, 2021
ASSETS
(in millions, except share
amounts)
Current assets:
Cash and cash equivalents
$
50
$
28
Accounts receivable, net
1,401
1,160
Derivative assets
145
183
Other current assets
68
42
Total current assets
1,664
1,413
Natural gas and oil properties, using the
full cost method
35,763
33,631
Other
527
509
Less: Accumulated depreciation, depletion
and amortization
(25,387
)
(24,202
)
Total property and equipment, net
10,903
9,938
Operating lease assets
177
187
Long-term derivative assets
72
226
Other long-term assets
110
84
Total long-term assets
359
497
TOTAL ASSETS
$
12,926
$
11,848
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt
$
—
$
206
Accounts payable
1,835
1,282
Taxes payable
136
93
Interest payable
86
75
Derivative liabilities
1,317
1,279
Current operating lease liabilities
42
42
Other current liabilities
65
75
Total current liabilities
3,481
3,052
Long-term debt
4,392
5,201
Long-term operating lease liabilities
133
142
Long-term derivative liabilities
378
632
Pension and other postretirement
liabilities
9
23
Other long-term liabilities
209
251
Total long-term liabilities
5,121
6,249
Commitments and contingencies
Equity:
Common stock, $0.01 par value;
2,500,000,000 shares authorized; issued 1,161,545,588 shares as of
December 31, 2022 and 1,158,672,666 shares as of December 31,
2021
12
12
Additional paid-in capital
7,172
7,150
Accumulated deficit
(2,539
)
(4,388
)
Accumulated other comprehensive income
(loss)
6
(25
)
Common stock in treasury, 61,614,693
shares as of December 31, 2022 and 44,353,224 shares as of December
31, 2021
(327
)
(202
)
Total equity
4,324
2,547
TOTAL LIABILITIES AND EQUITY
$
12,926
$
11,848
SOUTHWESTERN ENERGY COMPANY
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS
OF CASH FLOWS
(Unaudited)
For the years ended
December 31,
(in millions)
2022
2021
Cash Flows From Operating
Activities:
Net income (loss)
$
1,849
$
(25
)
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Depreciation, depletion and
amortization
1,174
546
Amortization of debt issuance costs
11
9
Impairments
—
6
(Gain) loss on derivatives, unsettled
(24
)
944
Stock-based compensation
4
2
Loss on early extinguishment of debt
14
93
Other
2
(3
)
Change in assets and liabilities, net of
effect of mergers:
Accounts receivable
(240
)
(425
)
Accounts payable
390
261
Taxes payable
43
(4
)
Interest payable
4
6
Inventories
2
(3
)
Other assets and liabilities
(75
)
(44
)
Net cash provided by operating
activities
3,154
1,363
Cash Flows From Investing
Activities:
Capital investments
(2,115
)
(1,032
)
Proceeds from sale of property and
equipment
72
4
Cash acquired in mergers
—
66
Cash paid in mergers
—
(1,642
)
Net cash used in investing activities
(2,043
)
(2,604
)
Cash Flows From Financing
Activities:
Payments on current portion of long-term
debt
(210
)
—
Payments on long-term debt
(612
)
(1,177
)
Payments on revolving credit facility
(12,071
)
(6,628
)
Borrowings under revolving credit
facility
11,861
6,388
Change in bank drafts outstanding
79
5
Repayment of revolving credit facilities
associated with mergers
—
(176
)
Proceeds from exercise of common stock
options
7
—
Proceeds from issuance of long-term
debt
—
2,900
Debt issuance and other financing
costs
(14
)
(53
)
Purchase of treasury stock
(125
)
—
Cash paid for tax withholding
(4
)
(3
)
Net cash provided by (used in) financing
activities
(1,089
)
1,256
Increase in cash and cash equivalents
22
15
Cash and cash equivalents at beginning of
year
28
13
Cash and cash equivalents at end of
year
$
50
$
28
Hedging Summary
A detailed breakdown of the Company’s derivative financial
instruments and financial basis positions as of February 21, 2023,
including 2023 derivative contracts that have settled, is shown
below. Please refer to our annual report on Form 10-K to be filed
with the Securities and Exchange Commission for complete
information on the Company’s commodity, basis and interest rate
protection.
Weighted Average Price per
MMBtu
Volume (Bcf)
Swaps
Sold Puts
Purchased Puts
Sold Calls
Natural gas
2023
Fixed price swaps
504
$
3.08
$
—
$
—
$
—
Two-way costless collars
219
—
—
3.03
3.55
Three-way costless collars
215
—
2.09
2.54
3.00
Total
938
2024
Fixed price swaps
517
$
3.54
$
—
$
—
$
—
Purchased puts
5
—
—
4.00
—
Two-way costless collars
44
—
—
3.07
3.53
Three-way costless collars
11
—
2.25
2.80
3.54
Total
577
Call Options – Natural Gas
(Net)
Volume
Weighted Average Strike
Price
(Bcf)
($/MMBtu)
2023
46
$
2.94
2024
9
$
3.00
Total
55
$
Natural gas financial basis
positions
Volume
Basis Differential
(Bcf)
($/MMBtu)
Q1 2023
Dominion South
33
$
(0.74
)
TCO
17
$
(0.61
)
TETCO M3
17
$
1.81
Trunkline Zone 1A
3
$
(0.29
)
Total
70
$
(0.08
)
Q2 2023
Dominion South
34
$
(0.75
)
TCO
20
$
(0.61
)
TETCO M3
15
$
(0.55
)
Trunkline Zone 1A
3
$
(0.29
)
Total
72
$
(0.65
)
Q3 2023
Dominion South
34
$
(0.75
)
TCO
20
$
(0.62
)
TETCO M3
15
$
(0.66
)
Trunkline Zone 1A
4
$
(0.29
)
Total
73
$
(0.68
)
Q4 2023
Dominion South
33
$
(0.75
)
TCO
19
$
(0.61
)
TETCO M3
15
$
(0.18
)
Trunkline Zone 1A
3
$
(0.29
)
Total
70
$
(0.57
)
2024
Dominion South
46
$
(0.71
)
2025
Dominion South
9
$
(0.64
)
Weighted Average Price per
Bbl
Volume (MBbls)
Swaps
Sold Puts
Purchased Puts
Sold Calls
Oil
2023
Fixed price swaps
1,252
$
61.89
$
—
$
—
$
—
Purchased puts
171
—
—
73.50
—
Three-way costless collars
1,268
—
33.97
45.51
56.12
Total
2,691
2024
Fixed price swaps
913
$
70.66
$
—
$
—
$
—
2025
Fixed price swaps
41
$
77.66
$
—
$
—
$
—
Ethane
2023
Fixed price swaps
5,999
$
11.56
$
—
$
—
$
—
2024
Fixed price swaps
1,305
$
10.81
$
—
$
—
$
—
Propane
2023
Fixed price swaps
4,345
$
36.15
$
—
$
—
$
—
2024
Fixed price swaps
1,094
$
35.70
$
—
$
—
$
—
Normal Butane
2023
Fixed price swaps
677
$
41.00
$
—
$
—
$
—
2024
Fixed price swaps
329
$
40.74
$
—
$
—
$
—
Natural Gasoline
2023
Fixed price swaps
634
$
65.31
$
—
$
—
$
—
2024
Fixed price swaps
329
$
64.37
$
—
$
—
$
—
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.
Another such non-GAAP financial measure is pre-tax PV-10.
Management believes that the presentation of PV-10 is relevant and
useful to our investors as supplemental disclosure to the
standardized measure of discounted future cash flows (“standardized
measure”), or after-tax PV-10 amount, because it presents the
discounted future net cash flows attributable to our proved
reserves prior to taking into account future corporate income taxes
and our current tax structure. While the standardized measure is
dependent on the unique tax situation of each company, PV-10 is
based on a pricing methodology and discount factors that are
consistent for all companies. Because of this, PV-10 can be used
within the industry and by creditors and securities analysts to
evaluate estimated net cash flows from proved reserves on a more
comparable basis. The difference between the standardized measure
and the PV-10 amount is the discounted amount of estimated future
income taxes.
Additional non-GAAP financial measures the Company may present
from time to time are free cash flow, net debt, adjusted net
income, adjusted diluted earnings per share and adjusted EBITDA,
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.
3 Months Ended December
31,
12 Months Ended December
31,
2022
2021
2022
2021
Adjusted net income:
(in millions)
Net income (loss)
$
2,901
$
2,361
$
1,849
$
(25
)
Add back (deduct):
Merger-related expenses
—
37
27
76
Restructuring charges
—
—
—
7
Impairments
—
—
—
6
(Gain) loss on unsettled derivatives
(1)
(2,548
)
(2,008
)
(24
)
944
Loss on early extinguishment of debt
8
34
14
93
Other (gain) loss
3
(6
)
4
(6
)
Adjustments due to discrete tax items
(2)
(660
)
(568
)
(386
)
2
Tax impact on adjustments
583
468
(5
)
(266
)
Adjusted net income
$
287
$
318
$
1,479
$
831
(1)
Includes ($7) million and ($4) million of
non-performance risk adjustment for the three months ended December
31, 2022 and 2021, respectively, and $1 million non-performance
risk adjustment for the twelve months ended December 31, 2021.
(2)
The Company’s 2022 income tax rate is
23.0% before the impacts of any valuation allowance.
3 Months Ended December
31,
12 Months Ended December
31,
2022
2021
2022
2021
Adjusted diluted earnings per
share:
Diluted earnings (loss) per share
$
2.63
$
2.31
$
1.66
$
(0.03
)
Add back (deduct):
Merger-related expenses
—
0.04
0.02
0.10
Restructuring charges
—
—
—
0.01
Impairments
—
—
—
0.01
(Gain) loss on unsettled derivatives
(1)
(2.31
)
(1.97
)
(0.02
)
1.19
Loss on early extinguishment of debt
0.01
0.03
0.01
0.12
Other (gain) loss
0.00
(0.01
)
0.01
(0.01
)
Adjustments due to discrete tax items
(2)
(0.60
)
(0.55
)
(0.34
)
0.00
Tax impact on adjustments
0.53
0.46
(0.01
)
(0.34
)
Adjusted diluted earnings per share
$
0.26
$
0.31
$
1.33
$
1.05
(1)
Includes ($7) million and ($4) million of
non-performance risk adjustment for the three months ended December
31, 2022 and 2021, respectively, and $1 million non-performance
risk adjustment for the twelve months ended December 31, 2021.
(2)
The Company’s 2022 income tax rate is
23.0% before the impacts of any valuation allowance.
3 Months Ended December
31,
12 Months Ended December
31,
2022
2021
2022
2021
Net cash flow:
(in millions)
Net cash provided by operating
activities
$
958
$
533
$
3,154
$
1,363
Add back (deduct):
Changes in operating assets and
liabilities
(281
)
63
(124
)
209
Merger-related expenses
—
37
27
76
Restructuring charges
—
—
—
7
Net cash flow
$
677
$
633
$
3,057
$
1,655
3 Months Ended December
31,
12 Months Ended December
31,
2022
2021
2022
2021
Free cash flow:
(in millions)
Net cash flow
$
677
$
633
$
3,057
$
1,655
Subtract:
Total capital investments
(537
)
(292
)
(2,209
)
(1,108
)
Free cash flow
$
140
$
341
$
848
$
547
3 Months Ended December
31,
12 Months Ended December
31,
2022
2021
2022
2021
Adjusted EBITDA:
(in millions)
Net income (loss)
$
2,901
$
2,361
$
1,849
$
(25
)
Add back (deduct):
Interest expense
45
41
184
136
Provision for income taxes
10
—
51
—
Depreciation, depletion and
amortization
313
212
1,174
546
Merger-related expenses
—
37
27
76
Restructuring charges
—
—
—
7
Impairments
—
—
—
6
(Gain) loss on unsettled derivatives
(1)
(2,548
)
(2,008
)
(24
)
944
Loss on early extinguishment of debt
8
34
14
93
Other (gain) loss
3
(6
)
4
(6
)
Stock-based compensation expense
—
—
4
2
Adjusted EBITDA
$
732
$
671
$
3,283
$
1,779
(1)
Includes ($7) million and ($4) million of
non-performance risk adjustment for the three months ended December
31, 2022 and 2021, respectively, and $1 million non-performance
risk adjustment for the twelve months ended December 31, 2021.
December 31, 2022
Net debt:
(in millions)
Total debt (1)
$
4,414
Subtract:
Cash and cash equivalents
(50
)
Net debt
$
4,364
(1)
Does not include $22 million of
unamortized debt premium/discount and issuance expense.
December 31, 2022
Net debt to adjusted EBITDA:
(in millions)
Net debt
$
4,364
Adjusted EBITDA
$
3,283
Net debt to adjusted EBITDA
1.3x
December 31, 2022
Pre-tax PV-10:
(in millions)
PV-10 (standardized measure)
$
37,588
Add back:
Present value of taxes
8,847
Pre-tax PV-10
$
46,435
View source
version on businesswire.com: https://www.businesswire.com/news/home/20230223005850/en/
Investor Contact Brittany Raiford Director, Investor
Relations (832) 796-7906 brittany_raiford@swn.com
Grafico Azioni Southwestern Energy (NYSE:SWN)
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Grafico Azioni Southwestern Energy (NYSE:SWN)
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