NEWS RELEASE
SOUTHWESTERN ENERGY ANNOUNCES FOURTH QUARTER AND FULL YEAR 2021 RESULTS; PROVIDES 2022 GUIDANCE
Record reserves value underscores resilient and growing free cash flow from responsible natural gas development
SPRING, Texas – February 24, 2022 – Southwestern Energy Company (NYSE: SWN) (the “Company” or “Southwestern”) today announced financial and operating results for the fourth quarter and full-year 2021 and provided first quarter and full-year 2022 guidance.
“In 2021, Southwestern Energy delivered results above expectations. We materially increased our scale and enhanced our free cash flow generation capability. Our new Haynesville assets complement our premium Appalachia position by deepening the Company’s inventory, expanding market optionality and reach, including globally through the LNG Corridor, while lowering the risk profile of the enterprise,” said Bill Way, Southwestern Energy President and Chief Executive Officer.
“We are also reporting Company-record reserves and value that reflect the quality and depth of our inventory. Notably, the reported PV-10 value of these reserves using SEC prices is more than double our current enterprise value, further emphasizing the compelling economic opportunity that SWN offers its shareholders. Our 2022 plan is designed to deliver that value,” continued Way.
2021 Highlights
•Generated $1.4 billion net cash provided by operating activities, $1.7 billion net cash flow (non-GAAP) and $547 million in free cash flow (non-GAAP);
•Delivered Company-record reserves of 21.1 Tcfe, PV-10 of $18.7 billion, and pre-tax PV-10 (non-GAAP) of $22.4 billion using SEC prices;
•Closed acquisitions of Indigo Natural Resources on September 1st and GEP Haynesville on December 31st; becomes largest Haynesville and second-largest natural gas-focused producer in United States;
•Strengthened financial position and lowered leverage ratio to 2.0 times, expanded liquidity, reduced cost of debt and extended weighted-average debt maturity profile; upgraded to BB+ by S&P in January 2022; and
•Announced and implementing Company-wide responsibly sourced gas certification and continuous monitoring.
2022 Guidance
The 2022 plan is designed to optimize free cash flow through the execution of our strategy of disciplined investment at maintenance capital levels. Highlights are presented below; full guidance is available in the attachments to this press release and on the Company’s website.
•Capital investment of $1.9 to $2.0 billion inclusive of $215 to $230 million in capitalized interest and expense; anticipate $15 to 20 million of investment in ESG initiatives, prioritizing emissions reduction and fresh water neutral efforts
•Maintaining production of approximately 4.7 Bcfe per day, including approximately 4.1 Bcf per day of natural gas and 90 MBbls per day of liquids
–Increase of approximately 1.7 Bcfe per day from year-end 2020, further demonstrating step change in scale through disciplined strategic acquisitions
•Expect to utilize free cash flow to pay down debt towards target range of $3.5 billion to $3.0 billion; expect to achieve target leverage range of 1.5 times to 1.0 times based on strip prices
•Estimate 130 to 140 gross operated wells to sales including 70 to 75 in the Haynesville with an average lateral length of over 8,000 feet and 60 to 65 in Appalachia with an average lateral length of over 14,000 feet
•Mitigating basis risk for 92% of expected natural gas production
–Haynesville protected through geographic location, firm sales and transportation to Gulf Coast and LNG corridor
–84% of Appalachia natural gas basis protected from in-basin basis exposure through transportation portfolio, firm sales agreements and financial basis hedges
2021 Fourth Quarter and Full Year Results
| FINANCIAL STATISTICS | For the three months ended | For the years ended | |||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||
| Net Income (loss) | $ | 2,361 | $ | (92) | $ | (25) | $ | (3,112) | |||||||||||||||
| Adjusted net income (non-GAAP) | $ | 318 | $ | 119 | $ | 831 | $ | 221 | |||||||||||||||
| Diluted earnings (loss) per share | $ | 2.31 | $ | (0.14) | $ | (0.03) | $ | (5.42) | |||||||||||||||
| Adjusted diluted earnings per share (non-GAAP) | $ | 0.31 | $ | 0.18 | $ | 1.05 | $ | 0.38 | |||||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 671 | $ | 276 | $ | 1,779 | $ | 742 | |||||||||||||||
| Net cash provided by operating activities | $ | 533 | $ | 121 | $ | 1,363 | $ | 528 | |||||||||||||||
| Net cash flow (non-GAAP) | $ | 633 | $ | 249 | $ | 1,655 | $ | 662 | |||||||||||||||
Total capital investments (1) | $ | 292 | $ | 194 | $ | 1,108 | $ | 899 | |||||||||||||||
(1)Capital investments on the cash flow statement include an increase of $7 million and a decrease of $5 million for the three months ended December 31, 2021 and 2020, respectively, and an increase of $70 million and a decrease of $3 million for the years ended December 31, 2021 and 2020, respectively, relating to the change in accrued expenditures between periods.
Fourth Quarter 2021 Financial Results
For the quarter ended December 31, 2021, Southwestern Energy recorded net income of $2.4 billion, or $2.31 per diluted share, including a positive $2.0 billion non-cash change in unsettled mark to market derivatives. This compares to a net loss of $92 million, or ($0.14) per diluted share in the fourth quarter of 2020.
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Adjusted net income (non-GAAP), which excludes non-cash items noted above and other one-time charges, was $318 million or $0.31 per diluted share in 2021 and $119 million or $0.18 per share for the same period in 2020. The increase was primarily related to increased production volumes and increased commodity prices. For the fourth quarter of 2021, adjusted EBITDA (non-GAAP) was $671 million, net cash provided by operating activities was $533 million and net cash flow (non-GAAP) was $633 million, and free cash flow (non-GAAP) was $341 million.
As indicated in the table below, fourth quarter 2021 weighted average realized price, including $0.28 per Mcfe of transportation expenses, was $5.36 per Mcfe, excluding the impact of derivatives. Including derivatives, the weighted average realized price for the quarter was up 31% to $2.81 per Mcfe, as compared to prior year, primarily due to higher commodity prices, including a 119% increase in NYMEX and an 81% increase in WTI, partially offset by the impact of settled derivatives. Fourth quarter 2021 weighted average realized price before transportation expense and excluding derivatives was $5.64 per Mcfe.
Full Year 2021 Financial Results
The Company recorded a net loss of $25 million, or ($0.03) per share, for the year ended December 31, 2021 compared to a net loss of $3.1 billion, or ($5.42) per share in 2020. In 2021, the Company recorded a $944 million non-cash loss on unsettled derivatives. Excluding these non-cash and other one-time items, adjusted net income (non-GAAP) for 2021 was $831 million, or $1.05 per share, compared to $221 million, or $0.38 per share, in 2020. The increase in adjusted net income (non-GAAP) compared to prior year was primarily the result of increased commodity prices and increased production volumes associated with the Company’s acquisitions. In 2021, Adjusted EBITDA (non-GAAP) was $1.8 billion, net cash provided by operating activities was $1.4 billion, net cash flow (non-GAAP) was $1.7 billion, and free cash flow (non-GAAP) was $547 million.
As indicated in the table below, for the full year 2021, weighted average realized price, including $0.34 per Mcfe of transportation expense, was $3.74 per Mcfe excluding the impact of derivatives. Including derivatives, weighted average realized price was up 30% from $1.94 per Mcfe in 2020 to $2.53 per Mcfe in 2021. The increase was primarily related to higher commodity prices, including an 85% increase in NYMEX Henry Hub and a 72% increase in WTI, partially offset by the impact of derivatives. In 2021, the weighted average realized price before transportation expenses and excluding the impact of derivatives was $4.08 per Mcfe.
As of December 31, 2021, Southwestern Energy had total debt of $5.4 billion and net debt to adjusted EBITDA (non-GAAP) of 2.0x. At the end of 2021, the Company had access to $1.4 billion of liquidity, with $460 million of borrowings under its revolving credit facility and $160 million in outstanding letters of credit. During the fourth quarter of 2021, the Company further extended its maturity profile and improved its weighted average cost of debt when securing financing for the consideration of its GEP Haynesville acquisition
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by issuing $1.15 billion of 4.75% senior notes due 2032 and a $550 million institutional term loan subject to variable rate interest at 3.0% at year-end.
In January 2022, the Company received an upgrade to its long-term debt issuer rating from S&P to BB+, placing the Company one notch below investment grade credit rating. The Company also retired during January the remaining $201 million of senior notes due March 2022.
| Realized Prices | For the three months ended | For the years ended | ||||||||||||||||||||||||
| (includes transportation costs) | December 31, | December 31, | ||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||
| Natural Gas Price: | ||||||||||||||||||||||||||
NYMEX Henry Hub price ($/MMBtu) (1) | $ | 5.83 | $ | 2.66 | $ | 3.84 | $ | 2.08 | ||||||||||||||||||
Discount to NYMEX (2) | (0.73) | (0.99) | (0.53) | (0.74) | ||||||||||||||||||||||
| Realized gas price per Mcf, excluding derivatives | $ | 5.10 | $ | 1.67 | $ | 3.31 | $ | 1.34 | ||||||||||||||||||
Gain on settled financial basis derivatives ($/Mcf) | 0.05 | 0.23 | 0.09 | 0.11 | ||||||||||||||||||||||
Gain (loss) on settled commodity derivatives ($/Mcf) | (2.55) | (0.09) | (1.12) | 0.25 | ||||||||||||||||||||||
Realized gas price per Mcf, including derivatives ($/Mcf) | $ | 2.60 | $ | 1.81 | $ | 2.28 | $ | 1.70 | ||||||||||||||||||
| Oil Price: | ||||||||||||||||||||||||||
WTI oil price ($/Bbl) (3) | $ | 77.19 | $ | 42.66 | $ | 67.92 | $ | 39.40 | ||||||||||||||||||
| Discount to WTI | (8.27) | (10.69) | (9.12) | (10.20) | ||||||||||||||||||||||
Realized oil price, excluding derivatives ($/Bbl) | $ | 68.92 | $ | 31.97 | $ | 58.80 | $ | 29.20 | ||||||||||||||||||
Realized oil price, including derivatives ($/Bbl) | $ | 42.03 | $ | 52.27 | $ | 40.48 | $ | 46.91 | ||||||||||||||||||
| NGL Price, per Bbl: | ||||||||||||||||||||||||||
Realized NGL price, excluding derivatives ($/Bbl) | $ | 36.79 | $ | 15.28 | $ | 28.72 | $ | 10.24 | ||||||||||||||||||
Realized NGL price, including derivatives ($/Bbl) | $ | 21.44 | $ | 14.65 | $ | 18.20 | $ | 11.15 | ||||||||||||||||||
| Percentage of WTI, excluding derivatives | 48 | % | 36 | % | 42 | % | 26 | % | ||||||||||||||||||
| Total Weighted Average Realized Price: | ||||||||||||||||||||||||||
Excluding derivatives ($/Mcfe) | $ | 5.36 | $ | 1.93 | $ | 3.74 | $ | 1.53 | ||||||||||||||||||
Including derivatives ($/Mcfe) | $ | 2.81 | $ | 2.14 | $ | 2.53 | $ | 1.94 | ||||||||||||||||||
(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.
(3)Based on the average daily settlement price of the nearby month futures contract over the period.
Operational Results
Total production for the quarter ended December 31, 2021 was 385 Bcfe, comprised of 86% natural gas, 12% NGLs and 2% oil. Production totaled 1.24 Tcfe for the year ended December 31, 2021.
Capital investments in the fourth quarter of 2021 were $292 million, bringing full year capital investment to $1,108 million. The Company brought 93 wells to sales, drilled 87 wells and completed 93 wells during the year.
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| For the three months ended | For the years ended | ||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Production | |||||||||||||||||||||||
Gas production (Bcf) | 331 | 207 | 1,015 | 694 | |||||||||||||||||||
Oil production (MBbls) | 1,388 | 1,365 | 6,610 | 5,141 | |||||||||||||||||||
NGL production (MBbls) | 7,685 | 7,001 | 30,940 | 25,927 | |||||||||||||||||||
Total production (Bcfe) | 385 | 257 | 1,240 | 880 | |||||||||||||||||||
Total production (Bcfe/day) | 4.2 | 2.8 | 3.4 | 2.4 | |||||||||||||||||||
| Average unit costs per Mcfe | |||||||||||||||||||||||
Lease operating expenses (1) | $ | 0.96 | $ | 0.92 | $ | 0.95 | $ | 0.93 | |||||||||||||||
General & administrative expenses (2)(3) | $ | 0.08 | $ | 0.11 | $ | 0.10 | $ | 0.12 | |||||||||||||||
| Taxes, other than income taxes | $ | 0.12 | $ | 0.06 | $ | 0.11 | $ | 0.06 | |||||||||||||||
| Full cost pool amortization | $ | 0.53 | $ | 0.33 | $ | 0.42 | $ | 0.38 | |||||||||||||||
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)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.
(3)Excludes $38 million and $41 million in merger-related expenses for the three months and year ended December 31, 2020, respectively. Excludes $4 million and $16 million in restructuring charges for the three months and year ended December 31, 2020, respectively.
Appalachia – In the fourth quarter, total production was 283 Bcfe, with NGL production of 84 MBbls per day and oil production of 15 MBbls per day. The Company drilled 13 wells, completed 11 wells and placed 11 wells to sales with an average lateral length of 17,129 feet. During the fourth quarter, Appalachia well costs averaged $650 per lateral foot for wells placed to sales, including approximately $518 per lateral foot in dry gas Marcellus.
In 2021, Appalachia’s total production was 1.1 Tcfe, including 103 MBbls per day of liquids. During 2021, the Company drilled 74 wells, completed 78 wells and placed 78 wells to sales, with an average lateral length of 14,332 feet. At year-end, the Company had 20 drilled but uncompleted wells in Appalachia.
Haynesville – In the fourth quarter, total production was 102 Bcf. There were 11 wells drilled, 11 wells completed and 10 wells placed to sales in the quarter with an average lateral length of 6,875 feet.
Production for the year was 132 Bcf in Haynesville. The Company drilled 13 wells, completed 15 wells and brought 15 wells to sales following the close of the Indigo acquisition, with 29 drilled but uncompleted wells at year-end, including those acquired from GEP Haynesville.
The Haynesville results in 2021 include activity from the properties acquired from Indigo Natural Resources starting on September 1, 2021. The Company closed its acquisition of GEP Haynesville on December 31, 2021, and, as such, there was no impact to reported 2021 production or capital investments.
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| E&P Division Results | For the three months ended December 31, 2021 | For the year ended December 31, 2021 | |||||||||||||||||||||
| Appalachia | Haynesville | Appalachia | Haynesville | ||||||||||||||||||||
Gas production (Bcf) | 229 | 102 | 883 | 132 | |||||||||||||||||||
| Liquids production | |||||||||||||||||||||||
Oil (MBbls) | 1,361 | 6 | 6,567 | 8 | |||||||||||||||||||
NGL (MBbls) | 7,683 | — | 30,936 | — | |||||||||||||||||||
Production (Bcfe) | 283 | 102 | 1,108 | 132 | |||||||||||||||||||
Capital investments ($ in millions) | |||||||||||||||||||||||
| Drilling and completions, including workovers | $ | 104 | $ | 126 | $ | 694 | $ | 178 | |||||||||||||||
| Land acquisition and other | 6 | — | 48 | 1 | |||||||||||||||||||
| Capitalized interest and expense | 31 | 15 | 140 | 21 | |||||||||||||||||||
| Total capital investments | $ | 141 | $ | 141 | $ | 882 | $ | 200 | |||||||||||||||
Gross operated well activity summary (1) | |||||||||||||||||||||||
| Drilled | 13 | 11 | 74 | 13 | |||||||||||||||||||
| Completed | 11 | 11 | 78 | 15 | |||||||||||||||||||
| Wells to sales | 11 | 10 | 78 | 15 | |||||||||||||||||||
| Total weighted average realized price per Mcfe, excluding derivatives | $ | 5.34 | $ | 5.43 | $ | 3.57 | $ | 5.18 | |||||||||||||||
(1)For Haynesville, represents wells drilled, completed and placed to sales by Southwestern Energy after the close of the Indigo Natural Resources acquisition on September 1, 2021.
| Wells to sales summary | For the three months ended December 31, 2021 | |||||||||||||
| Gross wells to sales | Average lateral length | |||||||||||||
| Appalachia | ||||||||||||||
| Super Rich Marcellus | 5 | 16,867 | ||||||||||||
| Dry Gas Utica | 3 | 14,063 | ||||||||||||
| Dry Gas Marcellus | 3 | 20,631 | ||||||||||||
Haynesville (1) | 10 | 6,875 | ||||||||||||
| Total | 21 | |||||||||||||
(1)Includes wells drilled and completed by Indigo.
2021 Proved Reserves
The Company increased its total proved reserves to 21.1 Tcfe at year-end 2021, up 76% from 12.0 Tcfe at year-end 2020. The increase was primarily related to reserves acquired from Indigo Natural Resources and GEP Haynesville, reserve additions in Appalachia, as well as an increase in commodity prices.
The after-tax PV-10 (standardized measure) of the Company’s reserves was $18.7 billion. The PV-10 value before the impact of taxes (non-GAAP) was $22.4 billion, including $15.5 billion from Appalachia and $6.9 billion from Haynesville. SEC prices used for the Company’s reported 2021 reserves were $3.60 per Mcf NYMEX Henry Hub, $66.56 per Bbl WTI, and $28.65 per Bbl NGLs.
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| Proved Reserves Summary | For the years ended December 31, | ||||||||||
| 2021 | 2020 | ||||||||||
Proved reserves (in Bcfe) | 21,148 | 11,990 | |||||||||
PV-10: (in millions) | |||||||||||
| Pre-tax | $ | 22,420 | $ | 1,847 | |||||||
| PV of taxes | (3,689) | — | |||||||||
After-tax (in millions) | $ | 18,731 | $ | 1,847 | |||||||
| Percent of estimated proved reserves that are: | |||||||||||
| Natural gas | 82 | % | 76 | % | |||||||
| NGLs and oil | 18 | % | 24 | % | |||||||
| Proved developed | 54 | % | 68 | % | |||||||
| 2021 Proved Reserves by Commodity | Natural Gas | Oil | NGL | Total | |||||||||||||||||||
| (Bcf) | (MBbls) | (MBbls) | (Bcfe) | ||||||||||||||||||||
| Proved reserves, beginning of year | 9,181 | 58,024 | 410,151 | 11,990 | |||||||||||||||||||
| Revisions of previous estimates due to price | 501 | 1,414 | (15,525) | 415 | |||||||||||||||||||
| Revisions of previous estimates other than price | 248 | 1,900 | 1,500 | 269 | |||||||||||||||||||
| Extensions, discoveries and other additions | 2,543 | 24,865 | 211,598 | 3,962 | |||||||||||||||||||
| Production | (1,015) | (6,610) | (30,940) | (1,240) | |||||||||||||||||||
Acquisition of reserves in place (1) | 5,750 | 247 | 180 | 5,753 | |||||||||||||||||||
| Disposition of reserves in place | (1) | (61) | — | (1) | |||||||||||||||||||
| Proved reserves, end of year | 17,207 | 79,779 | 576,964 | 21,148 | |||||||||||||||||||
| Proved developed reserves: | |||||||||||||||||||||||
| Beginning of year | 6,342 | 33,563 | 276,548 | 8,203 | |||||||||||||||||||
| End of year | 9,308 | 40,930 | 296,832 | 11,335 | |||||||||||||||||||
(1)Reflects the acquisition of our Haynesville properties.
2021 Proved Reserves by Division (Bcfe) | Appalachia | Haynesville | Other (1) | Total | |||||||||||||||||||
| Proved reserves, beginning of year | 11,989 | — | 1 | 11,990 | |||||||||||||||||||
| Price revisions | 415 | — | — | 415 | |||||||||||||||||||
| Performance and production revisions | 270 | — | (1) | 269 | |||||||||||||||||||
| Extensions, discoveries and other additions | 3,962 | — | — | 3,962 | |||||||||||||||||||
| Production | (1,108) | (132) | — | (1,240) | |||||||||||||||||||
Acquisition of reserves in place (2) | — | 5,753 | — | 5,753 | |||||||||||||||||||
| Disposition of reserves in place | (1) | — | — | (1) | |||||||||||||||||||
| Proved reserves, end of year | 15,527 | 5,621 | — | 21,148 | |||||||||||||||||||
(1)Other includes properties outside of Appalachia and Haynesville.
(2)Reflects the acquisition of our Haynesville properties.
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The Company reported 2021 proved developed finding and development (“PD F&D”) costs of $0.42 per Mcfe for its Appalachia properties when excluding the impact of capitalized interest and portions of capitalized G&A costs in accordance with the full cost method of accounting.
Proved Developed Finding and Development (1) | Three-Year | ||||||||||||||||||||||
| 12 Months Ended December 31, | Total | ||||||||||||||||||||||
Total PD Adds (Bcfe): | 2021 | 2020 | 2019 | 2021 | |||||||||||||||||||
New PD adds | 451 | 267 | 191 | 909 | |||||||||||||||||||
PUD conversions | 1,298 | (3) | 1,631 | 1,441 | 4,370 | ||||||||||||||||||
Total PD Adds | 1,749 | 1,898 | 1,632 | 5,279 | |||||||||||||||||||
Costs Incurred (in millions): | |||||||||||||||||||||||
| Unproved property acquisition costs | $ | 123 | $ | 124 | $ | 162 | $ | 409 | |||||||||||||||
| Exploration costs | — | — | 2 | 2 | |||||||||||||||||||
| Development costs | 799 | 812 | 936 | 2,547 | |||||||||||||||||||
Capitalized Costs Incurred | $ | 922 | $ | 936 | $ | 1,100 | $ | 2,958 | |||||||||||||||
Subtract (in millions): | |||||||||||||||||||||||
| Proved property acquisition costs | $ | — | $ | — | $ | — | $ | — | |||||||||||||||
| Unproved property acquisition costs | (123) | (124) | (162) | (409) | |||||||||||||||||||
Capitalized interest and expense associated with development and exploration (2) | (56) | (60) | (81) | (197) | |||||||||||||||||||
PD Costs Incurred | $ | 743 | $ | 752 | $ | 857 | $ | 2,352 | |||||||||||||||
| PD F&D (PD Cost Incurred / Total PD Adds) | $ | 0.42 | $ | 0.40 | $ | 0.53 | $ | 0.45 | |||||||||||||||
Note: Amounts may not add due to rounding
(1)Includes Appalachia only.
(2)Adjusting for the impacts of the full cost accounting method for comparability.
(3)Includes increased reserve estimates of 145 Bcfe in the Appalachian Basin associated with productivity enhancements for newly developed PUD locations and compression.
Conference Call
Southwestern Energy will host a conference call and webcast on Friday, February 25, 2022 at 9:30 a.m. Central to discuss fourth quarter and fiscal year 2021 results. To participate, dial US toll-free 877-883-0383, or international 412-902-6506 and enter access code 2596339. The conference call will webcast live at www.swn.com.
To listen to a replay of the call, dial 877-344-7529, International 412-317-0088, or Canada Toll Free 855-669-9658. Enter replay access code 3985981. The replay will be available until March 4, 2022.
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.swn.com/responsibility.
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Investor Contact
Brittany Raiford
Director, Investor Relations
(832) 796-7906
brittany_raiford@swn.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, estimated reserves and inventory duration, projected production and sales volume and growth rates, commodity prices, projected average well costs, generation of free cash flow, 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, lack of availability of drilling and production equipment and services, 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, cash flow and access to capital, the timing of development expenditures, a change in our credit rating, an increase in interest rates and any adverse impacts from the discontinuation of the London Interbank Offered Rate, 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
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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, 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, our ability to realize the expected benefits from acquisitions, including our mergers with GEP Haynesville, LLC, Montage Resources Corporation and Indigo Natural Resources LLC, and any other factors discussed 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, 2021.
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.
###
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2022 Guidance
| 1st Quarter | Total Year | ||||||||||
| PRODUCTION | |||||||||||
Gas production (Bcf) | 365 – 377 | 1,487 – 1,517 | |||||||||
Liquids (% of production) | 11.0% – 11.5% | 11.5% – 12.0% | |||||||||
Total (Bcfe) | 411 – 426 | 1,683 – 1,723 | |||||||||
Total (Bcfe/day) | ~4.6 | ~4.7 | |||||||||
CAPITAL BY DIVISION (in millions) | |||||||||||
| Appalachia | ~45% | ||||||||||
| Haynesville | ~55% | ||||||||||
| Total D&C capital (includes land) | $1,665 – $1,740 | ||||||||||
| Other | $20 – $30 | ||||||||||
| Capitalized interest and expense | $215 – $230 | ||||||||||
| Total Capital Investments | $1,900 – $2,000 | ||||||||||
| PRICING | |||||||||||
Natural gas discount to NYMEX including transportation (1) | $0.40 – $0.50 per Mcf | $0.55 – $0.70 per Mcf | |||||||||
| Oil discount to West Texas Intermediate (WTI) including transportation | $8.00 – $10.00 per Bbl | $8.00 – $10.00 per Bbl | |||||||||
Natural gas liquids realization as a % of WTI including transportation (2) | 38% – 43% | 32% – 40% | |||||||||
| EXPENSES | |||||||||||
| Lease operating expenses | $0.92 – $0.96 per Mcfe | ||||||||||
| General & administrative expense | $0.08 – $0.12 per Mcfe | ||||||||||
| Taxes, other than income taxes | $0.11 – $0.15 per Mcfe | ||||||||||
| Income tax rate (~100% deferred) | 24.1 | % | |||||||||
| GROSS OPERATED WELL COUNT | Drilled | Completed | Wells To Sales | Ending DUC Inventory | |||||||||||||||||||
| Appalachia | 70 – 75 | 70 – 75 | 60 – 65 | 25 – 30 | |||||||||||||||||||
| Haynesville | 60 – 65 | 65 – 70 | 70 – 75 | 18 – 23 | |||||||||||||||||||
| Total Well Count | 130 – 140 | 135 – 145 | 130 – 140 | 43 – 53 | |||||||||||||||||||
(1)Annual guidance based on $4.15 per Mcf NYMEX Henry Hub. Includes impact of transportation costs and expected $0.05 – $0.08 per Mcf gain from financial basis hedges for the full year of 2022. Do not expect a material impact from basis hedges in the first quarter of 2022.
(2)Annual guidance based on $75 per Bbl WTI.
11
| 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) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| Operating Revenues: | ||||||||||||||||||||||||||
| Gas sales | $ | 1,704 | $ | 356 | $ | 3,412 | $ | 967 | ||||||||||||||||||
| Oil sales | 97 | 43 | 394 | 154 | ||||||||||||||||||||||
| NGL sales | 283 | 107 | 890 | 265 | ||||||||||||||||||||||
| Marketing | 861 | 272 | 1,963 | 917 | ||||||||||||||||||||||
| Other | 2 | 1 | 8 | 5 | ||||||||||||||||||||||
| 2,947 | 779 | 6,667 | 2,308 | |||||||||||||||||||||||
| Operating Costs and Expenses: | ||||||||||||||||||||||||||
| Marketing purchases | 848 | 271 | 1,957 | 946 | ||||||||||||||||||||||
| Operating expenses | 365 | 236 | 1,170 | 813 | ||||||||||||||||||||||
| General and administrative expenses | 34 | 32 | 138 | 121 | ||||||||||||||||||||||
| Merger-related expenses | 37 | 38 | 76 | 41 | ||||||||||||||||||||||
| Restructuring charges | — | 4 | 7 | 16 | ||||||||||||||||||||||
| Depreciation, depletion and amortization | 212 | 90 | 546 | 357 | ||||||||||||||||||||||
| Impairments | — | 335 | 6 | 2,830 | ||||||||||||||||||||||
| Taxes, other than income taxes | 46 | 17 | 132 | 55 | ||||||||||||||||||||||
| 1,542 | 1,023 | 4,032 | 5,179 | |||||||||||||||||||||||
| Operating Income (Loss) | 1,405 | (244) | 2,635 | (2,871) | ||||||||||||||||||||||
| Interest Expense: | ||||||||||||||||||||||||||
| Interest on debt | 66 | 48 | 220 | 171 | ||||||||||||||||||||||
| Other interest charges | 4 | 4 | 13 | 11 | ||||||||||||||||||||||
| Interest capitalized | (29) | (21) | (97) | (88) | ||||||||||||||||||||||
| 41 | 31 | 136 | 94 | |||||||||||||||||||||||
| Gain (Loss) on Derivatives | 1,025 | 186 | (2,436) | 224 | ||||||||||||||||||||||
| Gain (Loss) on Early Extinguishment of Debt | (34) | — | (93) | 35 | ||||||||||||||||||||||
| Other Income (Loss), Net | 6 | (2) | 5 | 1 | ||||||||||||||||||||||
| Income (Loss) Before Income Taxes | 2,361 | (91) | (25) | (2,705) | ||||||||||||||||||||||
| Provision (Benefit) for Income Taxes | ||||||||||||||||||||||||||
| Current | — | — | — | (2) | ||||||||||||||||||||||
| Deferred | — | 1 | — | 409 | ||||||||||||||||||||||
| — | 1 | — | 407 | |||||||||||||||||||||||
| Net Income (Loss) | $ | 2,361 | $ | (92) | $ | (25) | $ | (3,112) | ||||||||||||||||||
| Earnings (Loss) Per Common Share | ||||||||||||||||||||||||||
| Basic | $ | 2.32 | $ | (0.14) | $ | (0.03) | $ | (5.42) | ||||||||||||||||||
| Diluted | $ | 2.31 | $ | (0.14) | $ | (0.03) | $ | (5.42) | ||||||||||||||||||
| Weighted Average Common Shares Outstanding: | ||||||||||||||||||||||||||
| Basic | 1,015,779,264 | 641,576,267 | 789,657,776 | 573,889,502 | ||||||||||||||||||||||
| Diluted | 1,020,130,445 | 641,576,267 | 789,657,776 | 573,889,502 | ||||||||||||||||||||||
12
| SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES | ||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||
| (Unaudited) | ||||||||||||||
| For the years ended | ||||||||||||||
| December 31, | ||||||||||||||
| (in millions) | 2021 | 2020 | ||||||||||||
| Cash Flows From Operating Activities: | ||||||||||||||
| Net income (loss) | $ | (25) | $ | (3,112) | ||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||
| Depreciation, depletion and amortization | 546 | 357 | ||||||||||||
| Amortization of debt issuance costs | 9 | 9 | ||||||||||||
| Impairments | 6 | 2,830 | ||||||||||||
| Deferred income taxes | — | 409 | ||||||||||||
| Loss on derivatives, unsettled | 944 | 138 | ||||||||||||
| Stock-based compensation | 2 | 3 | ||||||||||||
| (Gain) loss on early extinguishment of debt | 93 | (35) | ||||||||||||
| Other | (3) | 6 | ||||||||||||
| Change in assets and liabilities: | ||||||||||||||
| Accounts receivable | (425) | 50 | ||||||||||||
| Accounts payable | 261 | (131) | ||||||||||||
| Taxes payable | (4) | (7) | ||||||||||||
| Interest payable | 6 | (11) | ||||||||||||
| Inventories | (3) | 2 | ||||||||||||
| Other assets and liabilities | (44) | 20 | ||||||||||||
| Net cash provided by operating activities | 1,363 | 528 | ||||||||||||
| Cash Flows From Investing Activities: | ||||||||||||||
| Capital investments | (1,032) | (896) | ||||||||||||
| Proceeds from sale of property and equipment | 4 | 12 | ||||||||||||
| Cash acquired in mergers | 66 | 3 | ||||||||||||
| Cash paid in mergers | (1,642) | — | ||||||||||||
| Net cash used in investing activities | (2,604) | (881) | ||||||||||||
| Cash Flows From Financing Activities: | ||||||||||||||
| Payments on long-term debt | (1,177) | (72) | ||||||||||||
| Payments on revolving credit facility | (6,628) | (1,671) | ||||||||||||
| Borrowings under revolving credit facility | 6,388 | 2,337 | ||||||||||||
| Change in bank drafts outstanding | 5 | 1 | ||||||||||||
| Repayment of revolving credit facilities associated with mergers | (176) | (200) | ||||||||||||
| Repayment of Montage senior notes | — | (522) | ||||||||||||
| Proceeds from issuance of long-term debt | 2,900 | 350 | ||||||||||||
| Debt issuance and other financing costs | (53) | (10) | ||||||||||||
| Proceeds from issuance of common stock, net | — | 152 | ||||||||||||
| Cash paid for tax withholding | (3) | (4) | ||||||||||||
| Net cash provided by financing activities | 1,256 | 361 | ||||||||||||
| Increase in cash and cash equivalents | 15 | 8 | ||||||||||||
| Cash and cash equivalents at beginning of year | 13 | 5 | ||||||||||||
| Cash and cash equivalents at end of year | $ | 28 | $ | 13 | ||||||||||
13
Hedging Summary
A detailed breakdown of the Company’s derivative financial instruments and financial basis positions as of February 22, 2022, including 2022 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 | Sold | Purchased | Sold | ||||||||||||||||||||||||||
| (Bcf) | Swaps | Puts | Puts | Calls | |||||||||||||||||||||||||
| Natural gas | |||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Fixed price swaps | 806 | $ | 3.08 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Two-way costless collars | 144 | — | — | 2.71 | 3.14 | ||||||||||||||||||||||||
| Three-way costless collars | 347 | — | 2.06 | 2.52 | 2.94 | ||||||||||||||||||||||||
| Total | 1,297 | ||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Fixed price swaps | 503 | $ | 3.04 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Two-way costless collars | 219 | — | — | 3.03 | 3.55 | ||||||||||||||||||||||||
| Three-way costless collars | 215 | — | 2.09 | 2.54 | 3.00 | ||||||||||||||||||||||||
| Total | 937 | ||||||||||||||||||||||||||||
| 2024 | |||||||||||||||||||||||||||||
| Fixed price swaps | 224 | $ | 2.96 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Two-way costless collars | 44 | — | — | 3.07 | 3.53 | ||||||||||||||||||||||||
| Three-way costless collars | 11 | — | 2.25 | 2.80 | 3.54 | ||||||||||||||||||||||||
| Total | 279 | ||||||||||||||||||||||||||||
| Volume | Weighted Average Strike Price | |||||||||||||
| (Bcf) | ($/MMBtu) | |||||||||||||
| Call Options – Natural Gas (Net) | ||||||||||||||
| 2022 | 84 | $ | 3.01 | |||||||||||
| 2023 | 46 | $ | 2.94 | |||||||||||
| 2024 | 9 | $ | 3.00 | |||||||||||
| Total | 139 | |||||||||||||
14
| Natural gas financial basis positions | Volume | Basis Differential | ||||||||||||
| (Bcf) | ($/MMBtu) | |||||||||||||
| Q1 2022 | ||||||||||||||
| Dominion South | 25 | $ | (0.59) | |||||||||||
| TCO | 18 | $ | (0.49) | |||||||||||
| TETCO M3 | 23 | $ | 1.27 | |||||||||||
| Columbia Gulf Mainline | 6 | $ | (0.24) | |||||||||||
| Total | 72 | $ | 0.04 | |||||||||||
| Q2 2022 | ||||||||||||||
| Dominion South | 39 | $ | (0.65) | |||||||||||
| TCO | 26 | $ | (0.55) | |||||||||||
| TETCO M3 | 24 | $ | (0.48) | |||||||||||
| Columbia Gulf Mainline | 7 | $ | (0.24) | |||||||||||
| Total | 96 | $ | (0.55) | |||||||||||
| Q3 2022 | ||||||||||||||
| Dominion South | 40 | $ | (0.65) | |||||||||||
| TCO | 26 | $ | (0.56) | |||||||||||
| TETCO M3 | 24 | $ | (0.49) | |||||||||||
| Columbia Gulf Mainline | 7 | $ | (0.24) | |||||||||||
| Total | 97 | $ | (0.56) | |||||||||||
| Q4 2022 | ||||||||||||||
| Dominion South | 30 | $ | (0.65) | |||||||||||
| TCO | 25 | $ | (0.56) | |||||||||||
| TETCO M3 | 19 | $ | (0.14) | |||||||||||
| Columbia Gulf Mainline | 6 | $ | (0.24) | |||||||||||
| Total | 80 | $ | (0.47) | |||||||||||
| 2023 | ||||||||||||||
| Dominion South | 124 | $ | (0.72) | |||||||||||
| TCO | 55 | $ | (0.54) | |||||||||||
| TETCO M3 | 62 | $ | 0.15 | |||||||||||
| Total | 241 | $ | (0.45) | |||||||||||
15
| Weighted Average Price per Bbl | |||||||||||||||||||||||||||||
| Volume | Sold | Purchased | Sold | ||||||||||||||||||||||||||
| (MBbls) | Swaps | Puts | Puts | Calls | |||||||||||||||||||||||||
| Oil | |||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Fixed price swaps | 3,203 | $ | 53.54 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Three-way costless collars | 1,380 | — | 39.89 | 50.23 | 57.05 | ||||||||||||||||||||||||
| Total | 4,583 | ||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Fixed price swaps | 846 | $ | 55.98 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Three-way costless collars | 1,268 | — | 33.97 | 45.51 | 56.12 | ||||||||||||||||||||||||
| Total | 2,114 | ||||||||||||||||||||||||||||
| 2024 | |||||||||||||||||||||||||||||
| Fixed price swaps | 603 | $ | 68.68 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Ethane | |||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Fixed price swaps | 5,797 | $ | 11.37 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Two-way costless collars | 135 | — | — | 7.56 | 9.66 | ||||||||||||||||||||||||
| Total | 5,932 | ||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Fixed price swaps | 998 | $ | 11.61 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Propane | |||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Fixed price swaps | 6,369 | $ | 31.14 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Three-way costless collars | 305 | — | 16.80 | 21.00 | 31.92 | ||||||||||||||||||||||||
| Total | 6,674 | ||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Fixed price swaps | 883 | $ | 35.95 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Normal Butane | |||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Fixed price swaps | 1,806 | $ | 35.64 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Fixed price swaps | 329 | $ | 40.64 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| Natural Gasoline | |||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Fixed price swaps | 1,840 | $ | 52.85 | $ | — | $ | — | $ | — | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Fixed price swaps | 314 | $ | 63.01 | $ | — | $ | — | $ | — | ||||||||||||||||||||
16
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 free cash flow, which is defined as cash provided by operating activities, adjusting for changes in operating assets and liabilities, merger-related expenses and restructuring charges, less total capital investments. Management presents this measure because it is accepted as an indicator of excess cash flow available to a company for the repayment of debt or for other general corporate purposes.
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 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.
17
| 3 Months Ended December 31, | 12 Months Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Adjusted net income: | |||||||||||||||||||||||
| Net income (loss) | $ | 2,361 | $ | (92) | $ | (25) | $ | (3,112) | |||||||||||||||
| Add back (deduct): | |||||||||||||||||||||||
| Merger-related expenses | 37 | 38 | 76 | 41 | |||||||||||||||||||
| Restructuring charges | — | 4 | 7 | 16 | |||||||||||||||||||
| Impairments | — | 335 | 6 | 2,830 | |||||||||||||||||||
(Gain) loss on unsettled derivatives (1) | (2,008) | (134) | 944 | 138 | |||||||||||||||||||
| (Gain) loss on early extinguishment of debt | 34 | — | 93 | (35) | |||||||||||||||||||
| Legal settlement charges | — | — | — | 1 | |||||||||||||||||||
| Other (gain) loss | (6) | 2 | (6) | 2 | |||||||||||||||||||
Adjustments due to discrete tax items (2) | (568) | 22 | 2 | 1,042 | |||||||||||||||||||
| Tax impact on adjustments | 468 | (56) | (266) | (702) | |||||||||||||||||||
| Adjusted net income | $ | 318 | $ | 119 | $ | 831 | $ | 221 | |||||||||||||||
(1)Includes $1 million of non-performance risk adjustment for the three and twelve months ended December 31, 2021 and 2020.
(2)2020 primarily relates to the recognition of a valuation allowance. The Company’s 2021 income tax rate is 24.1% before the impacts of any valuation allowance.
| 3 Months Ended December 31, | 12 Months Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Adjusted diluted earnings per share: | |||||||||||||||||||||||
| Diluted earnings (loss) per share | $ | 2.31 | $ | (0.14) | $ | (0.03) | $ | (5.42) | |||||||||||||||
| Add back (deduct): | |||||||||||||||||||||||
| Merger-related expenses | 0.04 | 0.06 | 0.10 | 0.07 | |||||||||||||||||||
| Restructuring charges | — | 0.01 | 0.01 | 0.03 | |||||||||||||||||||
| Impairments | — | 0.52 | 0.01 | 4.91 | |||||||||||||||||||
(Gain) loss on unsettled derivatives (1) | (1.97) | (0.21) | 1.19 | 0.25 | |||||||||||||||||||
| (Gain) loss on early extinguishment of debt | 0.03 | — | 0.12 | (0.06) | |||||||||||||||||||
| Legal settlement charges | — | — | — | 0.00 | |||||||||||||||||||
| Other (gain) loss | (0.01) | 0.00 | (0.01) | 0.00 | |||||||||||||||||||
Adjustments due to discrete tax items (2) | (0.55) | 0.03 | 0.00 | 1.81 | |||||||||||||||||||
| Tax impact on adjustments | 0.46 | (0.09) | (0.34) | (1.21) | |||||||||||||||||||
| Adjusted diluted earnings per share | $ | 0.31 | $ | 0.18 | $ | 1.05 | $ | 0.38 | |||||||||||||||
(1)Includes $1 million of non-performance risk adjustment for the three and twelve months ended December 31, 2021 and 2020.
(2)2020 primarily relates to the recognition of a valuation allowance. The Company’s 2021 income tax rate is 24.1% before the impacts of any valuation allowance.
| 3 Months Ended December 31, | 12 Months Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Net cash flow: | (in millions) | ||||||||||||||||||||||
| Net cash provided by operating activities | $ | 533 | $ | 121 | $ | 1,363 | $ | 528 | |||||||||||||||
| Add back (deduct): | |||||||||||||||||||||||
| Changes in operating assets and liabilities | 63 | 86 | 209 | 77 | |||||||||||||||||||
| Merger-related expenses | 37 | 38 | 76 | 41 | |||||||||||||||||||
| Restructuring charges | — | 4 | 7 | 16 | |||||||||||||||||||
| Net cash flow | $ | 633 | $ | 249 | $ | 1,655 | $ | 662 | |||||||||||||||
18
| 3 Months Ended December 31, 2021 | 12 Months Ended December 31, 2021 | ||||||||||
| Free cash flow: | (in millions) | ||||||||||
| Net cash flow | $ | 633 | $ | 1,655 | |||||||
| Subtract: | |||||||||||
| Total capital investments | (292) | (1,108) | |||||||||
| Free cash flow | $ | 341 | $ | 547 | |||||||
| 3 Months Ended December 31, | 12 Months Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Adjusted EBITDA: | (in millions) | ||||||||||||||||||||||
| Net income (loss) | $ | 2,361 | $ | (92) | $ | (25) | $ | (3,112) | |||||||||||||||
| Add back (deduct): | |||||||||||||||||||||||
| Interest expense | 41 | 31 | 136 | 94 | |||||||||||||||||||
| Provision (benefit) for income taxes | — | 1 | — | 407 | |||||||||||||||||||
| Depreciation, depletion and amortization | 212 | 90 | 546 | 357 | |||||||||||||||||||
| Merger-related expenses | 37 | 38 | 76 | 41 | |||||||||||||||||||
| Restructuring charges | — | 4 | 7 | 16 | |||||||||||||||||||
| Impairments | — | 335 | 6 | 2,830 | |||||||||||||||||||
(Gain) loss on unsettled derivatives (1) | (2,008) | (134) | 944 | 138 | |||||||||||||||||||
| (Gain) loss on early extinguishment of debt | 34 | — | 93 | (35) | |||||||||||||||||||
| Legal settlement charges | — | — | — | 1 | |||||||||||||||||||
| Other (gain) loss | (6) | 2 | (6) | 2 | |||||||||||||||||||
| Stock based compensation expense | — | 1 | 2 | 3 | |||||||||||||||||||
| Adjusted EBITDA | $ | 671 | $ | 276 | $ | 1,779 | $ | 742 | |||||||||||||||
(1)Includes $1 million of non-performance risk adjustment for the three and twelve months ended December 31, 2021 and 2020.
| December 31, 2021 | ||||||||
| Net debt: | (in millions) | |||||||
Total debt (1) | $ | 5,440 | ||||||
| Subtract: | ||||||||
| Cash and cash equivalents | (28) | |||||||
| Net debt | $ | 5,412 | ||||||
(1)Does not include $33 million of unamortized debt premium/discount and issuance expense.
| December 31, 2021 | ||||||||
| Net debt to adjusted EBITDA: | (in millions) | |||||||
| Net debt | $ | 5,412 | ||||||
Adjusted EBITDA (1) | $ | 2,644 | ||||||
| Net debt to adjusted EBITDA | 2.0x | |||||||
(1)Adjusted EBITDA for the twelve months ended December 31, 2021 includes $369 million of adjusted EBITDA generated by Indigo Natural Resources prior to the September 2021 acquisition and $496 million of Adjusted EBITDA generated by GEP Haynesville prior to the December 2021 acquisition.
| December 31, 2021 | ||||||||
| Pre-tax PV-10: | (in millions) | |||||||
| PV-10 (standardized measure) | $ | 18,731 | ||||||
| Add back: | ||||||||
| Present value of taxes | 3,689 | |||||||
| Pre-tax PV-10 | $ | 22,420 | ||||||
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