SOUTHWESTERN ENERGY CO - Quarter Report: 2021 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☒ Quarterly Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the quarterly period ended June 30, 2021

☐ Transition Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the transition period from ________ to ________

Commission file number: 001-08246

Southwestern Energy Company

(Exact name of registrant as specified in its charter)

Delaware

71-0205415

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

10000 Energy Drive

Spring, Texas 77389

(Address of principal executive offices)(Zip Code)

(832) 796-1000

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, Par Value $0.01

SWN

New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:


Class						Outstanding as of July 27, 2021
Common Stock, Par Value $0.01						677,020,351

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2021


PART I – FINANCIAL INFORMATION			Page

Item 1.	Financial Statements		3
	Consolidated Statements of Operations		3
	Consolidated Statements of Comprehensive Income (Loss)		4
	Consolidated Balance Sheets		5
	Consolidated Statements of Cash Flows		6
	Consolidated Statements of Changes in Equity		7
	Notes to Consolidated Financial Statements		8
		Note 1. Basis of Presentation	8
		Note 2. Acquisition	8
		Note 3. Restructuring Charges	11
		Note 4. Revenue Recognition	11
		Note 5. Cash and Cash Equivalents	13
		Note 6. Natural Gas and Oil Properties	13
		Note 7. Earnings per Share	14
		Note 8. Derivatives and Risk Management	15
		Note 9. Reclassifications From Accumulated Other Comprehensive Income (Loss)	22
		Note 10. Fair Value Measurements	23
		Note 11. Debt	25
		Note 1 2 . Commitments and Contingencies	27
		Note 1 3 . Income Taxes	28
		Note 1 4 . Pension Plan and Other Postretirement Benefits	29
		Note 15. Long-Term Incentive Compensation	29
		Note 1 6 . Segment Information	33
		Note 1 7 . New Accounting Pronouncements	35
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	Results of Operations		37
	Liquidity and Capital Resources		45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		50
Item 4.	Controls and Procedures		51

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		51
Item 1A.	Risk Factors		51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		59
Item 3.	Defaults Upon Senior Securities		59
Item 4.	Mine Safety Disclosures		59
Item 5.	Other Information		59
Item 6.	Exhibits		59

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

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Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Quarterly Report on Form 10-Q (this “Quarterly Report”) identified by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “model,” “target” or similar words.

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•the timing and extent of changes in market conditions and prices for natural gas, oil and natural gas liquids (“NGLs”), including regional basis differentials and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 pandemic;

•our ability to fund our planned capital investments;

•a change in our credit rating, an increase in interest rates and any adverse impacts from the discontinuation of the London Interbank Offered Rate (“LIBOR”);

•the extent to which lower commodity prices impact our ability to service or refinance our existing debt;

•the impact of volatility in the financial markets or other global economic factors, including the impact of COVID-19;

•difficulties in appropriately allocating capital and resources among our strategic opportunities;

•the timing and extent of our success in discovering, developing, producing and estimating reserves;

•our ability to maintain leases that may expire if production is not established or profitably maintained;

•our ability to realize the expected benefits from acquisitions, including the Indigo Merger (discussed below);

•costs in connection with the Indigo Merger and the transactions contemplated thereby;

•the consummation of or failure to consummate the Indigo Merger and the timing thereof;

•integration of operations and results subsequent to the Indigo Merger;

•our ability to transport our production to the most favorable markets or at all;

•availability and costs of personnel and of products and services provided by third parties;

•the impact of government regulation, including changes in law, the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation or regulation relating to hydraulic fracturing, climate and over-the-counter derivatives;

•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; and

•any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

Should one or more of the risks or uncertainties described above or elsewhere in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to update publicly any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	For the three months ended June 30,				For the six months ended June 30,
(in millions, except share/per share amounts)	2021		2020		2021		2020
Operating Revenues:
Gas sales	$	433	$	164	$	897	$	412
Oil sales	106		19		187		71
NGL sales	179		40		352		90
Marketing	332		187		684		426
Other	—		—		2		3
	1,050		410		2,122		1,002
Operating Costs and Expenses:
Marketing purchases	333		201		689		449
Operating expenses	259		182		509		375
General and administrative expenses	34		32		72		58
Merger-related expenses	3		—		4		—
Restructuring charges	1		2		7		12

Depreciation, depletion and amortization	100		84		196		197
Impairments	—		655		—		2,134
Taxes, other than income taxes	27		10		51		23
	757		1,166		1,528		3,248
Operating Income (Loss)	293		(756)		594		(2,246)
Interest Expense:
Interest on debt	48		40		98		80
Other interest charges	3		3		6		5
Interest capitalized	(21)		(21)		(43)		(44)
	30		22		61		41

Gain (Loss) on Derivatives	(871)		(109)		(1,062)		230
Gain on Early Extinguishment of Debt	—		7		—		35
Other Income (Loss), Net	(1)		—		—		1

Loss Before Income Taxes	(609)		(880)		(529)		(2,021)
Provision (Benefit) for Income Taxes:
Current	—		—		—		(2)
Deferred	—		—		—		408
	—		—		—		406
Net Loss	$	(609)	$	(880)	$	(529)	$	(2,427)


Loss Per Common Share:
Basic	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)
Diluted	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)

Weighted Average Common Shares Outstanding:
Basic	676,722,999		541,079,192		676,057,534		540,693,841
Diluted	676,722,999		541,079,192		676,057,534		540,693,841

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Net loss	$	(609)	$	(880)	$	(529)	$	(2,427)

Change in value of pension and other postretirement liabilities:
Settlement adjustment (1)	3		—		3		—

Comprehensive loss	$	(606)	$	(880)	$	(526)	$	(2,427)

(1)Net of $1 million tax benefits for the three and six months ended June 30, 2021 and for the six months ended June 30, 2020. Tax benefits for the three months ended June 30, 2020 were immaterial.

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2021		December 31, 2020

ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	2	$	13
Accounts receivable, net	408		368
Derivative assets	132		241
Other current assets	51		49
Total current assets	593		671
Natural gas and oil properties, using the full cost method, including $1,485 million as of June 30, 2021 and $1,472 million as of December 31, 2020 excluded from amortization	27,796		27,261

Other	496		523
Less: Accumulated depreciation, depletion and amortization	(23,846)		(23,673)
Total property and equipment, net	4,446		4,111
Operating lease assets	147		163
Deferred tax assets	—		—
Other long-term assets	208		215
Total long-term assets	355		378
TOTAL ASSETS	$	5,394	$	5,160
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	207	$	—
Accounts payable	653		573
Taxes payable	62		74
Interest payable	57		58

Derivative liabilities	901		245
Current operating lease liabilities	41		42
Other current liabilities	23		20
Total current liabilities	1,944		1,012
Long-term debt	2,814		3,150
Long-term operating lease liabilities	104		117
Long-term derivative liabilities	355		183
Pension and other postretirement liabilities	33		45
Other long-term liabilities	162		156
Total long-term liabilities	3,468		3,651
Commitments and contingencies (Note 12)
Equity/(deficit):
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 721,372,443 shares as of June 30, 2021 and 718,795,700 shares as of December 31, 2020	7		7

Additional paid-in capital	5,104		5,093
Accumulated deficit	(4,892)		(4,363)
Accumulated other comprehensive loss	(35)		(38)
Common stock in treasury, 44,353,224 shares as of June 30, 2021 and December 31, 2020	(202)		(202)
Total equity/(deficit)	(18)		497
TOTAL LIABILITIES AND EQUITY	$	5,394	$	5,160

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the six months ended June 30,
(in millions)	2021		2020
Cash Flows From Operating Activities:
Net loss	$	(529)	$	(2,427)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	196		197
Amortization of debt issuance costs	4		4
Impairments	—		2,134
Deferred income taxes	—		408
(Gain) loss on derivatives, unsettled	941		(17)
Stock-based compensation	2		2
Gain on early extinguishment of debt	—		(35)

Other	1		—
Change in assets and liabilities:
Accounts receivable	(40)		94
Accounts payable	75		(121)
Taxes payable	(12)		(11)
Interest payable	—		(1)
Inventories	3		6
Other assets and liabilities	(24)		21
Net cash provided by operating activities	617		254

Cash Flows From Investing Activities:
Capital investments	(493)		(472)
Proceeds from sale of property and equipment	2		2
Other	(1)		—
Net cash used in investing activities	(492)		(470)

Cash Flows From Financing Activities:

Payments on long-term debt	—		(72)
Payments on revolving credit facility	(1,782)		(919)
Borrowings under revolving credit facility	1,650		1,221
Change in bank drafts outstanding	—		(8)

Debt issuance/amendment costs	(1)		—


Cash paid for tax withholding	(3)		(1)

Net cash provided by (used in) financing activities	(136)		221

Increase (decrease) in cash and cash equivalents	(11)		5
Cash and cash equivalents at beginning of year	13		5
Cash and cash equivalents at end of period	$	2	$	10

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)


	Common Stock			Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Common Stock in Treasury			Total
	Shares Issued	Amount								Shares	Amount

	(in millions, except share amounts)
Balance at December 31, 2020	718,795,700	$	7	$	5,093	$	(4,363)	$	(38)	44,353,224	$	(202)	$	497
Comprehensive income:
Net income	—	—		—		80		—		—	—		80
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		80


Issuance of restricted stock	10,067	—		—		—		—		—	—		—
Cancellation of restricted stock	(405)	—		—		—		—		—	—		—
Restricted units granted	2,136,882	—		8		—		—		—	—		8

Performance units vested	1,001,505	—		4		—		—		—	—		4
Tax withholding – stock compensation	(748,627)	—		(3)		—		—		—	—		(3)
Balance at March 31, 2021	721,195,122	$	7	$	5,102	$	(4,283)	$	(38)	44,353,224	$	(202)	$	586
Comprehensive loss:
Net loss	—	—		—		(609)		—		—	—		(609)
Other comprehensive income	—	—		—		—		3		—	—		3
Total comprehensive loss	—	—		—		—		—		—	—		(606)
Stock-based compensation	—	—		2		—		—		—	—		2
Issuance of restricted stock	148,700	—		—		—		—		—	—		—

Restricted units granted	41,879	—		—		—		—		—	—		—
Tax withholding – stock compensation	(13,258)	—		—		—		—		—	—		—
Balance at June 30, 2021	721,372,443	$	7	$	5,104	$	(4,892)	$	(35)	44,353,224	$	(202)	$	(18)


	Common Stock			Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Common Stock in Treasury			Total
	Shares Issued	Amount								Shares	Amount

	(in millions, except share amounts)
Balance at December 31, 2019	585,555,923	$	6	$	4,726	$	(1,251)	$	(33)	44,353,224	$	(202)	$	3,246
Comprehensive loss:
Net loss	—	—		—		(1,547)		—		—	—		(1,547)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(1,547)
Stock-based compensation	—	—		1		—		—		—	—		1

Issuance of restricted stock	12,397	—		—		—		—		—	—		—
Cancellation of restricted stock	(167,130)	—		—		—		—		—	—		—

Restricted units granted	1,005,976	—		1		—		—		—	—		1
Tax withholding – stock compensation	(383,731)	—		—		—		—		—	—		—
Balance at March 31, 2020	586,023,435	$	6	$	4,728	$	(2,798)	$	(33)	44,353,224	$	(202)	$	1,701
Comprehensive loss:
Net loss	—	—		—		(880)		—		—	—		(880)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(880)
Stock-based compensation	—	—		1		—		—		—	—		1
Issuance of restricted stock	222,489	—		—		—		—		—	—		—
Cancellation of restricted stock	(1,079,515)	—		—		—		—		—	—		—
Restricted units granted	1,649,294	—		2		—		—		—	—		2
Tax withholding – stock compensation	(222,163)	—		(1)		—		—		—	—		(1)
Balance at June 30, 2020	586,593,540	$	6	$	4,730	$	(3,678)	$	(33)	44,353,224	$	(202)	$	823

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”), which was previously referred to as “Midstream” when it included the operation of gathering systems. Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Marketing.

E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania, West Virginia and Ohio. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia, Ohio and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania, Ohio and West Virginia as “Appalachia.” The Company also operates drilling rigs located in Appalachia, and provides certain oilfield products and services, principally serving the Company’s E&P activities through vertical integration.

Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations.

The accompanying consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report. The comparability of certain 2021 amounts to prior periods could be impacted as a result of the Montage Merger (as defined below) with Montage Resources Corporation (“Montage”) in November 2020. The Company believes the disclosures made are adequate to make the information presented not misleading.

The consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Annual Report”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Board of Directors, are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s 2020 Annual Report.

(2) ACQUISITION

Indigo Natural Resources Merger

On June 1, 2021, Southwestern entered into an Agreement and Plan of Merger with Ikon Acquisition Company, LLC (“Ikon”), Indigo Natural Resources LLC (“Indigo”) and Ibis Unitholder Representative LLC (the “Indigo Merger Agreement”). Pursuant to the terms of the Indigo Merger Agreement, Indigo will merge with and into Ikon, a subsidiary of Southwestern, with Indigo surviving the merger (the “Indigo Merger”). The outstanding equity interests in Indigo will be cancelled and converted into the right to receive (i) $400 million in cash consideration, and (ii) 339,270,568 shares of Southwestern common stock, in each case, subject to adjustment as provided in the Indigo Merger Agreement. Additionally, Southwestern will assume $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). The shares of Southwestern common stock had an aggregate dollar value equal to $1.6 billion, based on the volume weighted average sales price as traded on the New York Stock Exchange of such shares calculated for the thirty trading day period ending on May 28, 2021. Following the closing of the Indigo Merger, Southwestern’s existing shareholders and Indigo’s existing equity holders will own approximately 67% and 33%, respectively, of the outstanding shares of the combined company. The transaction is expected to close in the second half of 2021, subject to customary closing conditions, including the approval of Southwestern’s shareholders.

The Company has recorded approximately $2 million in transaction expenses for the three and six months ended June 30, 2021 related to the Indigo Merger.

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Montage Resources Merger

On August 12, 2020, Southwestern entered into an Agreement and Plan of Merger (the “Montage Agreement and Plan of Merger”) with Montage whereby Montage would merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Montage Merger"). On November 12, 2020, Montage’s stockholders voted to approve the Montage Merger and it was made effective on November 13, 2020. The Montage Merger added to Southwestern’s oil and gas portfolio in Appalachia.

In exchange for each share of Montage common stock, Montage stockholders received 1.8656 shares of Southwestern common stock, plus cash in lieu of any fractional share of Southwestern common stock that otherwise would have been issued, based on the average price of $3.05 per share of Southwestern common stock on the NYSE on November 13, 2020. Following the closing of the Montage Merger, Southwestern's existing shareholders and Montage's existing shareholders owned approximately 90% and 10%, respectively, of the outstanding shares of the combined company.

In anticipation of the Montage Merger, in August 2020 Southwestern issued $350 million of new senior unsecured notes and 63,250,000 shares of common stock for $152 million after deducting underwriting discounts and offering expenses. The Company used the net proceeds from the debt and common stock offerings and borrowings under its revolving credit facility to fund a redemption of $510 million aggregate principal amount of Montage's outstanding 8.875% senior notes due 2023 (the “Montage Notes”) and related accrued interest in connection with the closing of the Montage Merger. See Note 7 and Note 11 for additional information.

The Montage Merger constituted a business combination and was accounted for using the acquisition method of accounting. The following table presents the fair value of consideration transferred to Montage stockholders as a result of the Montage Merger:


(in millions, except share, per share amounts)	As of November 13, 2020
Shares of Southwestern common stock issued in respect of outstanding Montage common stock	67,311,166
Shares of Southwestern common stock issued in respect of Montage stock-based awards	2,429,682
	69,740,848
NYSE closing price per share of Southwestern common shares on November 13, 2020	$	3.05
Total consideration (fair value of Southwestern common shares issued)	$	213
Increase in Southwestern common stock ($0.01 par value per share)	1
Increase in Southwestern additional paid-in capital	$	212

The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Montage Merger. The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the Company’s natural gas and oil properties as the studies necessary to determine the fair value are finalized. These amounts will be finalized no later than one year from the acquisition date. For the six months ended June 30, 2021 there were no changes to the allocation presented in the 2020 Form 10-K.

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(in millions)	As of November 13, 2020
Consideration:
Fair value of Southwestern’s stock issued on November 13, 2020	$	213
Fair Value of Assets Acquired:
Cash and cash equivalents	3
Accounts receivable	73
Other current assets	1
Commodity derivative assets	11
Evaluated oil and gas properties	1,012
Unevaluated oil and gas properties	90
Other property, plant and equipment	28
Other long-term assets	26
Total assets acquired	1,244
Fair Value of Liabilities Assumed:
Accounts payable	145
Other current liabilities	49
Derivative liabilities	70
Revolving credit facility	200
Senior unsecured notes	522
Asset retirement obligations	28
Other noncurrent liabilities	17
Total liabilities assumed	1,031
Net Assets Acquired and Liabilities Assumed	$	213

For the six months ended June 30, 2021, revenues and operating income associated with the operations acquired through the Montage Merger totaled $250 million and $121 million, respectively.

The following table presents selected unaudited pro forma condensed financial information for the three and six months ended June 30, 2020 as if the Montage Merger had occurred on January 1, 2019:


	Pro forma results
(in millions, except per share amounts)	For the three months ended June 30, 2020		For the six months ended June 30, 2020
Revenues	$	501	$	1,226
Loss from continuing operations	$	(925)	$	(2,415)

The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Montage Merger been completed at January 1, 2019, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma information gives effect to the Montage Merger and related equity and debt issuances along with the use of proceeds therefrom as if they had occurred on January 1, 2019. The unaudited pro forma information for 2020 is a result of combining the statements of operations of Southwestern with the pre-Montage Merger results of Montage from January 1, 2020 and included adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the Montage Merger and the impact of any Montage Merger-related costs. The pro forma results include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. Interest expense was adjusted to reflect the retirement of the Montage senior notes, the Montage credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the Montage notes and revolving line of credit. This decrease was partially offset by increases in interest on debt associated with the issuance of $350 million in new 8.375% Senior Notes due 2028 related to the Southwestern debt offering and borrowings under Southwestern’s credit facility used to pay off the Montage notes, Montage credit facility and related accrued interest. Management believes the estimates and assumptions are reasonable, and the relative effects of the Montage Merger are properly reflected.

Montage Merger-Related Expenses

For the three and six months ended June 30, 2021, the Company incurred $1 million and $2 million, respectively, in Montage Merger-related expenses primarily related to one-time severance costs and the accelerated vesting of certain Montage share-based awards, based on the terms of the Montage Agreement and Plan of Merger, for former Montage employees that continued to assist with the transition into 2021.

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(3) RESTRUCTURING CHARGES

On February 24, 2021, the Company notified employees of a workforce reduction plan as part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the three and six months ended June 30, 2021, and were substantially complete by the end of the first quarter of 2021.

In February 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company’s organizational structure. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the three months ended June 30, 2020, and were substantially complete by the end of the first quarter of 2020.

The following table presents a summary of the restructuring charges included in Operating Income (Loss) for the three and six months ended June 30, 2021 and 2020:


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Severance (including payroll taxes) (1)	$	1	$	2	$	7	$	12

(1)Total restructuring charges were $1 million and $2 million for the Company’s E&P segment for the three months ended June 30, 2021 and 2020, respectively, and $7 million and $12 million for the Company’s E&P segment for the six months ended June 30, 2021 and 2020, respectively.

The following table presents a reconciliation of the liability associated with the Company’s restructuring activities at June 30, 2021, which is reflected in accounts payable on the consolidated balance sheet:


(in millions)
Liability at December 31, 2020	$	3
Additions	7
Distributions	(10)
Liability at June 30, 2021	$	—

(4) REVENUE RECOGNITION

Revenues from Contracts with Customers

Natural gas and liquids. Natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions in the geographic areas in which the Company operates. Under the Company’s sales contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There is no significant financing component to the Company’s revenues as payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

The Company records revenue from its natural gas and liquids production in the amount of its net revenue interest in sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production imbalances are generally recorded as receivables and payables and not contract assets or contract liabilities as the imbalances are between the Company and other working interest owners, not the end customer.

Marketing. The Company, through its marketing affiliate, markets natural gas, oil and NGLs for its affiliated E&P company as well as other joint interest owners that choose to market with the Company. In addition, the Company markets some products purchased from third parties. Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to market indices with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions. Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the

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performance obligations are fulfilled. Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

Disaggregation of Revenues

The Company presents a disaggregation of E&P revenues by product on the consolidated statements of operations net of intersegment revenues. The following table reconciles operating revenues as presented on the consolidated statements of operations to the operating revenues by segment:


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended June 30, 2021
Gas sales	$	421	$	—	$	12	$	433
Oil sales	105		—		1		106
NGL sales	178		—		1		179
Marketing	—		983		(651)		332

Total	$	704	$	983	$	(637)	$	1,050

Three months ended June 30, 2020
Gas sales	$	155	$	—	$	9	$	164
Oil sales	16		—		3		19
NGL sales	40		—		—		40
Marketing	—		389		(202)		187

Total	$	211	$	389	$	(190)	$	410


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Six months ended June 30, 2021
Gas sales	$	872	$	—	$	25	$	897
Oil sales	185		—		2		187
NGL sales	351		—		1		352
Marketing	—		1,979		(1,295)		684
Other (1)	1		1		—		2
Total	$	1,409	$	1,980	$	(1,267)	$	2,122

Six months ended June 30, 2020
Gas sales	$	394	$	—	$	18	$	412
Oil sales	68		—		3		71
NGL sales	90		—		—		90
Marketing	—		937		(511)		426
Other (2)	3		—		—		3
Total	$	555	$	937	$	(490)	$	1,002

(1)For the six months ended June 30, 2021, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs and other Marketing revenues consists primarily of sales of gas from storage.

(2)For the six months ended June 30, 2020, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs.

Associated E&P revenues are also disaggregated for analysis on a geographic basis by the core areas in which the Company operates, which are in Pennsylvania, West Virginia and Ohio.


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Northeast Appalachia	$	230	$	117	$	493	$	312
Southwest Appalachia	474		94		915		243
Other	—		—		1		—
Total	$	704	$	211	$	1,409	$	555

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Receivables from Contracts with Customers

The following table reconciles the Company’s receivables from contracts with customers to consolidated accounts receivable as presented on the consolidated balance sheet:


(in millions)	June 30, 2021		December 31, 2020
Receivables from contracts with customers	$	391	$	350
Other accounts receivable	17		18
Total accounts receivable	$	408	$	368

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three and six months ended June 30, 2021 and 2020. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(5) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of June 30, 2021 and December 31, 2020:


(in millions)	June 30, 2021		December 31, 2020
Cash	$	2	$	13
Marketable securities (1)	—		—

Total	$	2	$	13

(1)Typically consists of government stable value money market funds.

(6) NATURAL GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had no hedge positions that were designated for hedge accounting as of June 30, 2021. Prices used to calculate the ceiling value of reserves were as follows:


	June 30, 2021		June 30, 2020
Natural gas (per MMBtu)	$	2.43	$	2.07
Oil (per Bbl)	$	49.78	$	47.17
NGLs (per Bbl)	$	17.06	$	8.87

Using the average quoted prices above, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at June 30, 2021. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

No impairment expense was recorded for the six months ended June 30, 2021 in relation to the recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with Accounting Standards Codification (“ASC”) Topic 820 – Fair Value Measurement. In the fourth quarter of 2020, pursuant to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Montage Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Montage Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021, as long as the Company can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company is required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Montage Merger was based on forward natural gas and oil pricing existing at the date of the Montage Merger, and the Company affirmed that there has not been a material decline

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to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger have an unamortized cost at June 30, 2021 of $1,130 million. Due to the improvement in commodity prices in the second quarter of 2021, no impairment charge would have been recorded for the three and six months ended June 30, 2021 had the recently acquired Montage natural gas and oil properties been included in the full cost ceiling test.

The Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1.5 billion at March 31, 2020 and $650 million at June 30, 2020, resulting in a non-cash ceiling test impairment for the first and second quarters of 2020.

(7) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, restricted stock units and performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise or contingent issuance of certain securities.

In August 2020, the Company completed an underwritten public offering of 63,250,000 shares of its common stock with an offering price to the public of $2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately $152 million. See Note 2 for additional details regarding the Company’s use of proceeds from the equity offering.

The following table presents the computation of earnings per share for the three and six months ended June 30, 2021 and 2020:


	For the three months ended June 30,				For the six months ended June 30,
(in millions, except share/per share amounts)	2021		2020		2021		2020
Net loss	$	(609)	$	(880)	$	(529)	$	(2,427)

Number of common shares:
Weighted average outstanding	676,722,999		541,079,192		676,057,534		540,693,841
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	—		—		—		—
Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	—		—		—		—
Weighted average and potential dilutive outstanding	676,722,999		541,079,192		676,057,534		540,693,841

Loss per common share
Basic	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)
Diluted	$	(0.90)	$	(1.63)	$	(0.78)	$	(4.49)

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three and six months ended June 30, 2021 and 2020, as they would have had an antidilutive effect:


	For the three months ended June 30,		For the six months ended June 30,
	2021	2020	2021	2020
Unexercised stock options	3,733,971	4,548,735	3,764,362	4,566,648
Unvested share-based payment	721,633	902,615	805,791	1,024,867
Restricted stock units	2,917,427	2,631,727	4,059,473	2,983,352
Performance units	2,832,043	2,712,207	2,934,615	2,096,041
Total	10,205,074	10,795,284	11,564,241	10,670,908

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(8) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of June 30, 2021, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, call options, swaptions and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:


Fixed price swaps			If the Company sells a fixed price swap, the Company receives a fixed price for the contract and pays a floating market price to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract and pays a fixed price to the counterparty.

Two-way costless collars			Arrangements that contain a fixed floor price (“purchased put option”) and a fixed ceiling price (“sold call option”) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.

Three-way costless collars			Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price that, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

Basis swaps			Arrangements that guarantee a price differential for natural gas from a specified delivery point. If the Company sells a basis swap, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the stated terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract.

Options (Calls and Puts)			The Company purchases and sells options in exchange for premiums. If the Company purchases a call option, the Company receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company purchases a put option, the Company receives from the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. If the Company sells a put option, the Company pays the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party.

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Swaptions			Instruments that refer to an option to enter into a fixed price swap. In exchange for an option premium, the purchaser gains the right but not the obligation to enter a specified swap agreement with the issuer for specified future dates. If the Company sells a swaption, the counterparty has the right to enter into a fixed price swap wherein the Company receives a fixed price for the contract and pays a floating market price to the counterparty. If the Company purchases a swaption, the Company has the right to enter into a fixed price swap wherein the Company receives a floating market price for the contract and pays a fixed price to the counterparty.

Interest rate swaps			Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.

The Company contracts with counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the credit ratings and credit default swap rates of these counterparties where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The fair value of the Company’s derivative assets and liabilities includes a non-performance risk factor. See Note 10 for additional details regarding the Company’s fair value measurements of its derivatives position. The Company presents its derivatives position on a gross basis and does not net the asset and liability positions.

The following tables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of June 30, 2021:


Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at June 30, 2021 (in millions)
Natural Gas
2021
Fixed price swaps	103	$	2.80	$	—	$	—	$	—	$	—	$	(87)
Two-way costless collars	140	—		—		2.62		2.97		—		(101)
Three-way costless collars	153	—		2.18		2.51		2.86		—		(127)
Total	396											$	(315)
2022
Fixed price swaps	268	$	2.72	$	—	$	—	$	—	$	—	$	(119)
Two-way costless collars	125	—		—		2.65		3.04		—		(46)
Three-way costless collars	333	—		2.06		2.51		2.94		—		(127)
Total	726											$	(292)
2023
Fixed price swaps	23	$	2.70	$	—	$	—	$	—	$	—	$	(3)
Two-way costless collars	34	—		—		2.50		2.72		—		(3)
Three-way costless collars	215	—		2.09		2.54		3.00		—		(34)
Total	272											$	(40)
2024
Three-way costless collars	11	$	—	$	2.25	$	2.80	$	3.54	$	—	$	(1)

Basis Swaps
2021	166	$	—	$	—	$	—	$	—	$	(0.47)	$	62
2022	261	—		—		—		—		(0.40)		40
2023	163	—		—		—		—		(0.53)		7
2024	40	—		—		—		—		(0.70)		2
2025	9	—		—		—		—		(0.64)		1
Total	639											$	112

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	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at June 30, 2021 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2021
Fixed price swaps	1,739	$	50.10	$	—	$	—	$	—	$	(37)
Two-way costless collars	92	—		—		37.50		45.50		(2)
Three-way costless collars	1,152	—		39.22		49.05		54.35		(20)
Total	2,983									$	(59)
2022
Fixed price swaps	3,203	$	53.54	$	—	$	—	$	—	$	(39)
Three-way costless collars	1,380	—		39.89		50.23		57.05		(15)
Total	4,583									$	(54)
2023
Fixed price swaps	846	$	55.98	$	—	$	—	$	—	$	(4)
Three-way costless collars	1,268	—		33.97		45.51		56.12		(12)
Total	2,114									$	(16)
2024
Fixed price swaps	54	$	53.15	$	—	$	—	$	—	$	—

Ethane
2021
Fixed price swaps	3,284	$	7.64	$	—	$	—	$	—	$	(17)
Two-way costless collars	294	—		—		7.14		10.40		(1)
Total	3,578									$	(18)
2022
Fixed price swaps	2,362	$	8.97	$	—	$	—	$	—	$	(6)
Two-way costless collars	135	—		—		7.56		9.66		—
Total	2,497									$	(6)





Propane
2021
Fixed price swaps	4,261	$	24.00	$	—	$	—	$	—	$	(84)


2022
Fixed price swaps	4,092	$	25.90	$	—	$	—	$	—	$	(42)
Three-way costless collars	305	—		16.80		21.00		31.92		(2)
Total	4,397									$	(44)



Normal Butane
2021
Fixed price swaps	1,245	$	29.04	$	—	$	—	$	—	$	(27)
2022
Fixed price swaps	1,295	$	29.16	$	—	$	—	$	—	$	(16)

Natural Gasoline
2021
Fixed price swaps	1,281	$	43.58	$	—	$	—	$	—	$	(29)
2022
Fixed price swaps	1,201	$	45.76	$	—	$	—	$	—	$	(17)

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Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at June 30, 2021 (in millions)





Call Options – Natural Gas (Net)
2021	38	$	3.19	$	(21)
2022	77	3.00		(34)
2023	46	2.94		(14)
2024	9	3.00		(4)

Total	170			$	(73)
Put Options – Natural Gas
2021	9	$	2.00	$	—
2022	5	2.00		—
Total	14			$	—


	Volume (MBbls)	Weighted Average Strike Price per Bbl		Fair Value at June 30, 2021 (in millions)
Call Options – Oil
2021	114	$	60.00	$	(1)


	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at June 30, 2021 (in millions)
Swaptions – Natural Gas
2021 (1)	18	$	3.00	$	(5)

(1)The Company has sold swaptions with an underlying tenor of January 2022 to December 2022, with an exercise date of December 23, 2021.


	Volume (Bcf)	Weighted Average Strike Price per MMBtu				Fair Value at June 30, 2021 (in millions)
		Swaps		Basis Differential
Storage (1)
2021
Purchased fixed price swaps	1	$	2.45	$	—	$	1
Purchased basis swaps	1	—		(0.88)		—
Fixed price swaps	1	2.59		—		(1)
Basis swaps	—	—		(0.89)		—
Total	3					$	—
2022
Purchased fixed price swaps	—	$	2.14	$	—	$	—
Fixed price swaps	2	2.82		—		(1)
Basis swaps	1	—		(0.57)		—
Total	3					$	(1)

(1)The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn and sold at a later date.


Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at June 30, 2021 (in millions)
2021	2	$	2.44	$	3

(1)The Company has entered into a limited number of derivatives to protect the value of certain long-term sales contracts.

At June 30, 2021, the net fair value of the Company’s financial instruments related to commodities was a $983 million liability and included a net reduction of the liability of $2 million related to non-performance risk. See Note 10 for additional details regarding the Company’s fair value measurements of its derivatives position.

As of June 30, 2021, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or do not meet hedge accounting requirements, are recorded

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as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gain and losses on both settled and unsettled derivatives. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) is summarized below as of June 30, 2021 and December 31, 2020:


Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	June 30, 2021		December 31, 2020
Derivatives not designated as hedging instruments:

Purchased fixed price swaps – natural gas	Derivative assets	$	3	$	1

Fixed price swaps – natural gas	Derivative assets	1		37
Fixed price swaps – oil	Derivative assets	—		13


Two-way costless collars – natural gas	Derivative assets	16		54


Three-way costless collars – natural gas	Derivative assets	18		57
Three-way costless collars – oil	Derivative assets	1		15
Basis swaps – natural gas	Derivative assets	83		60
Call options – natural gas	Derivative assets	9		4
Purchased fixed price swaps – natural gas storage	Derivative assets	1		—

Fixed price swaps – natural gas	Other long-term assets	—		7
Fixed price swaps – oil	Other long-term assets	—		2


Two-way costless collars – natural gas	Other long-term assets	12		20


Three-way costless collars – natural gas	Other long-term assets	68		87
Three-way costless collars – oil	Other long-term assets	5		15
Basis swaps – natural gas	Other long-term assets	56		15

Interest rate swaps	Other long-term assets	1		—
Total derivative assets		$	274	$	387

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Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	June 30, 2021		December 31, 2020
Derivatives not designated as hedging instruments:


Fixed price swaps – natural gas	Derivative liabilities	$	158	$	7
Fixed price swaps – oil	Derivative liabilities	58		12
Fixed price swaps – ethane	Derivative liabilities	21		10
Fixed price swaps – propane	Derivative liabilities	110		36
Fixed price swaps – normal butane	Derivative liabilities	36		8
Fixed price swaps – natural gasoline	Derivative liabilities	39		13
Two-way costless collars – natural gas	Derivative liabilities	151		43
Two-way costless collars – oil	Derivative liabilities	2		1
Two-way costless collars – ethane	Derivative liabilities	1		—
Three-way costless collars – natural gas	Derivative liabilities	217		82
Three-way costless collars – oil	Derivative liabilities	29		15
Three-way costless collars – propane	Derivative liabilities	1		—
Basis swaps – natural gas	Derivative liabilities	19		3
Call options – natural gas	Derivative liabilities	51		12
Call options – oil	Derivative liabilities	1		—
Put options – natural gas	Derivative liabilities	—		1
Swaptions – natural gas	Derivative liabilities	5		2

Fixed price swaps – natural gas storage	Derivative liabilities	2		—
Fixed price swaps – natural gas	Long-term derivative liabilities	52		3
Fixed price swaps – oil	Long-term derivative liabilities	22		2
Fixed price swaps – ethane	Long-term derivative liabilities	2		—
Fixed price swaps – propane	Long-term derivative liabilities	16		2
Fixed price swaps – normal butane	Long-term derivative liabilities	7		1
Fixed price swaps – natural gasoline	Long-term derivative liabilities	7		2
Two-way costless collars – natural gas	Long-term derivative liabilities	27		21

Three-way costless collars – natural gas	Long-term derivative liabilities	158		102
Three-way costless collars – oil	Long-term derivative liabilities	24		15
Three-way costless collars – propane	Long-term derivative liabilities	1		—
Basis swap – natural gas	Long-term derivative liabilities	8		7
Call options – natural gas	Long-term derivative liabilities	31		28

Total derivative liabilities		$	1,256	$	428

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The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three and six months ended June 30, 2021 and 2020:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings
	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled	For the three months ended June 30,				For the six months ended June 30,
Derivative Instrument		2021		2020		2021		2020

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	2	$	1	$	2	$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(221)		(39)		(243)		64
Fixed price swaps – oil	Gain (Loss) on Derivatives	(41)		(39)		(81)		74
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(11)		(22)		(13)		(10)
Fixed price swaps – propane	Gain (Loss) on Derivatives	(43)		(44)		(88)		(8)
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	(19)		—		(34)		—
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	(11)		—		(31)		—
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(148)		(7)		(160)		(11)
Two-way costless collars – oil	Gain (Loss) on Derivatives	—		(10)		(1)		9
Two-way costless collars – ethane	Gain (Loss) on Derivatives	(1)		—		(1)		—
Two-way costless collars – propane	Gain (Loss) on Derivatives	—		(3)		—		(1)
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(249)		(45)		(249)		(96)
Three-way costless collars – oil	Gain (Loss) on Derivatives	(29)		(6)		(47)		19
Three-way costless collars – propane	Gain (Loss) on Derivatives	(1)		—		(2)		—
Basis swaps – natural gas	Gain (Loss) on Derivatives	44		(13)		47		(14)
Call options – natural gas	Gain (Loss) on Derivatives	(40)		(4)		(37)		(9)
Call options – oil	Gain (Loss) on Derivatives	—		—		(1)		1
Put options – natural gas	Gain (Loss) on Derivatives	1		—		1		—
Swaptions – natural gas	Gain (Loss) on Derivatives	(4)		—		(3)		—
Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives	1		—		1		(1)
Fixed price swap – natural gas storage	Gain (Loss) on Derivatives	(2)		1		(2)		—
Interest rate swaps	Gain (Loss) on Derivatives	—		1		1		—
Total gain (loss) on unsettled derivatives		$	(772)	$	(229)	$	(941)	$	17

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Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended June 30,					For the six months ended June 30,
Derivative Instrument		2021		2020			2021			2020

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	1	$	(1)		$	1		$	(2)
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(6)		84		(2)	(1)			89		(2)
Fixed price swaps – oil	Gain (Loss) on Derivatives	(28)		18			(45)			27
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(6)		2			(10)			8
Fixed price swaps – propane	Gain (Loss) on Derivatives	(30)		7			(60)			17
Fixed price swaps – normal butane	Gain (Loss) on Derivatives	(9)		—			(16)			—
Fixed price swaps – natural gasoline	Gain (Loss) on Derivatives	(13)		—			(22)			—
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(2)		—			—			6
Two-way costless collars – oil	Gain (Loss) on Derivatives	(1)		6			(2)			9
Two-way costless collars – propane	Gain (Loss) on Derivatives	—		1			—			2
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(8)		7			(7)			43
Three-way costless collars – oil	Gain (Loss) on Derivatives	(5)		3			(6)			4
Basis swaps – natural gas	Gain (Loss) on Derivatives	8		(7)			49			9


Put options – natural gas	Gain (Loss) on Derivatives	—		—			(2)		(3)	—

Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	—		—			—			1

Total gain (loss) on settled derivatives		$	(99)	$	120		$	(121)		$	213

Total gain (loss) on derivatives		$	(871)	$	(109)		$	(1,062)		$	230

(1)The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that settled within the period.

(2)Includes $4 million amortization of premiums paid related to certain natural gas fixed price options for the three and six months ended June 30, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations.

(3)Includes $2 million amortization of premiums paid related to certain natural gas put options for the six months ended June 30, 2021 which is included in gain (loss) on derivatives on the consolidated statements of operations.

(9) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive income for the first six months of 2021 were related to the Company’s pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income and the related tax effects for the six months ended June 30, 2021:


(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2020	$	(24)	$	(14)	$	(38)
Other comprehensive income before reclassifications	—		—		—
Amounts reclassified from other comprehensive income (1)	3		—		3
Net current-period other comprehensive income	3		—		3
Ending balance June 30, 2021	$	(21)	$	(14)	$	(35)

Details about Accumulated Other Comprehensive Income

Affected Line Item in the Consolidated Statement of Operations

Amount Reclassified from Accumulated Other Comprehensive Income

For the six months ended
June 30, 2021

(in millions)

Pension and other postretirement:

Settlement adjustment (1)

Other Income (Loss), Net

Provision (Benefit) for Income Taxes

Net Income

Total reclassifications for the period

Net Income

(1) See Note 14 for additional details regarding the Company’s pension and other postretirement benefit plans.

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(10) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

The carrying amounts and estimated fair values of the Company’s financial instruments as of June 30, 2021 and December 31, 2020 were as follows:


	June 30, 2021				December 31, 2020
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	2	$	2	$	13	$	13
2018 revolving credit facility due April 2024	568		568		700		700
Senior notes (1)	2,471		2,684		2,471		2,609
Derivative instruments, net	(982)		(982)		(41)		(41)

(1)Excludes unamortized debt issuance costs and debt discounts.

The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

The carrying values of cash and cash equivalents, including marketable securities, accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes are based on the market value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. The fair value of the Company’s 4.10% Senior Notes due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy. The fair values of the Company’s remaining senior notes are considered the be a Level 1 measurement. The carrying values of the borrowings under the Company’s revolving credit facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its revolving credit facility to be a Level 1 measurement on the fair value hierarchy.

Derivative Instruments: The Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. As of June 30, 2021 and December 31, 2020, the impact of non-performance risk on the fair value of the Company’s net derivative asset position was a decrease of the net liability of $2 million and $1 million, respectively.

The Company has classified its derivative instruments into levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2020 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s call and put options, two-way costless collars and three-way costless collars (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. Inputs to the Black-Scholes model, including the volatility input, are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively. Swaptions are valued using a variant of the Black-Scholes model referred to as the Black Swaption model, which uses its own separate volatility inputs.

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The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.

Assets and liabilities measured at fair value on a recurring basis are summarized below:


	June 30, 2021
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	3	$	—	$	3
Fixed price swaps	—		1		—		1
Two-way costless collars	—		28		—		28
Three-way costless collars	—		92		—		92
Basis swaps	—		139		—		139
Call options	—		9		—		9
Purchased fixed price swaps – storage	—		1		—		1
Interest rate swaps	—		1		—		1
Liabilities

Fixed price swaps	—		(528)		—		(528)
Two-way costless collars	—		(181)		—		(181)
Three-way costless collars	—		(430)		—		(430)
Basis swaps	—		(27)		—		(27)
Call options	—		(83)		—		(83)

Swaptions	—		(5)		—		(5)
Fixed price swaps – storage	—		(2)		—		(2)

Total (1)	$	—	$	(982)	$	—	$	(982)

(1)Includes a net reduction to the liability fair value of $2 million related to estimated nonperformance risk.


	December 31, 2020
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	1	$	—	$	1
Fixed price swaps	—		59		—		59
Two-way costless collars	—		74		—		74
Three-way costless collars	—		174		—		174
Basis swaps	—		75		—		75
Call options	—		4		—		4

Liabilities

Fixed price swaps	—		(96)		—		(96)
Two-way costless collars	—		(65)		—		(65)
Three-way costless collars	—		(214)		—		(214)
Basis swaps	—		(10)		—		(10)
Call options	—		(40)		—		(40)
Put options	—		(1)		—		(1)
Swaptions	—		(2)		—		(2)


Total (1)	$	—	$	(41)	$	—	$	(41)

(1)Includes a net reduction to the liability fair value of $1 million related to estimated nonperformance risk.

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(11) DEBT

The components of debt as of June 30, 2021 and December 31, 2020 consisted of the following:


	June 30, 2021
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Current portion of long-term debt:
4.10% Senior Notes due March 2022	$	207	$	—		$	—	$	207
Total current portion of long-term debt	$	207	$	—		$	—	$	207

Long-term debt:
Variable rate (2.10% at June 30, 2021) 2018 revolving credit facility due April 2024	$	568	$	—	(1)	$	—	$	568
4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(5)			—		613
7.75% Senior Notes due October 2027	440		(4)			—		436
8.375% Senior Notes due September 2028	350		(5)			—		345
Total long-term debt	$	2,832	$	(18)		$	(1)	$	2,813

Total debt	$	3,039	$	(18)		$	(1)	$	3,020

	December 31, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (2.11% at December 31, 2020) 2018 term loan facility due April 2024	$	700	$	—	(1)	$	—	$	700
4.10% Senior Notes due March 2022	207		—			—		207
4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(6)			—		612
7.75% Senior Notes due October 2027	440		(5)			—		435
8.375% Senior Notes due September 2028	350		(5)			—		345
Total long-term debt	$	3,171	$	(20)		$	(1)	$	3,150

(1)At June 30, 2021 and December 31, 2020, unamortized issuance expense of $11 million and $12 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On June 2, 2021 in conjunction with the announcement of the Indigo Merger, S&P placed the Company’s bond rating on credit watch for a potential positive upgrade. Interest savings from any potential upgrade would be realized for coupon payments paid after January 2022.

The following is a summary of scheduled debt maturities by year as of June 30, 2021:


(in millions)
2021	$	—
2022	207
2023	—
2024 (1)	568
2025	856
Thereafter	1,408
	$	3,039

(1)The Company’s current revolving credit facility matures in 2024.

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Credit Facilities

2018 Revolving Credit Facility

In April 2018, the Company replaced its credit facility that was entered into in 2016 with a new revolving credit facility (the “2018 credit facility”) with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in March 2021, the banks participating in the 2018 credit facility reaffirmed the elected borrowing base and aggregate commitments to be $2.0 billion. The borrowing base is subject to redetermination at least twice a year, in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets.

The Company may utilize the 2018 credit facility in the form of loans and letters of credit. Loans under the 2018 credit facility are subject to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR for such interest period plus the applicable margin (as those terms are defined in the 2018 credit facility documentation). The applicable margin for Eurodollar loans under the 2018 credit facility, as amended, ranges from 1.75% to 2.75% based on the Company’s utilization of the 2018 credit facility. Alternate base rate loans bear interest at the alternate base rate plus the applicable margin. The applicable margin for alternate base rate loans under the 2018 credit facility, as amended, ranges from 0.75% to 1.75% based on the Company’s utilization of the 2018 credit facility.

The 2018 credit facility contains customary representations and warranties and contains covenants including, among others, the following:

•a prohibition against incurring debt, subject to permitted exceptions;

•a restriction on creating liens on assets, subject to permitted exceptions;

•restrictions on mergers and asset dispositions;

•restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business; and

•maintenance of the following financial covenants, commencing with the fiscal quarter ending June 30, 2018:

1.Minimum current ratio of no less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).

2.Maximum total net leverage ratio of no greater than, with respect to each fiscal quarter ending on or after June 30, 2020, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. EBITDAX, as defined in the credit agreement governing the Company’s 2018 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.

The 2018 credit facility contains customary events of default that include, among other things, the failure to comply with the financial covenants described above, non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations and warranties, bankruptcy and insolvency events, material judgments and cross-defaults to material indebtedness. If an event of default occurs and is continuing, all amounts outstanding under the 2018 credit facility may become immediately due and payable. As of June 30, 2021, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility.

Each United States domestic subsidiary of the Company for which the Company owns 100% guarantees the 2018 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes.

As of June 30, 2021, the Company had $233 million in letters of credit and $568 million borrowings outstanding under the 2018 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

The Company’s debt exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as

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Administrative Agent, and the Company. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (“SOFR”).

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes”). The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. Effective in July 2018, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the 2025 Notes bondholders at the higher interest rate was paid in January 2021. On June 2, 2021 in conjunction with the announcement of the Indigo Merger, S&P placed the Company’s bond rating on credit watch for a potential positive upgrade. Interest savings on the 2025 Notes from any potential upgrade would be realized for coupon payments paid after January 2022.

In the first half of 2020, the Company repurchased $6 million of its 4.10% Senior Notes due 2022, $36 million of its 4.95% Senior Notes due 2025, $21 million of its 7.50% Senior Notes due 2026 and $44 million of its 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

In August 2020, the Company completed a public offering of $350 million aggregate principal amount of its 8.375% Senior Notes due 2028 (the “2028 Notes”), with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses. The 2028 Notes were sold to the public at 100% of their face value. The net proceeds from the notes, in conjunction with the net proceeds from the August 2020 common stock offering and borrowings under the revolving credit facility, were utilized to fund a redemption of $510 million of Montage’s Notes in connection with the closing of the Montage Merger.

On June 1, 2021, Southwestern entered into the Indigo Merger Agreement. Upon the close of the Indigo Merger, and pursuant to the terms of the Indigo Merger Agreement, Southwestern will assume $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo. The transaction is expected to close in the second half of 2021, subject to customary closing conditions, including the approval of Southwestern’s shareholders.

(12) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of June 30, 2021, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.3 billion, $369 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. The Company also had guarantee obligations of up to $895 million of that amount. As of June 30, 2021, future payments under non-cancelable firm transportation and gathering agreements were as follows:


	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Infrastructure currently in service	$	7,965	$	713	$	1,557	$	1,317	$	1,744	$	2,634
Pending regulatory approval and/or construction (1)	369		2		18		25		52		272
Total transportation charges	$	8,334	$	715	$	1,575	$	1,342	$	1,796	$	2,906

(1)Based on estimated in-service dates as of June 30, 2021.

Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position, results of operations or cash flows of the Company.

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Litigation

The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of June 30, 2021, the Company does not currently have any material amounts accrued related to litigation matters. For any matters not accrued for, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

St. Lucie County Fire District Firefighters’ Pension Trust

On October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust filed a putative class action in the 61st District Court in Harris County, Texas, against the Company, certain of its former officers and current and former directors and the underwriters on behalf of itself and others that purchased certain depositary shares from the Company’s January 2015 equity offering, alleging material misstatements and omissions in the registration statement for that offering. The Company removed the case to federal court, but after a decision by the United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the federal court remanded the case to the Texas state court. The Texas trial court denied the Company’s motion to dismiss, and in February 2020, the court of appeals declined to exercise discretion to reverse the trial court’s decision. The Company filed a petition to review the trial court’s decision with the Texas Supreme Court, and the Court requested a response from the plaintiff. The Court subsequently requested full briefing on the merits of the case. The Company carries insurance for the claims asserted against it and the officer and director defendants, and the carrier accepted coverage. On June 15, 2021, the parties agreed to a settlement of the case without any admission of liability. The Company’s insurance carrier is fully funding the settlement amount. The trial court has issued an order preliminarily approving the settlement. A hearing on final approval of the settlement is set for October 21, 2021.

Indemnifications

The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings, and litigation, such as the St. Lucie County Fire District Firefighters’ Pension Trust case described above. In the case of asset dispositions, these indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. The Company likewise obtains indemnification for future matters when it sells assets, although there is no assurance the buyer will be capable of performing those obligations. In the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. No material liabilities have been recognized in connection with these indemnifications.

(13) INCOME TAXES

The Company’s effective tax rate was approximately 0% for the three and six months ended June 30, 2021. The effective tax rate for the three and six months June 30, 2021 related to the effects of a valuation allowance against the Company’s U.S. deferred tax assets. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.

In the first quarter of 2020, due to significant pricing declines and the material write-down of the carrying value of the Company’s natural gas and oil properties in addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in its valuation allowance. The net change in valuation allowance is reflected as a component of income tax expense. The Company also retained a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.

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The Company’s effective tax rate was approximately 0% and (20)% for the three and six months ended June 30, 2020, respectively. The effective tax rate for the six months ended June 30, 2020 was primarily the effect of recording the valuation allowance discussed above.

The Company adopted Accounting Standards Update No. 2019-12 (“ASU 2019-12”) in the current period. ASU 2019-12 addressed simplification to income tax accounting rules, such as removing a few exceptions to intraperiod allocation. There was no material impact to the financial statements as a result of this adoption.

(14) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company maintains defined pension and other postretirement benefit plans, which cover substantially all of the Company’s employees. As part of ongoing effort to reduce costs, the Company elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. Net periodic pension costs include the following components for the three and six months ended June 30, 2021 and 2020:



	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended June 30,				For the six months ended June 30,
(in millions)		2021		2020		2021		2020
Service cost	General and administrative expenses	$	—	$	2	$	—	$	4
Interest cost	Other Income (Loss), Net	1		1		2		2
Expected return on plan assets	Other Income (Loss), Net	(2)		(2)		(3)		(3)

Amortization of net loss	Other Income (Loss), Net	—		—		—		—
Settlement loss	Other Income (Loss), Net	1		—		1		—
Net periodic benefit cost		$	—	$	1	$	—	$	3

The Company recognized a $1 million non-cash settlement loss related to $4 million of lump sum payments from the pension plan in the first half of 2021. As a result of settlement accounting requirements, the Company recorded a $3 million reduction to its net pension liability in the second quarter of 2021, with a corresponding reduction to accumulated other comprehensive loss.

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million and less than $1 million for the three months ended June 30, 2021 and 2020, respectively, and $1 million and $1 million for the six months ended June 30, 2021 and 2020, respectively.

As of June 30, 2021, the Company has contributed $9 million to the pension and other postretirement benefit plans and expects to contribute an additional $3 million to its pension plan during the remainder of 2021. The Company recognized liabilities of $21 million and $14 million related to its pension and other postretirement benefits, respectively, as of June 30, 2021, compared to liabilities of $33 million and $13 million as of December 31, 2020, respectively.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the Non-Qualified Plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are included in treasury stock and totaled 2,035 shares and 3,632 shares at June 30, 2021 and December 31, 2020, respectively.

(15) LONG-TERM INCENTIVE COMPENSATION

The Company’s long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but subject to meeting annual performance thresholds.

Stock-Based Compensation

The Company’s stock-based compensation is classified as either equity awards or liability awards in accordance with GAAP. The fair value of an equity-classified award is determined at the grant date and is amortized to general and administrative expense on a straight-line basis over the vesting period of the award. A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in property and equipment. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense and capitalized expense over the vesting period of the award. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire seven years from the date of grant. The Company issues shares of restricted stock, restricted stock units or

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performance cash awards to employees and directors which generally vest over four years. Restricted stock, restricted stock units, performance cash awards and stock options granted to participants under the 2013 Incentive Plan, as amended and restated, immediately vest upon death, disability or retirement (subject to a minimum of three years of service). The Company issues performance unit awards to employees which historically have vested at or over three years.

In February of 2021 and 2020, the Company notified employees of workforce reduction plans as a result of strategic realignments of the Company’s organizational structure. These reductions were substantially complete by the end of the first quarter of each respective year. Affected employees were offered a severance package which, if applicable, included the current value of unvested long-term incentive awards that were forfeited.

The Company recognized the following amounts in total employee stock-based compensation costs for the three and six months ended June 30, 2021 and 2020:


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Stock-based compensation cost – expensed	$	9	$	6	$	22	$	6
Stock-based compensation cost – capitalized	5		1		10		1

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three and six months ended June 30, 2021 and 2020:


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Equity-classified awards – expensed	$	2	$	1	$	2	$	2
Equity-classified awards – capitalized	—		—		—		—

As of June 30, 2021, there was less than $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified stock option grants, equity-classified restricted stock grants and equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 1.4 years.

Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the six months ended June 30, 2021 and provides information for options outstanding and options exercisable as of June 30, 2021:


	Number of Options	Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2020	3,850	$	13.39
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(151)	$	32.21
Outstanding at June 30, 2021	3,699	$	12.63
Exercisable at June 30, 2021	3,699	$	12.63

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Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the six months ended June 30, 2021 and provides information for unvested shares as of June 30, 2021:


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2020	697	$	5.97
Granted	307	$	5.30
Vested	(855)	$	5.83
Forfeited	—	$	8.59
Unvested shares at June 30, 2021	149	$	5.38

Equity-Classified Restricted Stock Units

As a result of the Montage Merger, certain employees became employees of Southwestern and retained their original equity awards. The following table summarizes equity-classified performance unit activity for the six months ended June 30, 2021 and provides information for unvested units as of June 30, 2021.


	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2020	134	$	3.05
Granted	—	$	—
Vested	(87)	$	3.05
Forfeited	—	$	—
Unvested units at June 30, 2021	47	$	3.05

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three and six months ended June 30, 2021:


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Liability-classified stock-based compensation cost – expensed	$	7	$	5	$	20	$	4
Liability-classified stock-based compensation cost – capitalized	5		1		10		1

Liability-Classified Restricted Stock Units

In the first quarter of each year beginning with 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The awards granted in 2021 vest over a period of three years. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award. As of June 30, 2021, there was $25 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of 1.8 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2020	11,613	$	2.67
Granted	1,486	$	4.23
Vested	(4,522)	$	3.40
Forfeited	(489)	$	4.37
Unvested units at June 30, 2021	8,088	$	4.90

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Liability-Classified Performance Units

In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include performance conditions based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. In the first half of 2021, two types of performance unit awards were granted. One type of award includes a performance condition based on return on capital employed and a performance condition based on a reinvestment rate, and the second type of award includes one market condition based on relative TSR. The fair values of the market conditions are calculated by Monte Carlo models on a quarterly basis. As of June 30, 2021, there was $25 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 1.9 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2020	8,699	$	2.57
Granted	3,580	$	4.14
Vested	(2,020)	$	4.05
Forfeited	(622)	$	2.98
Unvested units at June 30, 2021	9,637	$	3.38

Cash-Based Compensation

Performance Cash Awards

In 2021 and 2020, the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. The value of each unit of the award equals one dollar. The Company recognizes the cost of these awards as general and administrative expense and capitalized expense over the vesting period of the awards. The performance cash awards granted in 2021 and 2020 include a performance condition determined annually by the Company. For both years, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. As of June 30, 2021, there was $27 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.3 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.


	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2020	18,353	$	1.00
Granted	18,546	$	1.00
Vested	(4,373)	$	1.00
Forfeited	(2,708)	$	1.00
Unvested units at June 30, 2021	29,818	$	1.00

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(16) SEGMENT INFORMATION

The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids. The Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2020 Annual Report. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and other income (loss). The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.


	E&P			Marketing		Other		Total

Three months ended June 30, 2021	(in millions)
Revenues from external customers	$	718		$	332	$	—	$	1,050
Intersegment revenues	(14)			651		—		637
Depreciation, depletion and amortization expense	97			3		—		100

Operating income	286		(1)	7		—		293
Interest expense (2)	30			—		—		30
Gain (loss) on derivatives	(872)			—		1		(871)

Other loss, net	(1)			—		—		(1)

Assets	4,870		(3)	408		116		5,394
Capital investments (4)	259			—		—		259

Three months ended June 30, 2020
Revenues from external customers	$	223		$	187	$	—	$	410
Intersegment revenues	(12)			202		—		190
Depreciation, depletion and amortization expense	81			3		—		84
Impairments	655			—		—		655
Operating loss	(748)		(1)	(8)		—		(756)
Interest expense (2)	22			—		—		22
Loss on derivatives	(109)			—		—		(109)
Gain on early extinguishment of debt	—			—		7		7
Other income (loss), net	(1)			—		1		—

Assets	4,185		(3)	208		162		4,555
Capital investments (4)	245			—		—		245

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	E&P			Marketing		Other		Total

Six months ended June 30, 2021	(in millions)
Revenues from external customers	$	1,437		$	685	$	—	$	2,122
Intersegment revenues	(28)			1,295		—		1,267
Depreciation, depletion and amortization expense	191			5		—		196

Operating income	581		(1)	13		—		594
Interest expense (2)	61			—		—		61
Gain (loss) on derivatives	(1,063)			—		1		(1,062)



Assets	4,870		(3)	408		116		5,394
Capital investments (4)	525			—		—		525

Six months ended June 30, 2020
Revenues from external customers	$	576		$	426	$	—	$	1,002
Intersegment revenues	(21)			511		—		490
Depreciation, depletion and amortization expense	192			5		—		197
Impairments	2,134			—		—		2,134
Operating loss	(2,234)		(1)	(12)		—		(2,246)
Interest expense (2)	41			—		—		41
Gain on derivatives	230			—		—		230
Gain on early extinguishment of debt	—			—		35		35
Other income, net	—			—		1		1
Benefit from income taxes (2)	406			—		—		406
Assets	4,185		(3)	208		162		4,555
Capital investments (4)	482			—		—		482

(1)Operating income (loss) for the E&P segment includes $1 million and $2 million of restructuring charges for the three months ended June 30, 2021 and 2020, respectively, and $7 million and $12 million of restructuring charges for the six months ended June 30, 2021 and 2020, respectively. The E&P segment operating income (loss) also includes $3 million and $4 million of merger-related charges for the three and six months ended June 30, 2021, respectively.

(2)Interest expense and provision (benefit) for income taxes by segment is an allocation of corporate amounts as they are incurred at the corporate level.

(3)E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties.

(4)Capital investments include a decrease of $9 million for the three months ended June 30, 2021, and increases of $29 million and $8 million for the six months ended June 30, 2021 and 2020, respectively, relating to the change in accrued expenditures between periods. There was no change in the capital accrual for the three months ended June 30, 2020.

The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments at June 30, 2021 and 2020:


	As of June 30,
(in millions)	2021		2020
Cash and cash equivalents	$	2	$	10
Accounts receivable	3		—
Income taxes receivable	—		31

Prepayments	15		7
Property, plant and equipment	14		21
Unamortized debt expense	11		10
Right-of-use lease assets	67		77
Non-qualified retirement plan	4		5
Other	—		1
	$	116	$	162

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(17) NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented in this Report

In August 2018, the Financial Accounting Standards Board (the “FASB”) issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 amends, adds and removes certain disclosure requirements under FASB ASC Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020 and was adopted on January 1, 2021. Adoption of ASU 2018-14 will result in certain disclosure changes within the Company's footnote disclosures. The adoption of ASU 2018-14 did not have a material impact on the Company's consolidated financial statements.

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. ASU 2019-12 eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard became effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company adopted the new standard on January 1, 2021 on a prospective basis, which did not have a material impact on its consolidated financial statements.

New Accounting Standards Not Yet Adopted in this Report

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new ASC Topic, ASC 848. The purpose of ASC 848 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration away from Interbank Offered Rates, such as LIBOR, which is expected to be phased out at the end of calendar year 2021, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other transactions that reference a benchmark reference rate expected to be discontinued because of reference rate reform. ASC 848 contains optional expedients and exceptions for applying U.S. GAAP to transactions affected by this reform. The amendments in ASU 2020-04 are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is currently assessing the impact of adopting this new guidance.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following updates information as to Southwestern Energy Company’s financial condition provided in our 2020 Annual Report and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2021 and 2020. For definitions of commonly used natural gas and oil terms used in this Quarterly Report, please refer to the “Glossary of Certain Industry Terms” provided in our 2020 Annual Report.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in “Cautionary Statement About Forward-Looking Statements” in the forepart of this Quarterly Report and in Item 1A, “Risk Factors” in Part I and elsewhere in our 2020 Annual Report. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Background

Southwestern Energy Company (including its subsidiaries, collectively, “we,” “our,” “us,” “the Company” or “Southwestern”) is an independent energy company engaged in natural gas, oil and NGLs exploration, development and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our marketing business, which we call “Marketing.” We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States.

E&P. Our primary business is the exploration for and production of natural gas, oil and NGLs, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania, Ohio and West Virginia. Our operations in northeast Pennsylvania, which we refer to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Our operations in West Virginia, Ohio and southwest Pennsylvania, which we refer to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, our properties in Pennsylvania, Ohio and West Virginia

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are herein referred to as “Appalachia.” We also have drilling rigs located in Appalachia, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration.

On June 1, 2021, we entered into an Agreement and Plan of Merger with Ikon Acquisition Company, LLC (“Ikon”), Indigo Natural Resources LLC (“Indigo”) and Ibis Unitholder Representative LLC (the “Indigo Merger Agreement”). Pursuant to the terms of the Indigo Merger Agreement, Indigo will merge with and into Ikon, a subsidiary of Southwestern, with Indigo surviving the merger (the “Indigo Merger”). The outstanding equity interests in Indigo will be cancelled and converted into the right to receive (i) $400 million in cash consideration, and (ii) 339,270,568 shares of Southwestern common stock, in each case, subject to adjustment as provided in the Indigo Merger Agreement. Additionally, we will assume $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). The shares of Southwestern common stock had an aggregate dollar value equal to $1.6 billion, based on the volume weighted average sales price as traded on the New York Stock Exchange of such shares calculated for the thirty trading day period ending on May 28, 2021.

Following the closing of the Indigo Merger, Southwestern’s existing shareholders and Indigo’s existing equity holders will own approximately 67% and 33%, respectively, of the outstanding shares of the combined company. The transaction is expected to close in the second half of 2021, subject to customary closing conditions, including the approval of Southwestern’s shareholders. The Indigo Merger is expected to diversify our operations by expanding our portfolio into the Haynesville basin and give us additional exposure to the markets on the Gulf Coast.

On November 13, 2020, we closed on our Agreement and Plan of Merger with Montage Resources Corporation (“Montage”) pursuant to which Montage merged with and into Southwestern, with Southwestern continuing as the surviving company (the “Montage Merger”). The Montage Merger expanded our footprint in Appalachia by supplementing our Northeast Appalachia and Southwest Appalachia operations and by expanding our operations into Ohio. See Note 2 to the consolidated financial statements of this Quarterly Report for more information on the Montage Merger.

Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in our E&P operations.

Recent Financial and Operating Results

Significant second quarter 2021 operating and financial results include:

Total Company

•Net loss of $609 million, or ($0.90) per diluted share, improved compared to net loss of $880 million, or ($1.63) per diluted share, for the same period in 2020. The improvement was primarily due to a $1,049 million increase in operating income partially offset by a $762 million reduction resulting from the impact of improved forward pricing on our derivatives position, $543 million of which was unrealized. Excluding the change in derivatives position and the impact of the $650 million impairment recorded in the second quarter of 2020, net income increased $383 million in the second quarter of 2021, compared to the same period in 2020, as a $399 million improvement in operating income was partially offset by an $8 million increase in interest expense and a $7 million gain on the early extinguishment of debt recorded in the second quarter of 2020.

•Operating income of $293 million increased compared to operating loss of $756 million for the same period in 2020 on a consolidated basis. Operating loss in the second quarter of 2020 included a $650 million non-cash full cost ceiling test impairment. Excluding the non-cash impairment, operating income improved $399 million, compared to the same period in 2020, as a $640 million increase in operating revenues more than offset a $241 million increase in operating costs, associated with increased production, and expenses.

•Net cash provided by operating activities of $270 million increased 187% from $94 million for the same period in 2020 as the effects of improved commodity pricing and higher production were only partially offset by a decrease in settled derivatives combined with an increase in operating expenses associated with higher liquids production.

•Total capital investment of $259 million increased 6% from $245 million for the same period in 2020.

E&P

•E&P segment operating income of $286 million increased from an operating loss of $748 million for the same period in 2020, primarily related to the non-cash full cost ceiling test impairment of $650 million in the second quarter of 2020. Excluding the non-cash impairment, E&P operating income increased $384 million, compared to the same period in 2020, as a $493 million increase in E&P operating revenues resulting from a $1.50 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and a 75 Bcfe increase in production volumes was only partially offset by a $109 million increase in E&P operating costs and expenses.

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•Total net production of 276 Bcfe, which was comprised of 79% natural gas and 21% oil and NGLs, increased 37% from 201 Bcfe in the same period in 2020, primarily due to a 39% increase in our natural gas production, 23% of which was associated with natural gas production from our Montage Merger-related properties acquired in November 2020.

•Excluding the effect of derivatives, our realized natural gas price of $1.92 per Mcf increased 96%, our realized oil price of $57.50 per barrel increased 266% and our realized NGL price of $23.24 per barrel increased 261%, as compared to the same period in 2020. Excluding the effect of derivatives, our total weighted average realized price of $2.55 per Mcfe increased 143% from the same period in 2020.

•E&P segment invested $259 million in capital; drilling 23 wells, completing 19 wells and placing 31 wells to sales.

Outlook

Our primary focus in 2021 is to strengthen the balance sheet and maximize value with disciplined investment across our portfolio. We expect to accomplish this by:

•Maximizing Our Margins. We will continue to concentrate our efforts on our highest return investment opportunities and look for ways to further reduce our cost structure and build on the synergies from our Montage Merger and anticipated Indigo Merger while further developing our knowledge of our asset base.

•Generating Free Cash Flow. We expect to generate cash flow from operations, net of changes in working capital, in excess of our expected capital investments, which are designed to keep our daily production at levels consistent with the end of last year. Additionally, we expect to maintain a hedging program that ensures a certain level of cash flow.

•Reducing Our Debt. We intend to utilize free cash flow generated in 2021 to pay down our debt, further strengthen our balance sheet and progress towards our lower leverage targets.

•Building Scale. We will continue to seek opportunities to leverage our operational expertise of integrating and developing large-scale assets to expand our portfolio, create economies of scale and increase optionality in our operations and our capital investment program.

We believe that we and our industry will continue to face challenges due to the uncertainty of natural gas, oil and NGL prices in the United States, changes in laws, regulations and investor sentiment, and other key factors described in Item 1A, “Risk Factors” in Part I and elsewhere in our 2020 Annual Report.

COVID-19

During the first half of 2021, we did not experience any material impact to our ability to operate or market our production due to the direct or indirect impacts of the COVID-19 pandemic. We continue to monitor the impact of COVID-19 on all aspects of our business. The COVID-19 outbreak resulted in state and local governments implementing measures with various levels of stringency to help control the spread of the virus. The U.S. Department of Homeland Security classifies individuals engaged in and supporting exploration for and production of natural gas, oil and NGLs as “essential critical infrastructure workforce,” and to date, state and local governments have followed this guidance and exempted these activities from business closures. Should this situation change, our access to supplies or workers to drill, complete and operate wells could be materially and adversely affected.

Ensuring the health and welfare of our employees, and all who visit our sites, is our top priority, and we are following all U.S. Centers for Disease Control and Prevention and state and local health department guidelines. Further, we implemented infection control measures at all our sites and put in place travel and in-person meeting restrictions and other physical distancing measures. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the effectiveness of the vaccines and the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. We will continually monitor our 2021 capital investment program to take into account these changed conditions and proactively adjust our activities and plans. Therefore, while this continued matter could potentially disrupt our operations, the degree of the potentially adverse financial impact cannot be reasonably estimated at this time.

RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Restructuring charges, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and income taxes are discussed on a consolidated basis.

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E&P


	For the three months ended June 30,						For the six months ended June 30,
(in millions)	2021			2020			2021			2020
Revenues	$	704		$	211		$	1,409		$	555
Operating costs and expenses	418		(1)	959		(2)	828		(1)	2,789		(2)
Operating income (loss)	$	286		$	(748)		$	581		$	(2,234)

Gain (loss) on derivatives, settled	$	(99)		$	120		$	(121)		$	213

(1)Includes $1 million and $7 million in restructuring charges for the three and six months ended June 30, 2021, respectively and $3 million and $4 million in merger related expenses for the three and six months ended June 30, 2021, respectively.

(2)Includes $650 million and $2,129 million related to non-cash full cost ceiling test impairments for the three and six months ended June 30, 2020, respectively, $2 million and $12 million in restructuring charges for the three and six months ended June 30, 2020, respectively, and $5 million related to the non-cash impairment of other non-core assets for the three and six months ended June 30, 2020.

Operating Income (Loss)

•E&P segment operating income increased $1,034 million for the three months ended June 30, 2021, compared to the same period in 2020. The operating loss for the second quarter of 2020 included a $650 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $384 million, compared to the same period in 2020, as a $493 million increase in E&P operating revenues resulting from a 143% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 37% increase in production volumes was only partially offset by a $109 million increase in E&P operating costs and expenses.

•Operating income for the E&P segment increased $2,815 million for the six months ended June 30, 2021 compared to the same period in 2020. The operating loss for the six months ended June 30, 2020 included a $2,129 million non-cash full cost ceiling test impairment. Excluding the effect of the impairment, operating income improved $686 million, compared to the same period in 2020, as a $854 million increase in E&P operating revenues resulting from a 88% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 36% increase in production volumes was only partially offset by a $168 million increase in E&P operating costs and expenses.

Revenues

The following illustrates the effects on sales revenues associated with changes in commodity prices and production volumes:


	Three months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2020 sales revenues	$	155		$	16		$	40		$	211
Changes associated with prices	206			77			128			411
Changes associated with production volumes	60			12			10			82
2021 sales revenues	$	421		$	105		$	178		$	704
Increase from 2020	172		%	556		%	345		%	234		%


	Six months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2020 sales revenues (1)	$	394		$	68		$	90		$	552
Changes associated with prices	328			89			239			656
Changes associated with production volumes	150			28			22			200
2021 sales revenues (2)	$	872		$	185		$	351		$	1,408
Increase from 2020	121		%	172		%	290		%	155		%

(1)Excludes $3 million in other operating revenues for the six months ended June 30, 2020 primarily related to gains on purchaser imbalances associated with certain NGLs.

(2)Excludes $1 million in other operating revenues for the six months ended June 30, 2021 primarily related to gains on purchaser imbalances associated with certain NGLs.

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Production Volumes


	For the three months ended June 30,				Increase/(Decrease)	For the six months ended June 30,				Increase/(Decrease)
Production volumes:	2021		2020			2021		2020
Natural Gas (Bcf)
Northeast Appalachia	123		113		9%	241		227		6%
Southwest Appalachia	96		45		113%	192		87		121%

Total	219		158		39%	433		314		38%

Oil (MBbls)
Southwest Appalachia	1,826		1,079		69%	3,484		2,474		41%
Other	5		4		25%	9		8		13%
Total	1,831		1,083		69%	3,493		2,482		41%

NGL (MBbls)
Southwest Appalachia	7,665		6,110		25%	15,242		12,237		25%
Other	1		1		—%	2		2		—%
Total	7,666		6,111		25%	15,244		12,239		25%

Production volumes by area: (Bcfe)
Northeast Appalachia	123		113		9%	241		227		6%
Southwest Appalachia	153		88		74%	304		175		74%

Total (1)	276		201		37%	545		402		36%

Production percentage:
Natural gas	79	%	79	%		79	%	78	%
Oil	4	%	3	%		4	%	4	%
NGL	17	%	18	%		17	%	18	%

(1)Approximately 242 Bcfe and 200 Bcfe for the three months ended June 30, 2021 and 2020, respectively, and 455 Bcfe and 401 Bcfe for the six months ended June 30, 2021 and 2020, respectively, were produced from the Marcellus Shale formation. Approximately 34 Bcfe and 90 Bcfe for the three and six months ended June 30, 2021 were produced from the Utica formation.

•E&P production volumes increased by 75 Bcfe for the three months ended June 30, 2021, compared to the same period in 2020, primarily due to incremental production volumes of 44 Bcfe associated with our recently acquired Montage properties, all of which is reflected in Southwest Appalachia.

•E&P production volumes increased by 143 Bcfe for the six months ended June 30, 2021, compared to the same period in 2020, primarily due to incremental production volumes of 92 Bcfe associated with our recently acquired Montage properties, of which 91 Bcfe is reflected in Southwest Appalachia and 1 Bcfe is reflected in Northeast Appalachia.

•Oil and NGL production increased 69% and 25%, respectively, for the three months ended June 30, 2021, compared to the same period in 2020. Production volumes associated with the recently acquired Montage properties were 299 MBbls and 870 MBbls for oil and NGLs, respectively, for the three months ended June 30, 2021.

•Oil and NGL production increased 41% and 25%, respectively, for the six months ended June 30, 2021, compared to the same period in 2020. Production volumes associated with the recently acquired Montage properties were 640 MBbls and 1,804 MBbls for oil and NGLs, respectively, for the six months ended June 30, 2021.

Commodity Prices

The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events such as the response to the COVID-19 pandemic, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.

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	For the three months ended June 30,						Increase/(Decrease)	For the six months ended June 30,						Increase/(Decrease)
	2021			2020				2021			2020
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	2.83		$	1.72		65%	$	2.76		$	1.83		51%
Discount to NYMEX (2)	(0.91)			(0.74)			23%	(0.74)			(0.57)			30%
Average realized gas price, excluding derivatives ($/Mcf)	$	1.92		$	0.98		96%	$	2.02		$	1.26		60%
Gain (loss) on settled financial basis derivatives ($/Mcf)	0.03			(0.05)				0.11			0.03
Gain (loss) on settled commodity derivatives ($/Mcf)	(0.06)			0.57				(0.02)			0.43
Average realized gas price, including derivatives ($/Mcf)	$	1.89		$	1.50		26%	$	2.11		$	1.72		23%

Oil Price:
WTI oil price ($/Bbl) (3)	$	66.07		$	27.85		137%	$	61.96		$	37.01		67%
Discount to WTI	(8.57)			(12.16)			(30)%	(8.92)			(9.46)			(6)%
Average oil price, excluding derivatives ($/Bbl)	$	57.50		$	15.69		266%	$	53.04		$	27.55		93%
Gain (loss) on settled derivatives ($/Bbl)	(19.13)			25.95				(15.34)			16.53
Average oil price, including derivatives ($/Bbl)	$	38.37		$	41.64		(8)%	$	37.70		$	44.08		(14)%

NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	23.24		$	6.43		261%	$	23.05		$	7.29		216%
Gain (loss) on settled derivatives ($/Bbl)	(7.37)			1.79				(7.06)			2.21
Average realized NGL price, including derivatives ($/Bbl)	$	15.87		$	8.22		93%	$	15.99		$	9.50		68%
Percentage of WTI, excluding derivatives	35		%	23		%		37		%	20		%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	2.55		$	1.05		143%	$	2.58		$	1.37		88%
Including derivatives ($/Mcfe)	$	2.20		$	1.65		33%	$	2.36		$	1.90		24%

(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.

We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials and transportation and fuel charges.

We regularly enter into various derivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” and Note 8 to the consolidated financial statements, included in this Quarterly Report.

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The table below presents the amount of our future natural gas production in which the basis is protected as of June 30, 2021:


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas
2021	166	$	(0.47)
2022	261	(0.40)
2023	163	(0.53)
2024	40	(0.70)
2025	9	(0.64)
Total	639

Physical NYMEX Sales Arrangements – Natural Gas
2021	132	$	(0.40)
2022	129	(0.36)
2023	63	(0.36)
2024	27	(0.49)
2025	12	(0.50)

Total	363

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of June 30, 2021:


	Remaining 2021	Full Year 2022	Full Year 2023
Natural gas (Bcf)	396	726	272
Oil (MBbls)	2,983	4,583	2,114
Ethane (MBbls)	3,578	2,497	—
Propane (MBbls)	4,261	4,397	—
Normal Butane (MBbls)	1,245	1,295	—
Natural Gasoline (MBbls)	1,281	1,201	—
Total financial protection on future production (Bcfe)	476	810	285

We refer you to Note 8 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

Operating Costs and Expenses


	For the three months ended June 30,				Increase/(Decrease)	For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2021		2020			2021		2020
Lease operating expenses (1)	$	260	$	182	43%	$	510	$	376	36%
General & administrative expenses	30		29		3%	65		52		25%
Merger related expenses	3		—		100%	4		—		100%
Restructuring charges	1		2		(50)%	7		12		(42)%
Taxes, other than income taxes	27		10		170%	51		23		122%
Full cost pool amortization	94		77		22%	184		183		1%
Non-full cost pool DD&A	3		4		(25)%	7		9		(22)%
Impairments	—		655		(100)%	—		2,134		(100)%
Total operating costs	$	418	$	959	(56)%	$	828	$	2,789	(70)%


	For the three months ended June 30,						Increase/	For the six months ended June 30,						Increase/
Average unit costs per Mcfe:	2021			2020			(Decrease)	2021			2020			(Decrease)
Lease operating expenses (1)	$	0.94		$	0.91		3%	$	0.94		$	0.94		—%
General & administrative expenses	$	0.11	(2)	$	0.14	(3)	(21)%	$	0.12	(2)	$	0.13	(3)	(8)%
Taxes, other than income taxes	$	0.10		$	0.05		100%	$	0.09		$	0.06		50%
Full cost pool amortization	$	0.34		$	0.38		(11)%	$	0.34		$	0.46		(26)%

(1)Includes post-production costs such as gathering, processing, fractionation and compression.

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(2)Excludes $3 million and $4 million in merger related expenses for the three and six months ended June 30, 2021, respectively, and $1 million and $7 million in restructuring charges for the three and six months ended June 30, 2021, respectively.

(3)Excludes $2 million and $12 million in restructuring charges for the three and six months ended June 30, 2020, respectively.

Lease Operating Expenses

•Lease operating expenses per Mcfe increased $0.03 per Mcfe for the three months ended June 30, 2021, compared to the same period in 2020, primarily due to increased liquids production, which includes processing fees, and an increase in water costs.

•Lease operating expenses per Mcfe remained approximately the same for the six months ended June 30, 2021, compared to the same period in 2020, as a 36% increase in production volumes, primarily associated with the Montage Merger, offset a $134 million increase in lease operating expenses.

General and Administrative Expenses

•General and administrative expenses increased $1 million and $13 million for the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020, as a result of the increase in our share price and related mark-to-market impact on the value of our share-based awards, which are accounted for as liability awards.

Restructuring Charges

•In February 2021, employees were notified of a workforce reduction plan as part of an ongoing strategic effort to reposition our portfolio, optimize operational performance and improve margins. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. We recognized restructuring expense of $1 million and $7 million for the three and six months ended months ended June 30, 2021, respectively, related to cash severance expenses, including payroll taxes.

•In February 2020, employees were notified of a workforce reduction plan as a result of a strategic realignment of our organizational structure. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. We recognized restructuring expense of $2 million and $12 million for the three and six months ended June 30, 2020, respectively, related to cash severance expenses, including payroll taxes.

See Note 3 of the consolidated financial statements included in this Quarterly Report for additional details about our restructuring charges.

Taxes, Other than Income Taxes

•On a per Mcfe basis, taxes, other than income taxes, may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices. Taxes, other than income taxes, per Mcfe increased $0.05 and $0.03 for the three and six months ended June 30, 2021, respectively, compared to the same period in 2020, primarily due to the impact of higher commodity pricing on our severance taxes.

Full Cost Pool Amortization

•Our full cost pool amortization rate decreased $0.04 and $0.12 per Mcfe for the three and six months ended June 30, 2021, respectively, as compared to the same period in 2020. The average amortization rate decreased primarily as a result of the impact of $2,825 million in non-cash full cost ceiling test impairments recorded in 2020.

•No impairment expense was recorded for the six months ended June 30, 2021 in relation to our recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. In the fourth quarter of 2020, pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Montage Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Montage Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021, as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Montage Merger was based on forward natural gas and oil pricing existing at the date of the Montage Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger have an unamortized cost at June 30, 2021 of

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$1,130 million. Due to the improvement in commodity prices in the first half of 2021, we would not have recorded any impairment charge for the six months ended June 30, 2021 had we included our recently acquired Montage natural gas and oil properties.

•The amortization rate is impacted by the timing and amount of reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from non-cash full cost ceiling test impairments, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserve changes.

•Unevaluated costs excluded from amortization were $1,485 million and $1,472 million at June 30, 2021 and at December 31, 2020, respectively. The unevaluated costs excluded from amortization increased slightly as the impact of $194 million of unevaluated capital invested during the period was only partially offset by the evaluation of previously unevaluated properties totaling $181 million.

Impairments

•During the three and six months ended June 30, 2020, we recognized non-cash full cost ceiling test impairments of $650 million and $2,129 million, respectively, primarily due to decreased commodity pricing over the prior twelve months. Additionally, for the three and six months ended June 30, 2020, we recognized a $5 million impairment related to other non-core assets. There were no impairments in the first half of 2021.

Marketing


	For the three months ended June 30,						Increase/ (Decrease)	For the six months ended June 30,						Increase/ (Decrease)
(in millions except volumes and percentages)	2021			2020				2021			2020
Marketing revenues	$	983		$	389		153%	$	1,979		$	937		111%
Other operating revenues	—			—			—%	1			—			100%
Marketing purchases	969			391			148%	1,955			938			108%
Operating costs and expenses	7			6			17%	12			11			9%


Operating income (loss)	$	7		$	(8)		188%	$	13		$	(12)		208%

Volumes marketed (Bcfe)	343			265			29%	688			528			30%

Percent natural gas production marketed from affiliated E&P operations	97		%	87		%		95		%	87		%
Percent oil and NGL production marketed from affiliated E&P operations	83		%	83		%		81		%	80		%

Operating Income

•Operating income for our Marketing segment increased $15 million for the three months ended June 30, 2021, compared to the same period in 2020, primarily due to a $16 million increase in the marketing margin.

•Marketing operating income increased $25 million for the six months ended June 30, 2021, compared to the same period in 2020, primarily due to a $25 million increase in the marketing margin and a $1 million increase in natural gas storage gains recorded in the first half of 2021.

•The margin generated from marketing activities was $14 million and ($2) million for the three months ended June 30, 2021 and 2020, respectively, and $24 million and ($1) million for the six months ended June 30, 2021 and 2020, respectively. The marketing margin increased in 2021, compared to the same periods in 2020, primarily due to increased volumes marketed and a corresponding reduction in third-party purchases and sales used to optimize the transportation portfolio due to increased affiliated volumes available for marketing.

Marketing margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities, related cost of transportation and the ultimate disposition of those commodities. Increases and decreases in marketing revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in purchase expenses. Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.

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Revenues

•Revenues from our marketing activities increased $594 million for the three months ended June 30, 2021 compared to the same period in 2020, as a 95% increase in the price received for volumes marketed and a 78 Bcfe increase in volumes marketed.

•For the six months ended June 30, 2021, revenues from our marketing activities increased $1,042 million compared to the same period in 2020, primarily due to a 62% increase in the price received for volumes marketed and a 30% increase in volumes marketed.

Operating Costs and Expenses

•Operating costs and expenses for the marketing segment increased $1 million and $1 million for the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020, as a result of the increase in our share price and related mark-to-market impact on the value of our share-based awards, which are accounted for as liability awards.

Consolidated

Interest Expense


	For the three months ended June 30,				Increase/(Decrease)	For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2021		2020			2021		2020
Gross interest expense:
Senior notes	$	43	$	36	19%	$	87	$	73	19%
Credit arrangements	5		4		25%	11		7		57%
Amortization of debt costs	3		3		—%	6		5		20%
Total gross interest expense	51		43		19%	104		85		22%
Less: capitalization	(21)		(21)		—%	(43)		(44)		(2)%
Net interest expense	$	30	$	22	36%	$	61	$	41	49%

•Interest expense related to our senior notes increased for the three and six months ended June 30, 2021, compared to the same period in 2020, as the interest savings from the repurchase of $107 million of our outstanding senior notes during the first quarter of 2020 was more than offset by the interest associated with the August 2020 public offering of $350 million aggregate principal amount of our 8.375% Senior Notes due 2028.

•Capitalized interest remained approximately the same for the three months ended June 30, 2021 and decreased for the six months ended June 30, 2021, both as compared to the same periods in 2020, due to the evaluation of natural gas and oil properties over the past twelve months.

•Capitalized interest decreased as a percentage of gross interest expense for the three and six months ended June 30, 2021, compared to the same period in 2020, primarily related to a smaller percentage change in our unevaluated natural gas and oil properties balance as compared to the larger percentage increase in our gross interest expense over the same period.

Gain (Loss) on Derivatives


	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
Gain (loss) on unsettled derivatives	$	(772)	$	(229)	$	(941)	$	17
Gain (loss) on settled derivatives	(99)		120		(121)		213
Gain (loss) on derivatives	$	(871)	$	(109)	$	(1,062)	$	230

We refer you to Note 8 to the consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.

Gain/Loss on Early Extinguishment of Debt

For the three and six months ended June 30, 2020, we recorded a gain on early extinguishment of debt of $7 million and $35 million, respectively, as a result of our repurchase of $27 million in aggregate principal amount of our outstanding senior notes for $20 million in the second quarter of 2020 and $107 million in aggregate principal amount of our outstanding senior

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notes for $72 million in the first half of 2020. See Note 11 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes


	For the three months ended June 30,						For the six months ended June 30,
(in millions except percentages)	2021			2020			2021			2020
Income tax expense	$	—		$	—		$	—		$	406
Effective tax rate	0		%	0		%	0		%	(20)		%

•As of the first quarter of 2019, we had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, we concluded that it was more likely than not that the deferred tax asset would be realized and released substantially all of the valuation allowance. However, due to commodity price declines during 2020 and the write-down of the carrying value of our natural gas and oil properties, in addition to other negative evidence, we concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in our valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. We continue to have a full valuation allowance for the first half of 2021. We also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.

New Accounting Standards Implemented in this Report

Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have been implemented.

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have not yet been implemented.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on funds generated from our operations, our 2018 credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. In March 2021, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $2.0 billion. At June 30, 2021, we had approximately $1.2 billion of total available liquidity, which exceeds our currently modeled needs, and we remain committed to our strategy of capital discipline. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2018 credit facility and related covenant requirements.

On June 1, 2021, we entered into the Indigo Merger Agreement. Upon the close of the Indigo Merger, and pursuant to the terms of the Indigo Merger Agreement, the outstanding equity interests in Indigo will be cancelled and converted into the right to receive (i) $400 million in cash consideration, and (ii) approximately $1.6 billion in Southwestern common stock. Additionally, we will assume $700 million in aggregate principal amount of 5.375% Senior Notes due 2029 of Indigo (the “Indigo Notes”). We expect to fund the $400 million cash portion of the Indigo Merger consideration with borrowings on our credit facility. The transaction is expected to close in the second half of 2021, subject to customary closing conditions, including the approval of our shareholders. See Note 2 to the consolidated financial statements of this Quarterly Report for more information on the Indigo Merger.

Our cash flow from operating activities is highly dependent upon our ability to sell, and the sales prices that we receive for, our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. Although we are continually adding additional derivative positions for portions of our expected 2021, 2022 and 2023 production, there can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. See “Quantitative and Qualitative Disclosures about Market Risk” in Item 3 in Part I and Note 8 in the consolidated financial statements included in this Quarterly Report for further details.

Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit

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defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

Our short-term cash flows are also dependent on the timely collection of receivables from our customers and joint interest owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and joint interest owners could adversely impact our cash flows.

Due to these factors, we are unable to forecast with certainty our future level of cash flows from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Arrangements and Financing Activities

In April 2018, we entered into a new revolving credit facility (the “2018 credit facility”) with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in March 2021, the banks participating in our 2018 credit facility reaffirmed the elected borrowing base to be $2.0 billion, which also reflected our aggregate commitments. The borrowing base is subject to redetermination at least twice a year, in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivatives position, the level of capital investment and operating costs. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets. We may utilize the 2018 credit facility in the form of loans and letters of credit. As of June 30, 2021, we had $568 million borrowings outstanding on our revolving credit facility and $233 million in outstanding letters of credit. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

As of June 30, 2021, we were in compliance with all of the covenants contained in the credit agreement governing our revolving credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas and liquids. We refer you to Note 11 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2018 credit facility.

The credit status of the financial institutions participating in our revolving credit facility could adversely impact our ability to borrow funds under the revolving credit facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

Our exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and Southwestern. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (or “SOFR”).

Because of the focused work on refinancing and repayment of our debt during the last three years, only $207 million, or 8%, of our senior notes outstanding as of June 30, 2021 are scheduled to become due prior to 2025.

At July 27, 2021, we had a long-term issuer credit rating of Ba2 by Moody’s (rating and stable outlook affirmed on April 28, 2021), a long-term debt rating of BB- by S&P (rating placed on credit watch on June 2, 2021 for potential positive upgrade at the closing of the Indigo Merger) and a long-term issuer default rating of BB by Fitch Ratings (rating affirmed and outlook upgraded to stable on January 29, 2021). In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% in July 2020. The first coupon payment to the 2025 Notes bondholders at the higher interest rate was January 2021. Any reduction of the interest rate on the 2025 Notes as a result of a potential upgrade to the bond rating would be effective following the January 2022 coupon payment. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.

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Cash Flows


	For the six months ended June 30,
(in millions)	2021		2020
Net cash provided by operating activities	$	617	$	254
Net cash used in investing activities	(492)		(470)
Net cash provided by (used in) financing activities	(136)		221

Cash Flow from Operating Activities


	For the six months ended June 30,
(in millions)	2021		2020
Net cash provided by operating activities	$	617	$	254
Add back (subtract) changes in working capital	(2)		12
Net cash provided by operating activities, net of changes in working capital	$	615	$	266

•Net cash provided by operating activities increased 143%, or $363 million, for the six months ended June 30, 2021, compared to the same period in 2020, primarily due to a $656 million increase resulting from higher commodity prices, a $200 million increase associated with increased production, an $18 million increase in marketing margin and a $14 million increased impact of working capital. These increases were partially offset by a $334 million decrease in our settled derivatives, a $175 million increase in operating costs and expenses and a $20 million increase in interest expense.

•Net cash generated from operating activities, net of changes in working capital, provided 117% of our cash requirements for capital investments for the six months ended June 30, 2021, compared to providing 55% of our cash requirements for capital investments for the same period in 2020. We remain committed to our disciplined capital investment strategy.

Cash Flow from Investing Activities

•Total capital investments increased $43 million for the six months ended June 30, 2021, compared to the same period in 2020, due to a $37 million increase in direct E&P capital investments and a $6 million increase in capitalized interest and internal costs, as compared to the same period in 2020.


	For the six months ended June 30,
(in millions)	2021		2020
Additions to properties and equipment	$	493	$	472
Adjustments for capital investments
Changes in capital accruals	29		8
Other (1)	3		2
Total capital investment	$	525	$	482

(1)Includes capitalized non-cash stock-based compensation and costs to retire assets, which are classified as cash used in operating activities.

Capital Investment


	For the three months ended June 30,				Increase/(Decrease)	For the six months ended June 30,				Increase/(Decrease)
(in millions except percentages)	2021		2020			2021		2020
E&P capital investment	$	259	$	245	6%	$	525	$	482	9%
Other capital investment (1)	—		—		—%	—		—		—%
Total capital investment	$	259	$	245	6%	$	525	$	482	9%

(1)Other capital investment was immaterial for the three and six months ended June 30, 2021 and 2020.

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	For the three months ended June 30,				For the six months ended June 30,
(in millions)	2021		2020		2021		2020
E&P Capital Investments by Type:
Exploratory and development drilling, including workovers	$	204	$	197	$	419	$	387
Acquisition of properties	12		8		22		14

Water infrastructure	2		2		2		3
Other	3		5		7		9
Capitalized interest and expenses	38		33		75		69
Total E&P capital investments	$	259	$	245	$	525	$	482

E&P Capital Investments by Area:
Northeast Appalachia	$	85	$	115	$	165	$	201
Southwest Appalachia	169		123		352		269
Other E&P (1)	5		7		8		12
Total E&P capital investments	$	259	$	245	$	525	$	482


	For the three months ended June 30,		For the six months ended June 30,
	2021	2020	2021	2020
Gross Operated Well Count Summary:
Drilled	23	30	46	68
Completed	19	31	48	53
Wells to sales	31	31	48	43

Actual capital expenditure levels may vary significantly from period to period due to many factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the prices and availability of goods and services, and the extent to which properties are acquired or non-strategic assets are sold.

Cash Flow from Financing Activities

•For the six months ended June 30, 2021, we paid down $132 million on our revolving credit facility.

•In the first half of 2020, we had net borrowings of $302 million from our revolving credit facility. In addition, we repurchased $107 million principal amount of our outstanding senior notes for $72 million and recognized a $35 million gain on the extinguishment of debt.

We refer you to Note 11 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

We had negative working capital of $1,351 million at June 30, 2021, a $1,010 million decrease from December 31, 2020, as a $40 million increase in accounts receivable was more than offset by a $765 million reduction in the current mark-to-market value of our derivatives position related to improved forward pricing across all commodities, along with the reclassification of long-term debt to short-term debt of $207 million related to our 2022 senior notes, a $68 million increase in various payables and an $11 million decrease in cash and cash equivalents, as compared to December 31, 2020. We believe that our anticipated cash flows from operations, the remaining borrowing capacity on our credit facility and our existing cash and cash equivalents will be sufficient to meet our working capital and operational spending requirements, as well as our funding requirements associated with the Indigo Merger.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2021, our material off-balance sheet arrangements and transactions include operating service arrangements and $233 million in letters of credit outstanding against our 2018 credit facility. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” below for a summary of our operating leases.

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Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the firm transportation and gathering agreements discussed below, there have been no material changes to our contractual obligations from those disclosed in our 2020 Annual Report.

Contingent Liabilities and Commitments

As of June 30, 2021, we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaling approximately $8.3 billion, $369 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or additional construction efforts. This amount also included guarantee obligations of up to $895 million. As of June 30, 2021, future payments under non-cancelable firm transportation and gathering agreements are as follows:


	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years
Infrastructure currently in service	$	7,965	$	713	$	1,557	$	1,317	$	1,744	$	2,634
Pending regulatory approval and/or construction (1)	369		2		18		25		52		272
Total transportation charges	$	8,334	$	715	$	1,575	$	1,342	$	1,796	$	2,906

(1)Based on the estimated in-service dates as of June 30, 2021.

Substantially all of our employees who were employed prior to January 1, 2021 are covered by defined benefit and postretirement benefit plans. As part of ongoing effort to reduce costs, we elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. For the six months ended June 30, 2021, we have contributed $9 million to the pension and postretirement benefit plans, and we expect to contribute an additional $3 million to our pension plan during the remainder of 2021. We recognized liabilities of $35 million and $46 million as of June 30, 2021 and December 31, 2020, respectively, as a result of the underfunded status of our pension and other postretirement benefit plans. See Note 14 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on our results of operations or cash flows for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations or cash flows.

For further information, we refer you to “Litigation” and “Environmental Risk” in Note 12 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

Supplemental Guarantor Financial Information

As discussed in Note 11, in April 2018 the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of our senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 credit facility but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of our operating units that are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes.

The Company and the Guarantor Subsidiaries jointly and severally, and fully and unconditionally, guarantee the payment of the principal and premium, if any, and interest on the senior notes when due, whether at stated maturity of the senior notes,

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by acceleration, by call for redemption or otherwise, together with interest on the overdue principal, if any, and interest on any overdue interest, to the extent lawful, and all other obligations of the Company to the holders of the senior notes.

SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantor Subsidiaries are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as service costs and credit risk concentrations. We use fixed price swap agreements, options and basis swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our exposure to concentrations of credit risk consists primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas. At June 30, 2021, no purchaser accounted for greater than 10% of our revenues. For the year ended December 31, 2020, one purchaser accounted for 10% of our revenues. A default on this account could have a material impact on the Company, but we do not believe that there is a material risk of a default. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

As of June 30, 2021, we had approximately $2,471 million principal amount of outstanding senior notes with a weighted average interest rate of 7.02% and $568 million of borrowings under our revolving credit facility. At June 30, 2021, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of BB- by S&P and a long-term issuer default rating of BB by Fitch Ratings. In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on our 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On June 2, 2021 in conjunction with the announcement of the Indigo Merger, S&P placed our bond rating on credit watch for a potential positive upgrade. Interest savings on the 2025 Notes from any potential upgrade would be realized for coupon payments paid after January 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.


	Expected Maturity Date
($ in millions)	2022			2023			2024			2025			2026			Thereafter			Total
Fixed rate payments (1)	$	207		$	—		$	—		$	856		$	618		$	790		$	2,471
Weighted average interest rate	4.10		%	—		%	—		%	6.45		%	7.50		%	8.03		%	7.02		%

Variable rate payments (1)	$	—		$	—		$	568		$	—		$	—		$	—		$	568
Weighted average interest rate	—		%	—		%	2.10		%	—		%	—		%	—		%	2.10		%

(1)Excludes unamortized debt issuance costs and debt discounts.

Commodities Risk

We use fixed price swap agreements and options to protect sales of our production against the inherent risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps) and transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps).

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the

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production that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. The fair value of our derivative assets and liabilities includes a non-performance risk factor. We refer you to Note 8 and Note 10 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer (Interim), of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer (Interim), to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer (Interim), concluded that our disclosure controls and procedures were effective as of June 30, 2021 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to “Litigation” and “Environmental Risk” in Note 12 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s 2020 Annual Report, except as set forth below.

Risk Factors Relating to the Indigo Merger

There can be no assurances when or if the Indigo Merger will be completed.

Although SWN expects to complete the Indigo Merger by the end of the fourth quarter of 2021, there can be no assurances as to the exact timing of completion of the Indigo Merger or that the Indigo Merger will be completed at all. The completion of the Indigo Merger is subject to numerous conditions, including, among others:

•the absence of any law, order or injunction prohibiting the Indigo Merger;

•the expiration or earlier termination of the waiting period under the HSR Act;

•the accuracy of each party’s representations and warranties;

•each party’s compliance with its covenants and agreements contained in the Indigo Merger Agreement; and

•approval of the Stock Issuance Proposal.

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There can be no assurance that the conditions required to complete the Indigo Merger, some of which are beyond the control of SWN and Indigo, will be satisfied or waived on the anticipated schedule, or at all.

Additionally, the Indigo Merger Agreement also provides for certain termination rights for both SWN and Indigo, including if the Indigo Merger is not consummated on or before November 29, 2021. Upon termination of the Indigo Merger Agreement under certain circumstances, including (a) termination by Indigo in the event of a change of recommendation by the Board, or (b) if an alternative transaction is publicly proposed or publicly disclosed and not withdrawn prior to the Special Meeting and the Indigo Merger Agreement is terminated (i) by SWN or Indigo due to either the failure of SWN shareholders to approve the Stock Issuance Proposal or the failure of the Indigo Merger to close on or before November 29, 2021, or (ii) by Indigo due to a breach by SWN and, in any such case, within 12 months after such termination SWN enters into a definitive agreement with respect to, or otherwise consummates, an alternative transaction, SWN will be obligated to pay Indigo a fee of $81 million.

Obtaining required approvals and satisfying closing conditions may prevent or delay completion of the Indigo Merger.

The Indigo Merger is subject to a number of conditions to closing as specified in the Indigo Merger Agreement. These closing conditions include, among others, obtaining shareholder approval of the Stock Issuance Proposal, approval for listing on the NYSE of the shares of common stock issuable in accordance with the Indigo Merger Agreement, the absence of governmental restraints or prohibitions preventing the consummation of the Indigo Merger. The obligation of each of SWN and Indigo to consummate the Indigo Merger is also conditioned on, among other things, (i) the accuracy of the representations and warranties as set forth by the other party in the Indigo Merger Agreement, (ii) the performance by the other party, in all material respects, of its obligations under the Indigo Merger Agreement required to be performed at or prior to the effective time of the Indigo Merger and (iii) the delivery by the other party of a certificate of an authorized officer certifying that the required conditions have been satisfied. The required shareholder consents and approvals may not be obtained and the required conditions to closing may not be satisfied, and, if all required consents and approvals are obtained and the conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such consents and approvals. Any delay in completing the Indigo Merger could cause SWN and Indigo not to realize, or to be delayed in realizing, some or all of the benefits that SWN and Indigo expect to achieve if the Indigo Merger is successfully completed within its expected time frame.

The market price for shares of common stock following the completion of the Indigo Merger may be affected by factors different from, or in addition to, those that historically have affected or currently affect the market prices of shares of common stock.

SWN’s businesses differ in some regards from those of Indigo and, accordingly, the results of operations of SWN following completion of the Indigo Merger will be affected by some factors that are different from those currently or historically affecting the results of operations of SWN. The results of operations of SWN following completion of the Indigo Merger may also be affected by factors different from those that currently affect or have historically affected SWN. In addition, following completion of the Indigo Merger, SWN may seek to raise additional equity financing through one or more underwritten offerings, private placements and/or rights offerings, or issue stock in connection with acquisitions, which may result in downward pressure on the share price of the common stock.

SWN may be adversely affected by negative publicity related to the proposed Indigo Merger and in connection with other matters.

From time to time, political and public sentiment in connection with the proposed Indigo Merger and in connection with other matters could result in a significant amount of adverse press coverage and other adverse public statements affecting SWN. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceeding, can divert the time and effort of senior management from the management of SWN’s and Indigo’s respective businesses. Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of SWN and Indigo, on the morale and performance of their employees and on their relationships with their respective regulators. It may also have a negative impact on their ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on SWN’s and Indigo’s respective businesses, financial condition, results of operations and cash flows.

The Indigo Merger is subject to conditions, including certain conditions that may not be satisfied or completed on a timely basis or at all. Failure to complete the Indigo Merger could have material and adverse effects on SWN.

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Completion of the Indigo Merger is subject to a number of conditions, including, among other things, obtaining the approval of the Stock Issuance Proposal and the expiration of the applicable waiting period under the HSR Act. Such conditions, some of which are beyond SWN’s control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the completion of the Indigo Merger uncertain. In addition, the Indigo Merger Agreement contains certain termination rights for both SWN and Indigo, which if exercised, will also result in the Indigo Merger not being consummated. Furthermore, the governmental authorities from which the regulatory approvals are required may impose conditions on the completion of the Indigo Merger or require changes to the terms thereof. Such conditions or changes and the process of obtaining regulatory approvals could have the effect of delaying or impeding consummation of the transactions or of imposing additional costs or limitations on SWN or Indigo following completion of the Indigo Merger, any of which might have an adverse effect on SWN following completion of the Indigo Merger.

If the Indigo Merger is not completed, SWN’s ongoing business may be adversely affected and, without realizing any of the benefits of having completed the Indigo Merger, SWN will be subject to a number of risks, including the following:

• SWN will be required to pay its costs relating to the Indigo Merger, such as legal, accounting and financial advisory, whether or not the Indigo Merger is completed;

•time and resources committed by SWN’s management to matters relating to the Indigo Merger could otherwise have been devoted to pursuing other beneficial opportunities; and

•the market price of the common stock could decline to the extent that the current market price reflects a market assumption that the Indigo Merger will be completed.

In addition to the above risks, if the Indigo Merger Agreement is terminated and the Board seeks another acquisition, SWN’s shareholders cannot be certain that SWN will be able to find a party willing to enter into a transaction as attractive to SWN as Indigo. Also, if the Indigo Merger Agreement is terminated under certain specified circumstances, SWN may be required to pay Indigo a termination fee of $81 million or reimburse certain of Indigo’s expenses.

SWN may waive one or more of the closing conditions without re-soliciting shareholder approval.

SWN may determine to waive, in whole or part, one or more of the conditions to closing the Indigo Merger prior to SWN being obligated to consummate the Indigo Merger. SWN currently expects to evaluate the materiality of any waiver and its effect on SWN shareholders in light of the facts and circumstances at the time, to determine whether any amendment of the proxy statement or any re-solicitation of proxies is required in light of such waiver. Any determination whether to waive any condition to the Indigo Merger or to re-solicit shareholder approval or amending or supplementing the proxy statement as a result of a waiver will be made by SWN at the time of such waiver based on the facts and circumstances as they exist at that time.

SWN and Indigo will be subject to business uncertainties while the Indigo Merger is pending, which could adversely affect SWN’s business.

In connection with the pendency of the Indigo Merger, it is possible that certain persons with whom SWN or Indigo have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with SWN or Indigo, as the case may be, as a result of the Indigo Merger, which could negatively affect SWN’s or Indigo’s revenues, earnings and cash flows as well as the market price of the common stock, regardless of whether the Indigo Merger is completed. Also, SWN’s and Indigo’s ability to attract, retain and motivate employees may be impaired until the Indigo Merger is completed, and SWN’s ability to do so may be impaired for a period of time thereafter, as current and prospective employees may experience uncertainty about their roles within the combined company following the Indigo Merger.

Under the terms of the Indigo Merger Agreement, SWN and Indigo are subject to certain restrictions on the conduct of business prior to the consummation of the Indigo Merger, which may adversely affect SWN’s and Indigo’s ability to execute certain of SWN’s and Indigo’s business strategies, including the ability in certain cases to modify or enter into certain contracts, acquire or dispose of certain assets, incur or prepay certain indebtedness, incur encumbrances, make capital expenditures or settle claims. Such limitations could negatively affect SWN’s and Indigo’s businesses and operations prior to the completion of the Indigo Merger.

SWN will incur significant transaction costs in connection with the Indigo Merger.

SWN has incurred and is expected to continue to incur a number of non-recurring costs associated with the Indigo Merger, combining the operations of Indigo with SWN’s and achieving desired synergies. These costs have been, and will continue to

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be, substantial and, in many cases, will be borne by SWN whether or not the Indigo Merger is completed. A substantial majority of non-recurring expenses will consist of transaction costs and include, among others, fees paid to financial, legal, accounting and other advisors and employee retention, severance, and benefit costs. SWN will also incur costs related to formulating and implementing integration plans. Although SWN expects that the elimination of duplicative costs, as well as the realization of synergies and efficiencies related to the integration of the assets and operations of Indigo, should allow SWN to offset these transaction costs over time, this net benefit may not be achieved in the near term or at all.

Moreover, if the Indigo Merger is not completed, SWN will have incurred substantial expenses for which no ultimate benefit will have been received. SWN has incurred out-of-pocket expenses in connection with the Indigo Merger for investment banking, legal and accounting fees and financial printing and other costs and expenses, much of which will be incurred even if the Indigo Merger is not completed.

Termination of the Indigo Merger Agreement or failure to otherwise complete the Indigo Merger could negatively impact SWN’s business and financial results.

Termination of the Indigo Merger Agreement or any failure to otherwise complete the Indigo Merger may result in various consequences, including:

•SWN’s business may have been adversely impacted by the failure to pursue other beneficial opportunities due to the focus of management on the Indigo Merger, without realizing any of the anticipated benefits of completing the Indigo Merger;

•in certain instances, payment by SWN of a termination fee or reimbursement of certain expenses to Indigo;

•under certain circumstances, the Indigo Merger Agreement requires that SWN advance, or pay to Indigo the amount of loss in respect of, certain hedge contracts entered into by Indigo subsequent to the execution of the Indigo Merger Agreement; and

•negative reactions from the financial markets and customers may occur if the anticipated benefits of the Indigo Merger are not able to be realized. Such anticipated benefits may include, among others, operational efficiencies, cost savings, and synergies.

If the Indigo Merger is not consummated, SWN cannot assure you that the risks described above will not negatively impact the business, financial results, and ability to repay its outstanding indebtedness.

Until the completion of the Indigo Merger or the termination of the Indigo Merger Agreement in accordance with its terms, SWN and Indigo are each prohibited from entering into certain transactions and taking certain actions that might otherwise be beneficial to SWN or Indigo and their respective shareholders.

From and after the date of the Indigo Merger Agreement and prior to completion of the Indigo Merger, the Indigo Merger Agreement restricts SWN and Indigo from taking specified actions without the consent of the other party and generally requires that the business of each company and its respective subsidiaries be conducted in all material respects in the ordinary course of business consistent with past practice. These restrictions may prevent SWN or Indigo from making appropriate changes to their respective businesses or organizational structures or from pursuing attractive business opportunities that may arise prior to the completion of the Indigo Merger, and could have the effect of delaying or preventing other strategic transactions. Adverse effects arising from the pendency of the Indigo Merger could be exacerbated by any delays in consummation of the Indigo Merger or termination of the Indigo Merger Agreement.

The announcement and pendency of the Indigo Merger could have an adverse effect on SWN’s and/or Indigo’s business, financial condition, results of operations or business prospects.

The announcement and pendency of the Indigo Merger could disrupt SWN’s and/or Indigo’s businesses in the following ways, among others:

•SWN’s and/or Indigo’s employees may experience uncertainty regarding their future roles in the combined company, which might adversely affect SWN’s and/or Indigo’s ability to retain, recruit and motivate key personnel;

•the attention of SWN’s and/or Indigo’s management may be directed toward the completion of the Indigo Mergers and other transaction-related considerations and may be diverted from the day-to-day business operations of SWN and/or Indigo, as applicable, and matters related to the Indigo Mergers may require commitments of time and resources that

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could otherwise have been devoted to other opportunities that might have been beneficial to SWN and/or Indigo, as applicable; and

•customers, suppliers and other third parties with business relationships with SWN and/or Indigo may decide not to renew or may decide to seek to terminate, change and/or renegotiate their relationships with SWN and/or Indigo as a result of the Indigo Merger, whether pursuant to the terms of their existing agreements with SWN and/or Indigo or otherwise.

Any of these matters could adversely affect the businesses of, or harm the financial condition, results of operations or business prospects of, SWN and/or Indigo.

Securities class action and derivative lawsuits may be brought against SWN in connection with the Indigo Merger, which could result in substantial costs and may delay or prevent the Indigo Merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements that could prevent or delay the completion of the Indigo Merger and result in significant costs to SWN, including any costs associated with the indemnification of directors and officers. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on SWN’s liquidity and financial condition.

Lawsuits that may be brought against SWN, Indigo or SWN’s or Indigo’s directors could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin SWN from consummating the Indigo Merger. One of the conditions to the closing of the Indigo Merger is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing of the Indigo Merger. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Indigo Merger, that injunction may delay or prevent the Indigo Merger from being completed within the expected timeframe or at all, which may adversely affect SWN’s business, financial position and results of operation.

The combined company may record goodwill and other intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined company in the future.

SWN will account for the Indigo Merger as an acquisition of a business in accordance with GAAP. Under the acquisition method of accounting, the assets and liabilities of Indigo and its subsidiaries will be recorded, as of completion, at their respective fair values and added to SWN’s. SWN’s reported financial condition and results of operations for periods after completion of the Indigo Merger will reflect Indigo’s balances and results after completion of the Indigo Merger but will not be restated retroactively to reflect the historical financial position or results of operations of Indigo and its subsidiaries for periods prior to the Indigo Merger.

Under the acquisition method of accounting, the total purchase price will be allocated to Indigo’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the Indigo Merger. The excess of the purchase price over those fair values, if any, will be recorded as goodwill. To the extent the value of goodwill or intangibles, if any, becomes impaired in the future, the combined company may be required to incur material non-cash charges relating to such impairment. The combined company’s operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.

Risks Factors Relating to SWN Following the Indigo Merger

If the Indigo Merger is consummated, SWN may be unable to successfully integrate Indigo’s business into its business or achieve the anticipated benefits of the Indigo Merger.

The success of the Indigo Merger will depend, in part, on SWN’s ability to realize the anticipated benefits and cost savings from combining SWN’s and Indigo’s businesses, and there can be no assurance that SWN will be able to successfully integrate or otherwise realize the anticipated benefits of the Indigo Merger. Difficulties in integrating SWN and Indigo may result in the combined company performing differently than expected, in operational challenges, or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

•the inability to successfully integrate Indigo in a manner that permits the achievement of full revenue, expected cash flows and cost savings anticipated from the Indigo Merger;

•not realizing anticipated operating synergies;

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•integrating personnel from Indigo and the loss of key employees;

•potential unknown liabilities and unforeseen expenses or delays associated with and following the completion of the Indigo Merger;

•integrating relationships with customers, vendors and business partners;

•performance shortfalls as a result of the diversion of management’s attention caused by completing the Indigo Merger and integrating Indigo’s operations;

•the impact of SWN’s recent acquisition of Montage Resources Corporation and continuing integration related to the acquisition; and

•the disruption of, or the loss of momentum in, SWN’s ongoing business or inconsistencies in standards, controls, procedures and policies.

SWN’s ability to achieve the anticipated benefits of the Indigo Merger will depend in part upon whether it can integrate Indigo’s business into SWN’s existing business in an efficient and effective manner. SWN may not be able to accomplish this integration process successfully. The successful acquisition of producing properties, including those owned by Indigo, requires an assessment of several factors, including:

•recoverable reserves;

•future natural gas and oil prices and their appropriate differentials;

•availability and cost of transportation of production to markets;

•availability and cost of drilling equipment and of skilled personnel;

•development and operating costs including access to water and potential environmental and other liabilities; and

•regulatory, permitting and similar matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, SWN has performed a review of the subject properties that it believes to be generally consistent with industry practices. The review was based on SWN’s analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Data used in such review was furnished by Indigo or obtained from publicly available sources. SWN’s review may not reveal all existing or potential problems or permit SWN to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the assets and operations of Indigo may differ materially after such data is reviewed further by SWN. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, Indigo may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. SWN is often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the assets and operations of Indigo, SWN is entitled to remedies for only certain environmental liabilities. Additionally, SWN will not have the ability to control operations with respect to the portion of the assets and operations of Indigo in which Indigo holds only a non-operating interest. The integration process may be subject to delays or changed circumstances, and SWN can’t give any assurances that the assets and operations of Indigo will perform in accordance with SWN’s expectations or that SWN’s expectations with respect to integration or cost savings as a result of the Indigo Merger will materialize.

SWN’s results may suffer if it does not effectively manage its expanded operations following the Indigo Merger.

Following completion of the Indigo Merger, the size of the Company’s business will increase significantly beyond its current size. SWN’s future success will depend, in part, on SWN’s ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of Indigo into SWN’s existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners.

SWN’s current shareholders will have a reduced ownership and voting interest after the Indigo Merger compared to their current ownership and will exercise less influence over management.

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Based on the number of outstanding shares of common stock as of July 27, 2021, immediately after the Indigo Merger is completed, it is expected that, on a fully diluted basis, SWN’s current shareholders will collectively own approximately 67% and the former Indigo shareholders will own, in the aggregate, approximately 33% of the outstanding shares of common stock (assuming no adjustments are made pursuant to the Indigo Merger Agreement). As a result of the Indigo Merger, SWN’s current shareholders will own a smaller percentage of SWN than they currently own, and as a result will have less influence on SWN’s management and policies.

Sales of substantial amounts of the common stock in the open market by the holders of units of Indigo (“Indigo Holders”) could depress SWN’s stock price.

Shares of common stock that are issued to the Indigo Holders in the Indigo Merger will become freely tradable once registered pursuant to the registration rights agreement to be entered into by SWN and certain Indigo Holders (the “Registration Rights Agreement”) or sold in compliance with Rule 144 promulgated under the Securities Act. Pursuant to the Registration Rights Agreement, all of the shares of common stock issued as stock consideration to any Indigo Holder who is a party to the Registration Rights Agreement will be registered for resale. Once registered, the common stock held by such Indigo Holders will be unrestricted and will not require further registration under the Securities Act, although such shares may be subject to the lockup restrictions set forth in the Registration Rights Agreement.

The Indigo Holders may wish to dispose of some or all of their interests in SWN, and as a result may seek to sell their shares of common stock. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of common stock, may affect the market for, and the market price of, the common stock in an adverse manner.

If the Indigo Merger is completed and SWN’s shareholders, including the Indigo Holders, sell substantial amounts of common stock in the public market following the closing of the Indigo Merger, the market price of the common stock may decrease. These sales might also make it more difficult for SWN to raise capital by selling equity or equity-related securities at a time and price that it otherwise would deem appropriate.

The trading price and volume of the common stock may be volatile following the Indigo Merger.

The trading price and volume of the common stock may be volatile following completion of the Indigo Merger. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of the common stock. As a result, you may suffer a loss on your investment.

The market for the common stock will depend on a number of conditions, most of which the combined company cannot control, including:

•general economic conditions within the U.S. and internationally, including changes in interest rates;

•general market conditions, including fluctuations in commodity prices;

•domestic and international economic, legal and regulatory factors unrelated to the combined company’s performance;

•changes in oil and natural gas prices; volatility in the financial markets or other global economic factors, including the impact of COVID-19;

•actual or anticipated fluctuations in the combined company’s quarterly and annual results and those of its competitors;

•quarterly variations in the rate of growth of the combined company’s financial indicators, such as revenue, EBITDA, net income and net income per share;

•the businesses, operations, results and prospects of the combined company;

•the operating and financial performance of the combined company;

•future mergers and strategic alliances;

•market conditions in the oil industry;

•changes in government regulation, taxes, legal proceedings or other developments;

•shortfalls in the combined company’s operating results from levels forecasted by securities analysts;

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•investor sentiment toward the stock of oil and gas companies;

•changes in revenue or earnings estimates, or changes in recommendations by equity research analysts;

•failure of the combined company to achieve the perceived benefits of the Indigo Merger, including financial results and anticipated synergies, as rapidly as or to the extent anticipated by financial or industry analysts;

•speculation in the press or investment community;

•the failure of research analysts to cover the combined company’s common stock;

•sales of the common stock by the combined company, large shareholders or management, or the perception that such sales may occur;

•changes in accounting principles, policies, guidance, interpretations or standards;

•announcements concerning the combined company or its competitors;

•public reaction to the combined company’s press releases, other public announcements and filings with the SEC;

•strategic actions taken by competitors;

•actions taken by the combined company shareholders;

•additions or departures of key management personnel;

•maintenance of acceptable credit ratings or credit quality; and

•the general state of the securities markets.

These and other factors may impair the market for the common stock and the ability of investors to sell shares at an attractive price. These factors also could cause the market price and demand for the common stock to fluctuate substantially, which may negatively affect the price and liquidity of the common stock. Many of these factors and conditions are beyond the control of the combined company or the combined company shareholders.

Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against the combined company, could result in very substantial costs, divert management’s attention and resources and harm the combined company’s business, operating results and financial condition.

Following the completion of the Indigo Merger, SWN may be exposed to additional commodity price risk as a result of the acquisition of Indigo’s upstream assets.

The prices for natural gas have historically been volatile, and SWN expects this volatility to continue in the future. The Indigo Merger may increase SWN’s exposure to these, or other, commodity price risks.

To mitigate its exposure to changes in commodity prices, Indigo hedges natural gas from time to time, primarily through the use of certain derivative commodity instruments. SWN will bear the economic impact of all of Indigo’s current hedges following the completion of the Indigo Merger. Actual natural gas prices may differ from the Company’s expectations and, as a result, such hedges could have a negative impact on SWN’s business.

SWN’s ability to utilize its U.S. net operating loss carryforwards to reduce future taxable income following the consummation of the Indigo Merger will be subject to various limitations under the United States Internal Revenue Code of 1986, as amended (the “Code”).

Section 382 of the Code imposes a limitation on the ability of a corporation to utilize its net operating loss carryforwards (“NOLs”) upon the occurrence of an ownership change resulting from issuances of a corporation’s stock or the sale or exchange of such corporation’s stock by certain shareholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of such corporation’s stock by such shareholders during any three-year period. SWN believes that the Indigo Merger, if consummated, will result in an ownership change with respect to SWN, which would trigger a limitation on SWN’s ability to utilize any of its historic loss carryforwards following the consummation of the Indigo Merger, based on information currently available. The limitation with respect to such loss carryforwards generally would be equal to (i) the fair market value of SWN’s equity as of immediately prior to such ownership change multiplied by (ii) a percentage approximately

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equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. In addition, the limitation would, under current law, be increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains in SWN’s assets at the time of the ownership change. Any such limitation imposed on the ability to use such NOLs to offset future taxable income could cause the Company to pay U.S. federal income taxes earlier than it otherwise would if such limitations were not in effect and could cause certain of such NOLs to expire unused, thereby reducing or eliminating the benefit of such NOLs.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Our sand mine location, which supported our former Fayetteville Shale business, was subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Quarterly Report. On February 10, 2021, we sold our sand mine to a third party and, as a result, no longer own or operate any mines.

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS


(2.1)			Agreement and Plan of Merger, dated as of August 12, 2020, by and between Southwestern Energy Company and Montage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K/A filed on August 12, 2020).
(2.2)			Agreement and Plan of Merger, dated June 1, 2021, by and among Southwestern Energy Company, Ikon Acquisition Company, LLC, Indigo Natural Resources LLC, and Ibis Unitholder Representative, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed June 2, 2021).
(3.1)			Amended and Restated Certificate of Incorporation of Southwestern Energy Company (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010).
(3.2)			Amended and Restated Bylaws of Southwestern Energy Company, as amended on April 28, 2020 (Incorporated by reference to Exhibit 3.2 to the Registrant’s Quarterly Report on Form 10-Q filed April 30, 2020).
(10.1)			Amendment No.10 to Credit Agreement, dated June 9, 2021, among Southwestern Energy Corporation, the lenders party thereto and JP Morgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed June 9, 2021).
(31.1)*			Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)*			Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)*			Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2)*			Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(95.1)*			Mine Safety Disclosure.
(101.INS)			Inline Interactive Data File Instance Document
(101.SCH)			Inline Interactive Data File Schema Document
(101.CAL)			Inline Interactive Data File Calculation Linkbase Document
(101.LAB)			Inline Interactive Data File Label Linkbase Document
(101.PRE)			Inline Interactive Data File Presentation Linkbase Document
(101.DEF)			Inline Interactive Data File Definition Linkbase Document
(104.1)			Cover Page Interactive Data File – the cover page from this Quarterly Report on Form 10-Q, formatted in inline XBRL (included within the Exhibit 101 attachments)

*Filed herewith

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		SOUTHWESTERN ENERGY COMPANY
		Registrant

Dated:	July 29, 2021	/s/ CARL F. GIESLER, JR.
		Carl F. Giesler, Jr. Executive Vice President and Chief Financial Officer