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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 ~~March 31,~~September 30, 2020

☐ 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 ~~April 28,~~October 27, 2020
Common Stock, Par Value $0.01						~~541,688,616~~605,559,524

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~MARCH 31,~~SEPTEMBER 30, 2020


PART I – FINANCIAL INFORMATION					Page

Item 1.	Financial Statements			3
	Consolidated Statements of Operations			3
	Consolidated Statements of Comprehensive Income			4
	Consolidated Balance Sheets			5
	Consolidated Statements of Cash Flows			6
	Consolidated Statements of Changes in Equity			7
	Notes to Consolidated Financial Statements			89
		Note 1. Basis of Presentation	89
		Note 2. ~~Restructuring Charges~~	8
		~~Note 3. Revenue Recognition~~Acquisition	9
		Note ~~4. Cash and Cash Equivalents~~3 . Restructuring Charges	10
		Note 4 . Revenue Recognition	11
		Note ~~5. Natural Gas~~5 . Cash and ~~Oil Properties~~Cash Equivalents	1112
		Note ~~6. Earnings per Share~~	116
		~~Note 7. Derivatives~~. Natural Gas and ~~Risk Management~~Oil Properties	13
		Note 8.7 . Earnings per Share	13
		Note 8 . Derivatives and Risk Management	14
		Note 9 . Reclassifications From Accumulated Other Comprehensive Income (Loss)	2022
		Note 9.10 . Fair Value Measurements	20
		~~Note 10. Debt~~	22
		Note 1 1 . ~~Commitments and Contingencies~~Debt	24
		~~Note 1~~2 ~~. Income Taxes~~	2625
		Note 1 32 . ~~Pension Plan~~Commitments and ~~Other Postretirement Benefits~~Contingencies	2627
		Note 1 3 . Income Taxes	28
		Note 1 4 . ~~Stock-Based Compensation~~Pension Plan and Other Postretirement Benefits	2729
		Note 1 5 . ~~Segment Information~~Long-Term Incentive Compensation	3029
		Note 1 6 . Segment Information	33
		Note 1 7 . New Accounting Pronouncements	3134
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			3135
	Results of Operations			3438
	Liquidity and Capital Resources			4045
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			4551
Item 4.	Controls and Procedures			4552

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings			4652
Item 1A.	Risk Factors			4752
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			4754
Item 3.	Defaults Upon Senior Securities			4754
Item 4.	Mine Safety Disclosures			4754
Item 5.	Other Information			4754
Item 6.	Exhibits			4855

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

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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.

~~Table of Contents~~

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;~~acquisitions, including the Merger (as defined below);

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

•costs in connection with the Merger;

•integration of operations and results subsequent to the Merger;

•our ability to refinance the Montage Notes (as defined below) and the borrowings under Montage’s senior secured revolving credit facility;

•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 March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2020		2019		(in millions, except share/per share amounts)	2020		2019		2020		2019
Operating Revenues:	Operating Revenues:					Operating Revenues:
Gas sales	Gas sales	$	248	$	430	Gas sales	$	199	$	238	$	611	$	943
Oil sales	Oil sales	52		39		Oil sales	40		67		111		153
NGL sales	NGL sales	50		81		NGL sales	68		52		158		191
Marketing	Marketing	239		438		Marketing	219		279		645		1,004
Other	Other	3		2		Other	1		0		4		2
		592		990			527		636		1,529		2,293
Operating Costs and Expenses:	Operating Costs and Expenses:					Operating Costs and Expenses:
Marketing purchases	Marketing purchases	248		441		Marketing purchases	226		288		675		1,022
Operating expenses	Operating expenses	193		165		Operating expenses	202		189		577		523
General and administrative expenses	General and administrative expenses	26		37		General and administrative expenses	31		42		89		119

Montage acquisition-related expenses						Montage acquisition-related expenses	3		0		3		0
Restructuring charges	Restructuring charges	10		3		Restructuring charges	0		4		12		9
Loss on sale of operating assets						Loss on sale of operating assets	0		0		0		3
Depreciation, depletion and amortization	Depreciation, depletion and amortization	113		112		Depreciation, depletion and amortization	70		125		267		352
Impairments	Impairments	1,479		—		Impairments	361		2		2,495		8
Taxes, other than income taxes	Taxes, other than income taxes	13		19		Taxes, other than income taxes	15		15		38		51
		2,082		777			908		665		4,156		2,087
Operating Income (Loss)	Operating Income (Loss)	(1,490)		213		Operating Income (Loss)	(381)		(29)		(2,627)		206
Interest Expense:	Interest Expense:					Interest Expense:
Interest on debt	Interest on debt	40		42		Interest on debt	43		42		123		125
Other interest charges	Other interest charges	2		1		Other interest charges	2		2		7		5
Interest capitalized	Interest capitalized	(23)		(29)		Interest capitalized	(23)		(27)		(67)		(84)
		19		14			22		17		63		46

Gain (Loss) on Derivatives	Gain (Loss) on Derivatives	339		(32)		Gain (Loss) on Derivatives	(192)		100		38		220
Gain on Early Extinguishment of Debt	Gain on Early Extinguishment of Debt	28		—		Gain on Early Extinguishment of Debt	0		7		35		7
Other Income, Net		1		1
Other Income (Loss), Net						Other Income (Loss), Net	2		(2)		3		(7)

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(1,141)		168		Income (Loss) Before Income Taxes	(593)		59		(2,614)		380
Provision (Benefit) for Income Taxes:	Provision (Benefit) for Income Taxes:					Provision (Benefit) for Income Taxes:
Current	Current	(2)		—		Current	0		(1)		(2)		(1)
Deferred	Deferred	408		(426)		Deferred	0		11		408		(400)
		406		(426)			0		10		406		(401)
Net Income (Loss)	Net Income (Loss)	$	(1,547)	$	594	Net Income (Loss)	$	(593)	$	49	$	(3,020)	$	781


Earnings (Loss) Per Common Share:	Earnings (Loss) Per Common Share:					Earnings (Loss) Per Common Share:
Basic	Basic	$	(2.86)	$	1.10	Basic	$	(1.04)	$	0.09	$	(5.48)	$	1.45
Diluted	Diluted	$	(2.86)	$	1.10	Diluted	$	(1.04)	$	0.09	$	(5.48)	$	1.44

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:					Weighted Average Common Shares Outstanding:
Basic	Basic	540,308,491		539,721,751		Basic	571,872,413		539,221,101		551,162,559		539,315,170
Diluted	Diluted	540,308,491		541,320,487		Diluted	571,872,413		540,038,187		551,162,559		540,442,649

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

(Unaudited)


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Net income (loss)	Net income (loss)	$	(1,547)	$	594	Net income (loss)	$	(593)	$	49	$	(3,020)	$	781

Change in value of pension and other postretirement liabilities:	Change in value of pension and other postretirement liabilities:					Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost(1)	Amortization of prior service cost and net loss included in net periodic pension cost(1)	—		—		Amortization of prior service cost and net loss included in net periodic pension cost(1)	1		1		1		5

Comprehensive income (loss)	Comprehensive income (loss)	$	(1,547)	$	594	Comprehensive income (loss)	$	(592)	$	50	$	(3,019)	$	786

(1)Tax benefits for the three months ended September 30, 2020 were immaterial. Net of less than$1 million in tax benefits for the nine months ended September 30, 2020 and the three months ended September 30, 2019 and $2 million in tax benefits for the nine months ended September 30, 2019. In 2019, primarily related to settlement of pension assets.

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)


		March 31, 2020		December 31, 2019			September 30, 2020			December 31, 2019

ASSETS	ASSETS	(in millions)							ASSETS	(in millions)
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	5	$	5	Cash and cash equivalents	$	95		$	5
Accounts receivable, net	Accounts receivable, net	292		345		Accounts receivable, net	239			345
Derivative assets	Derivative assets	627		278		Derivative assets	238			278
Other current assets	Other current assets	48		51		Other current assets	41			51
Total current assets	Total current assets	972		679		Total current assets	613			679
Natural gas and oil properties, using the full cost method, including $1,437 million as of March 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization		25,488		25,250
Natural gas and oil properties, using the full cost method, including $1,379 million as of September 30, 2020 and $1,506 million as of December 31, 2019 excluded from amortization						Natural gas and oil properties, using the full cost method, including $1,379 million as of September 30, 2020 and $1,506 million as of December 31, 2019 excluded from amortization	25,969			25,250

Other	Other	523		520		Other	500			520
Less: Accumulated depreciation, depletion and amortization	Less: Accumulated depreciation, depletion and amortization	(22,095)		(20,503)		Less: Accumulated depreciation, depletion and amortization	(23,247)			(20,503)
Total property and equipment, net	Total property and equipment, net	3,916		5,267		Total property and equipment, net	3,222			5,267
Operating lease assets	Operating lease assets	152		159		Operating lease assets	145			159
Deferred tax assets	Deferred tax assets	—		407		Deferred tax assets	0			407
Other long-term assets	Other long-term assets	235		205		Other long-term assets	177			205
Total long-term assets	Total long-term assets	387		771		Total long-term assets	322			771
TOTAL ASSETS	TOTAL ASSETS	$	5,275	$	6,717	TOTAL ASSETS	$	4,157		$	6,717
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:

Accounts payable	Accounts payable	$	465	$	525	Accounts payable	$	416		$	525
Taxes payable	Taxes payable	52		59		Taxes payable	47			59
Interest payable	Interest payable	54		51		Interest payable	56			51

Derivative liabilities	Derivative liabilities	268		125		Derivative liabilities	287			125
Current operating lease liabilities	Current operating lease liabilities	32		34		Current operating lease liabilities	33			34
Other current liabilities	Other current liabilities	43		54		Other current liabilities	30			54
Total current liabilities	Total current liabilities	914		848		Total current liabilities	869			848
Long-term debt	Long-term debt	2,279		2,242		Long-term debt	2,450			2,242
Long-term operating lease liabilities	Long-term operating lease liabilities	114		119		Long-term operating lease liabilities	107			119
Long-term derivative liabilities						Long-term derivative liabilities	188			111
Pension and other postretirement liabilities	Pension and other postretirement liabilities	40		43		Pension and other postretirement liabilities	35			43
Other long-term liabilities	Other long-term liabilities	227		219		Other long-term liabilities	124			108
Total long-term liabilities	Total long-term liabilities	2,660		2,623		Total long-term liabilities	2,904			2,623
Commitments and contingencies (Note 11)
Commitments and contingencies (Note 12)						Commitments and contingencies (Note 12)
Equity:	Equity:					Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 586,023,435 shares as of March 31, 2020 and 585,555,923 shares as of December 31, 2019		6		6
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 649,899,653 shares as of September 30, 2020 and 585,555,923 shares as of December 31, 2019						Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 649,899,653 shares as of September 30, 2020 and 585,555,923 shares as of December 31, 2019	7			6

Additional paid-in capital	Additional paid-in capital	4,728		4,726		Additional paid-in capital	4,882			4,726
Accumulated deficit	Accumulated deficit	(2,798)		(1,251)		Accumulated deficit	(4,271)			(1,251)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(33)		(33)		Accumulated other comprehensive loss	(32)			(33)
Common stock in treasury, 44,353,224 shares as of March 31, 2020 and December 31, 2019		(202)		(202)
Common stock in treasury, 44,353,224 shares as of September 30, 2020 and December 31, 2019						Common stock in treasury, 44,353,224 shares as of September 30, 2020 and December 31, 2019	(202)			(202)
Total equity	Total equity	1,701		3,246		Total equity	384			3,246
TOTAL LIABILITIES AND EQUITY	TOTAL LIABILITIES AND EQUITY	$	5,275	$	6,717	TOTAL LIABILITIES AND EQUITY	$	4,157		$	6,717

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 three months ended March 31,							For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019
Cash Flows From Operating Activities:	Cash Flows From Operating Activities:					Cash Flows From Operating Activities:
Net income (loss)	Net income (loss)	$	(1,547)	$	594	Net income (loss)	$	(3,020)	$	781
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	113		112		Depreciation, depletion and amortization	267		352
Amortization of debt issuance costs	Amortization of debt issuance costs	1		1		Amortization of debt issuance costs	6		5
Impairments	Impairments	1,479		—		Impairments	2,495		8
Deferred income taxes	Deferred income taxes	408		(426)		Deferred income taxes	408		(400)
(Gain) loss on derivatives, unsettled	(Gain) loss on derivatives, unsettled	(246)		22		(Gain) loss on derivatives, unsettled	272		(108)
Stock-based compensation	Stock-based compensation	1		2		Stock-based compensation	2		6
Gain on early extinguishment of debt	Gain on early extinguishment of debt	(28)		—		Gain on early extinguishment of debt	(35)		(7)

Loss on sale of assets						Loss on sale of assets	0		3
Other	Other	—		1		Other	3		11
Change in assets and liabilities:	Change in assets and liabilities:					Change in assets and liabilities:
Accounts receivable	Accounts receivable	53		189		Accounts receivable	106		257
Accounts payable	Accounts payable	(86)		(48)		Accounts payable	(129)		(124)
Taxes payable	Taxes payable	(6)		4		Taxes payable	(12)		(3)
Interest payable	Interest payable	1		2		Interest payable	3		2
Inventories	Inventories	8		5		Inventories	3		(2)
Other assets and liabilities	Other assets and liabilities	9		(16)		Other assets and liabilities	38		(42)
Net cash provided by operating activities	Net cash provided by operating activities	160		442		Net cash provided by operating activities	407		739

Cash Flows From Investing Activities:	Cash Flows From Investing Activities:					Cash Flows From Investing Activities:
Capital investments	Capital investments	(228)		(258)		Capital investments	(700)		(877)

Proceeds from sale of property and equipment						Proceeds from sale of property and equipment	2		42

Net cash used in investing activities	Net cash used in investing activities	(228)		(258)		Net cash used in investing activities	(698)		(835)

Cash Flows From Financing Activities:	Cash Flows From Financing Activities:					Cash Flows From Financing Activities:

Payments on long-term debt	Payments on long-term debt	(52)		—		Payments on long-term debt	(72)		(43)
Payments on revolving credit facility	Payments on revolving credit facility	(500)		—		Payments on revolving credit facility	(1,449)		0
Borrowings under revolving credit facility	Borrowings under revolving credit facility	615		—		Borrowings under revolving credit facility	1,415		0
Change in bank drafts outstanding	Change in bank drafts outstanding	5		3		Change in bank drafts outstanding	(9)		(11)

Proceeds from issuance of long-term debt						Proceeds from issuance of long-term debt	350		0
Debt issuance costs						Debt issuance costs	(5)		0
Purchase of treasury stock	Purchase of treasury stock	—		(21)		Purchase of treasury stock	0		(21)

Proceeds from issuance of common stock, net						Proceeds from issuance of common stock, net	152		0
Cash paid for tax withholding	Cash paid for tax withholding	—		(1)		Cash paid for tax withholding	(1)		(1)

Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	68		(19)		Net cash provided by (used in) financing activities	381		(76)

Increase in cash and cash equivalents		—		165
Increase (decrease) in cash and cash equivalents						Increase (decrease) in cash and cash equivalents	90		(172)
Cash and cash equivalents at beginning of year	Cash and cash equivalents at beginning of year	5		201		Cash and cash equivalents at beginning of year	5		201
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	5	$	366	Cash and cash equivalents at end of period	$	95	$	29

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

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

Issuance of restricted stock	Issuance of restricted stock	12,397	—		—		—		—		—	—			—		Issuance of restricted stock	12,397	—			—		—		—		—	—			—
Cancellation of restricted stock	Cancellation of restricted stock	(167,130)	—		—		—		—		—	—			—		Cancellation of restricted stock	(167,130)	—			—		—		—		—	—			—
Restricted units granted	Restricted units granted	1,005,976	—		1		—		—		—	—			1		Restricted units granted	1,005,976	—			1		—		—		—	—			1
Treasury stock		—	—		—		—		—		—	—			—
Performance units vested		—	—		—		—		—		—	—			—

Tax withholding – stock compensation	Tax withholding – stock compensation	(383,731)	—		—		—		—		—	—			—		Tax withholding – stock compensation	(383,731)	—			—		—		—		—	—			—
Balance at March 31, 2020	Balance at March 31, 2020	586,023,435	$	6	$	4,728	$	(2,798)	$	(33)	44,353,224	$	(202)		$	1,701	Balance at March 31, 2020	586,023,435	$	6		$	4,728	$	(2,798)	$	(33)	44,353,224	$	(202)		$	1,701

Comprehensive loss:																	Comprehensive loss:
Net loss																	Net loss	—	—			—		(880)		—		—	—			(880)
Other comprehensive income																	Other comprehensive income	—	—			—		—		—		—	—			—
Total comprehensive loss																	Total comprehensive loss	—	—			—		—		—		—	—			(880)
Stock-based compensation																	Stock-based compensation	—	—			1		—		—		—	—			1
Issuance of restricted stock																	Issuance of restricted stock	222,489	—			—		—		—		—	—			—
Cancellation of restricted stock																	Cancellation of restricted stock	(1,079,515)	—			—		—		—		—	—			—
Restricted units granted																	Restricted units granted	1,649,294	—			2		—		—		—	—			2
Tax withholding – stock compensation																	Tax withholding – stock compensation	(222,163)	—			(1)		—		—		—	—			(1)
Balance at June 30, 2020																	Balance at June 30, 2020	586,593,540	$	6		$	4,730	$	(3,678)	$	(33)	44,353,224	$	(202)		$	823
Comprehensive loss:																	Comprehensive loss:
Net loss																	Net loss	—	—			—		(593)		—		—	—			(593)
Other comprehensive income																	Other comprehensive income	—	—			—		—		1		—	—			1
Total comprehensive loss																	Total comprehensive loss	—	—			—		—		—		—	—			(592)
Stock-based compensation																	Stock-based compensation	—	—			1		—		—		—	—			1
Issuance of common stock																	Issuance of common stock	63,250,000	1			151		—		—		—	—			152
Issuance of restricted stock																	Issuance of restricted stock	63,344	—			—		—		—		—	—			—
Cancellation of restricted stock																	Cancellation of restricted stock	(5,196)	—			—		—		—		—	—			—
Treasury stock																	Treasury stock	—	—			—		—		—		—	—			—
Tax withholding – stock compensation																	Tax withholding – stock compensation	(2,035)	—			—		—		—		—	—			—
Balance at Balance at September 31, 2020																	Balance at Balance at September 31, 2020	649,899,653	$	7		$	4,882	$	(4,271)	$	(32)	44,353,224	$	(202)		$	384

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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, 2018 585,407,107 $ 6 $ 4,715 $ (2,142) $ (36) 39,092,537 $ (181) $ 2,362
Comprehensive income:
Net income — — — 594 — — — 594
Other comprehensive income — — — — — — — —
Total comprehensive income — — — — — — — 594
Stock-based compensation — — 3 — — — — 3
Issuance of restricted stock 8,798 — — — — — — —
Cancellation of restricted stock (128,324) — — — — — — —
Treasury stock — — — — — 5,260,687 (21) (21)
Performance units vested 535,802 — — — — — — —
Tax withholding – stock compensation (274,657) — (1) — — — — (1)
Balance at March 31, 2019 585,548,726 $ 6 $ 4,717 $ (1,548) $ (36) 44,353,224 $ (202) $ 2,937


	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, 2018	585,407,107	$	6	$	4,715	$	(2,142)	$	(36)	39,092,537	$	(181)	$	2,362
Comprehensive income:
Net income	—	—		—		594		—		—	—		594
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive income	—	—		—		—		—		—	—		594
Stock-based compensation	—	—		3		—		—		—	—		3

Issuance of restricted stock	8,798	—		—		—		—		—	—		—
Cancellation of restricted stock	(128,324)	—		—		—		—		—	—		—
Treasury stock	—	—		—		—		—		5,260,687	(21)		(21)
Performance units vested	535,802	—		—		—		—		—	—		—
Tax withholding – stock compensation	(274,657)	—		(1)		—		—		—	—		(1)
Balance at March 31, 2019	585,548,726	$	6	$	4,717	$	(1,548)	$	(36)	44,353,224	$	(202)	$	2,937
Comprehensive income:
Net income	—	—		—		138		—		—	—		138
Other comprehensive income	—	—		—		—		4		—	—		4
Total comprehensive income	—	—		—		—		—		—	—		142
Stock-based compensation	—	—		3		—		—		—	—		3
Issuance of restricted stock	6,424	—		—		—		—		—	—		—
Cancellation of restricted stock	(72,555)	—		—		—		—		—	—		—
Tax withholding – stock compensation	(4,250)	—		—		—		—		—	—		—
Balance at June 30, 2019	585,478,345	$	6	$	4,720	$	(1,410)	$	(32)	44,353,224	$	(202)	$	3,082
Comprehensive income:
Net income	—	—		—		49		—		—	—		49
Other comprehensive income	—	—		—		—		1		—	—		1
Total comprehensive income	—	—		—		—		—		—	—		50
Stock-based compensation	—	—		3		—		—		—	—		3
Issuance of restricted stock	205,883	—		—		—		—		—	—		—
Cancellation of restricted stock	(33,851)	—		—		—		—		—	—		—
Tax withholding – stock compensation	(12,957)	—		—		—		—		—	—		—
Balance at Balance at September 30, 2019	585,637,420	$	6	$	4,723	$	(1,361)	$	(31)	44,353,224	$	(202)	$	3,135

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 2 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 and West Virginia. 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 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 and West Virginia as “Appalachia.” The Company also operates drilling rigs located in Pennsylvania and West Virginia, and provides certain oilfield products and services, principally serving the Company’s E&P ~~operations~~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 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, 2019 (“2019 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 2019 Annual Report.

(2) ACQUISITION

On August 12, 2020, Southwestern and Montage Resources Corporation (“Montage”) entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Montage will merge with and into Southwestern, with Southwestern continuing as the surviving company (the “Merger”). The Company will acquire at the effective time of the Merger (the “Effective Time”) all of the outstanding shares of common stock of Montage in exchange for 1.8656 shares of common stock of the Company per share of Montage common stock. No fractional Southwestern common shares will be issued in the Merger, and holders of Montage common shares will, instead, receive cash in lieu of fractional Southwestern common shares, if any. This exchange ratio is fixed and will not be adjusted for changes in the Company’s stock price. Following the closing of the Merger, Southwestern’s existing shareholders and Montage’s existing shareholders will own approximately 90% and 10%, respectively, of the outstanding shares of the combined company. The transaction is expected to close in the fourth quarter of 2020, subject to customary closing conditions, including the approval of the Montage shareholders.

The Merger Agreement provides that, upon consummation of the Merger, the directors and officers of Southwestern immediately prior to the Effective Time shall, from and after the Effective Time, be the directors and officers of the combined company. Southwestern will continue to be headquartered in Spring, Texas.

In August 2020, the Company completed an underwritten public offering of 63,250,000 shares of common stock with an offering price to the public of $2.50 per share, with net proceeds from the offering totaling $152 million after deducting underwriting discounts and offering expenses. Also in August 2020, the Company completed an underwritten public offering of

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$350 million aggregate principal amount of 8.375% senior notes due 2028 (the “2028 Notes”). The net proceeds from the offering, after deducting the underwriting discount and estimated offering expenses, were approximately $345 million. The Company intends to use the net proceeds from the debt offering, together with the net proceeds received from the common stock offering 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 Merger. Pending the consummation of the Merger, a portion of these net proceeds has temporarily been used to repay revolving credit facility borrowings until the anticipated redemption of the Montage Notes. The 2028 Notes are subject to special mandatory redemption at par plus accrued and unpaid interest if the Merger does not close on or prior to February 12, 2021 or the Company determines in its sole discretion that the consummation of the Merger cannot or is not reasonably likely to be satisfied by February 12, 2021.

The Company has recorded approximately $3 million in transaction related expenses for the three and nine months ended September 30, 2020.

(3) RESTRUCTURING CHARGES

On February 4, 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company’s organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. 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~~nine months ended ~~March 31,~~September 30, 2020, and ~~a liability~~were substantially complete by the end of ~~approximately $0.3 million has been accrued as~~the first quarter of ~~March 31, 2020 related to future payments associated with the February 2020 restructuring.~~2020.

In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in ~~Arkansas (the “Fayetteville Shale sale”).~~Arkansas. As part of ~~the~~this transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. ~~Due to the scale of the assets that were sold, the temporary employment of certain employees was extended through a transition period into 2019.~~ All 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 a portion of equity awards that were forfeited. ~~The~~As of September 30, 2019, the Company ~~also incurred~~had substantially completed the Fayetteville Shale sale-related employment terminations.

As a result of the Fayetteville Shale sale, the Company relocated certain employees and infrastructure to other locations and began the process of consolidating and reorganizing its office space. These charges related to office ~~consolidation. A portion of these costs along with the aforementioned severance costs were~~consolidation and reorganization have been recognized as restructuring charges.

In July 2019, the Company terminated its existing lease agreement in its headquarters office building and entered into a new 10-year lease agreement for a smaller portion of the building. Approximately $3 million and $5 million of the fees associated with the Company’s headquarters office consolidation and other office consolidation are reflected as restructuring charges for the three and nine months ended September 30, 2019, respectively. The Company also recognized additional severance costs in the ~~first~~third quarter of ~~2019.~~

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2019 related to continued organizational restructuring.

The following table presents a summary of the restructuring charges included in Operating Income (Loss) for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019:


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Severance (including payroll taxes)	Severance (including payroll taxes)	$	10	$	2	Severance (including payroll taxes)	$	0	$	1	$	12	$	4
Office consolidation	Office consolidation	—		1		Office consolidation	0		3		0		5

Total restructuring charges⁽¹⁾	Total restructuring charges⁽¹⁾	$	10	$	3	Total restructuring charges (1)	$	0	$	4	$	12	$	9

(1)Total restructuring charges were ~~$10 million and $3~~$12 million for the Company’s E&P segment for the ~~three~~nine months ended ~~March 31,~~September 30, 2020, and $4 million and $9 million for the three and nine months ended September 30, 2019, respectively.

The following table presents a reconciliation of the liability associated with the Company’s restructuring activities at ~~March 31,~~September 30, 2020, which is reflected in accounts payable on the consolidated balance sheet:


(in millions)
Liability at December 31, 2019	$	2
Additions	1012
Distributions	~~(12)~~(14)
Liability at ~~March 31,~~September 30, 2020	$	—0

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~~(3)~~(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 a market ~~index~~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 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.

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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 March 31, 2020
Gas sales $ 239 $ — $ 9 $ 248
Oil sales 52 — — 52
NGL sales 50 — — 50
Marketing — 548 (309) 239
Other ⁽¹⁾
3 — — 3
Total $ 344 $ 548 $ (300) $ 592
Three months ended March 31, 2019
Gas sales $ 421 $ — $ 9 $ 430
Oil sales 39 — — 39
NGL sales 81 — — 81
Marketing — 940 (502) 438
Other ⁽²⁾
1 1 — 2
Total $ 542 $ 941 $ (493) $ 990


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended September 30, 2020
Gas sales	$	190	$	0	$	9	$	199
Oil sales	39		0		1		40
NGL sales	68		0		0		68
Marketing	0		495		(276)		219
Other	1		0		0		1

Total	$	298	$	495	$	(266)	$	527

Three months ended September 30, 2019
Gas sales	$	230	$	0	$	8	$	238
Oil sales	66		0		1		67
NGL sales	52		0		0		52
Marketing	0		592		(313)		279

Total	$	348	$	592	$	(304)	$	636

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(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2020
Gas sales	$	584	$	0	$	27	$	611
Oil sales	107		0		4		111
NGL sales	158		0		0		158
Marketing	0		1,432		(787)		645
Other (1)	4		0		0		4
Total	$	853	$	1,432	$	(756)	$	1,529

Nine months ended September 30, 2019
Gas sales	$	918	$	0	$	25	$	943
Oil sales	151		0		2		153
NGL sales	191		0		0		191
Marketing	0		2,158		(1,154)		1,004
Other (2)	1		1		0		2
Total	$	1,261	$	2,159	$	(1,127)	$	2,293

(1)For the ~~three~~nine months ended ~~March 31,~~September 30, 2020, other E&P revenues consists primarily of gains on purchaser imbalances associated with certain NGLs.

(2)For the ~~three~~nine months ended ~~March 31,~~September 30, 2019, other E&P revenues consists primarily of water sales to third-party operators, and other Marketing revenues consists primarily of sales of gas from storage.

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 and West Virginia.


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Northeast Appalachia	Northeast Appalachia	$	195	$	348	Northeast Appalachia	$	131	$	175	$	443	$	740
Southwest Appalachia	Southwest Appalachia	149		193		Southwest Appalachia	166		173		409		519
Other	Other	—		1		Other	1		0		1		2
Total	Total	$	344	$	542	Total	$	298	$	348	$	853	$	1,261

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)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	September 30, 2020		December 31, 2019
Receivables from contracts with customers	Receivables from contracts with customers	$	195	$	284	Receivables from contracts with customers	$	218	$	284
Other accounts receivable	Other accounts receivable	97		61		Other accounts receivable	21		61
Total accounts receivable	Total accounts receivable	$	292	$	345	Total accounts receivable	$	239	$	345

Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019. The Company has 0 contract assets or contract liabilities associated with its revenues from contracts with customers.

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~~(4)~~(5) CASH AND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of ~~March 31,~~September 30, 2020 and December 31, 2019:


(in millions)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	September 30, 2020		December 31, 2019
Cash	Cash	$	5	$	5	Cash	$	93	$	5
Marketable securities ⁽¹⁾	Marketable securities ⁽¹⁾	—		—		Marketable securities (1)	2		0

Total	Total	$	5	$	5	Total	$	95	$	5

(1)~~At March 31, 2020, marketable securities were immaterial and consisted~~Consists of government stable value money market funds.

~~(5)~~

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(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 no0 hedge positions that were designated for hedge accounting as of ~~March 31,~~September 30, 2020. Prices used to calculate the ceiling value of reserves were as follows:


(in millions)		March 31, 2020		March 31, 2019
							September 30, 2020		September 30, 2019
Natural gas (per MMBtu)	Natural gas (per MMBtu)	$	2.30	$	3.07	Natural gas (per MMBtu)	$	1.97	$	2.87
Oil (per Bbl)	Oil (per Bbl)	$	55.77	$	63.00	Oil (per Bbl)	$	43.40	$	57.77
NGLs (per Bbl)	NGLs (per Bbl)	$	9.96	$	17.65	NGLs (per Bbl)	$	9.26	$	12.59

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 exceeded the ceiling by ~~$1.5 billion~~$361 million at ~~March 31,~~September 30, 2020, resulting in a non-cash ceiling test impairment. In the first and second quarters of 2020, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $1.48 billion and $650 million, respectively, and resulted in a non-cash ceiling test impairments. 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. Given the decline in commodity prices in late 2019 and ~~early~~the first three quarters of 2020, ~~the Company expects that~~ an additional non-cash impairment of ~~its~~the Company’s assets ~~will likely~~may occur in the ~~second~~fourth quarter of 2020.

For the nine months ended September 30, 2020, the Company recognized a $5 million impairment related to other non-core assets not included in natural gas and ~~perhaps later.~~oil properties.

The Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at ~~March 31,~~September 30, 2019, and the Company had 0 derivative positions that were designated for hedge accounting as of ~~March 31,~~September 30, 2019. In June 2019, the Company sold non-core acreage for $25 million. There was no production or proved reserves associated with this acreage.

~~(6)~~(7) EARNINGS PER SHARE

Basic earnings per common share is computed by dividing net income ~~attributable to common stock~~ 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, ~~performance~~restricted stock units and ~~the assumed conversion of mandatory convertible preferred stock.~~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.

In the first quarter of 2019, the Company repurchased 5,260,687 shares of its outstanding common stock as part of a share repurchase program for approximately $21 million at an average price of $3.84 per share.

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The following table presents the computation of earnings per share for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019:


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	(in millions, except share/per share amounts)	2020		2019		(in millions, except share/per share amounts)	2020		2019		2020		2019
Net income (loss)	Net income (loss)	$	(1,547)	$	594	Net income (loss)	$	(593)	$	49	$	(3,020)	$	781

Number of common shares:	Number of common shares:					Number of common shares:
Weighted average outstanding	Weighted average outstanding	540,308,491		539,721,751		Weighted average outstanding	571,872,413		539,221,101		551,162,559		539,315,170
Issued upon assumed exercise of outstanding stock options	Issued upon assumed exercise of outstanding stock options	—		—		Issued upon assumed exercise of outstanding stock options	0		0		0		0
Effect of issuance of non-vested restricted common stock	Effect of issuance of non-vested restricted common stock	—		665,435		Effect of issuance of non-vested restricted common stock	0		187,706		0		400,120
Effect of issuance of non-vested restricted units	Effect of issuance of non-vested restricted units	—		—		Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	Effect of issuance of non-vested performance units	—		933,301		Effect of issuance of non-vested performance units	0		629,380		0		727,359
Weighted average and potential dilutive outstanding	Weighted average and potential dilutive outstanding	540,308,491		541,320,487		Weighted average and potential dilutive outstanding	571,872,413		540,038,187		551,162,559		540,442,649

Earnings per common share	Earnings per common share					Earnings per common share
Basic	Basic	$	(2.86)	$	1.10	Basic	$	(1.04)	$	0.09	$	(5.48)	$	1.45
Diluted	Diluted	$	(2.86)	$	1.10	Diluted	$	(1.04)	$	0.09	$	(5.48)	$	1.44

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019, as they would have had an antidilutive effect:


		For the three months ended March 31,				For the three months ended September 30,		For the nine months ended September 30,
		2020	2019		2020	2019	2020	2019
Unexercised stock options	Unexercised stock options	4,584,563	5,128,640	Unexercised stock options	4,425,886	5,102,882	4,519,385	5,115,334
Unvested share-based payment	Unvested share-based payment	1,006,860	1,881,355	Unvested share-based payment	939,941	2,136,453	946,547	1,797,963
Restricted stock units	Restricted stock units	1,312,293	—	Restricted stock units	1,935,781	0	2,001,621	0
Performance units	Performance units	2,275,498	260,201	Performance units	2,282,211	240,450	2,027,985	247,443
Total	Total	9,179,214	7,270,196	Total	9,583,819	7,479,785	9,495,538	7,160,740

~~Table of Contents~~

~~(7)~~(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 ~~March 31,~~September 30, 2020, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps and call ~~options and~~options. The Company’s interest rate ~~swaps.~~swaps expired in June 2020. 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.

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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.

Call options			The Company purchases and sells call options in exchange for a premium. 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.

Interest rate swaps			Interest rate swaps ~~are~~were used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments iswas to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes. The Company’s interest rate swaps expired in June 2020.

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 91 0 for additional details regarding the Company’s fair value measurements of its derivative positions. The Company presents its derivative positions on a gross basis and does not net the asset and liability positions.

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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 ~~March 31,~~September 30, 2020:


Financial Protection on Production	Financial Protection on Production																												Financial Protection on Production
			Weighted Average Price per MMBtu																							Weighted Average Price per MMBtu
		Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2020 (in millions)				Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2020 (in millions)
Natural Gas	Natural Gas															Natural Gas
2020	2020															2020
Fixed price swaps	Fixed price swaps	279	$	2.50	$	—	$	—	$	—	$	—	$	181	⁽¹⁾	Fixed price swaps	91	$	2.46	$	—	$	—	$	—	$	—	$	16	(1)
Two-way costless collars	Two-way costless collars	23	—		—		2.50		2.79		—		3			Two-way costless collars	57	—		—		2.45		2.75		—		(7)
Three-way costless collars	Three-way costless collars	136	—		2.08		2.42		2.70		—		15			Three-way costless collars	25	—		2.19		2.58		2.96		—		(11)		(2)
Total	Total	438											$	199		Total	173											$	(2)
2021	2021															2021
Fixed price swaps	Fixed price swaps	36	$	2.53	$	—	$	—	$	—	$	—	$	5		Fixed price swaps	93	$	2.67	$	—	$	—	$	—	$	—	$	(13)
Two-way costless collars	Two-way costless collars	29	—		—		2.28		2.77		—		(1)			Two-way costless collars	166	—		—		2.51		2.89		—		(27)
Three-way costless collars	Three-way costless collars	265	—		2.18		2.49		2.84		—		(20)			Three-way costless collars	291	—		2.16		2.49		2.84		—		(113)		(3)
Total	Total	330											$	(16)		Total	550											$	(153)
2022	2022															2022
Fixed price swaps																Fixed price swaps	37	$	2.75	$	—	$	—	$	—	$	—	$	(2)
Two-way costless collars	Two-way costless collars	29	$	—	$	—	$	2.10	$	2.83	$	—	$	—		Two-way costless collars	32	—		—		2.17		2.88		—		(5)
Three-way costless collars	Three-way costless collars	91	—		2.10		2.46		2.86		—		(2)			Three-way costless collars	116	—		2.07		2.44		2.87		—		(24)
Total	Total	120											$	(2)		Total	185											$	(31)
2023	2023															2023

Three-way costless collars	Three-way costless collars	2	$	—	$	2.15	$	2.55	$	3.35	$	—	$	—		Three-way costless collars	25	$	—	$	2.07	$	2.48	$	3.18	$	—	$	(2)

Basis Swaps	Basis Swaps															Basis Swaps
2020	2020	199	$	—	$	—	$	—	$	—	$	(0.44)	$	(3)		2020	66	$	—	$	—	$	—	$	—	$	(0.37)	$	21
2021	2021	103	—		—		—		—		(0.03)		12			2021	155	—		—		—		—		(0.12)		21
2022	2022	88	—		—		—		—		(0.48)		(4)			2022	127	—		—		—		—		(0.38)		4
Total	Total	390											$	5		Total	348											$	46

(1)Includes $9$1 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at ~~March 31,~~September 30, 2020. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

(2)Includes $2 million in deferred premiums related to certain natural gas three-way costless collars recognized as a component of derivative liabilities within current liabilities on the consolidated balance sheet at September 30, 2020. As certain three-way costless collars settle, the premium will be paid and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.

(3)Includes $1 million in deferred premiums related to certain natural gas three-way costless collars recognized as a component of derivative liabilities within current liabilities on the consolidated balance sheet at September 30, 2020. As certain three-way costless collars settle, the premium will be paid and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.

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		Volume (MBbls)	Weighted Average Strike Price per Bbl																						Fair Value at March 31, 2020 (in millions)			Volume (MBbls)				Weighted Average Strike Price per Bbl								Fair Value at September 30, 2020 (in millions)
					Swaps			Sold Puts			Purchased Puts			Sold Calls					Fair Value at March 31, 2020 (in millions)	Volume (MBbls)				Swaps						Purchased Puts				Sold Calls				Fair Value at September 30, 2020 (in millions)
Oil	Oil																Oil
2020	2020																2020
Fixed price swaps⁽¹⁾	Fixed price swaps⁽¹⁾	2,442	$	57.75		$	—		$	—		$	—		$	66	Fixed price swaps (1)	584				$	75.44			$	—			$	—			$	—			$	20
Two-way costless collars	Two-way costless collars	731	—			—			56.88			59.81			19		Two-way costless collars	261		—				—				56.76				59.75				4
Three-way costless collars	Three-way costless collars	1,210	—			43.94			53.17			58.05			9		Three-way costless collars	404		—				43.71				52.85				57.78				3
Total	Total	4,383													$	94	Total	1,249																		$	27
2021	2021																2021
Fixed price swaps	Fixed price swaps	2,328	$	53.72		$	—		$	—		$	—		$	39	Fixed price swaps	2,574		$	52.84			$	—			$	—			$	—			$	27
Three-way costless collars	Three-way costless collars	1,445	—			43.52			53.25			58.14			10		Three-way costless collars	1,445		—				43.52				53.25				58.14				8
Total	Total	3,773													$	49	Total	4,019																		$	35
2022	2022																2022
Fixed price swaps	Fixed price swaps	438	$	51.74		$	—		$	—		$	—		$	5	Fixed price swaps	762		$	48.85			$	—			$	—			$	—			$	4
Three-way costless collars	Three-way costless collars	666	—			42.50			53.20			58.00			4		Three-way costless collars	666		—				42.50				53.20				58.00				2
Total	Total	1,104													$	9	Total	1,428																		$	6
2023																	2023
Three-way costless collars																	Three-way costless collars	111		$	—			$	30.00			$	40.00			$	57.85			$	0

Ethane	Ethane																Ethane
2020	2020																2020
Fixed price swaps	Fixed price swaps	6,952	$	8.59		$	—		$	—		$	—		$	21	Fixed price swaps	2,629		$	8.62			$	—			$	—			$	—			$	0
2021	2021																2021
Fixed price swaps	Fixed price swaps	3,017	$	7.40		$	—		$	—		$	—		$	2	Fixed price swaps	5,889		$	7.12			$	—			$	—			$	—			$	(12)
Two-way costless collar																	Two-way costless collar	584		—				—				7.14				10.40				0
Total																	Total	6,473																		$	(12)
2022																	2022
Fixed price swaps																	Fixed price swaps	190		$	7.41			$	—			$	—			$	—			$	0
Two-way costless collar																	Two-way costless collar	135		—				—				7.56				9.66				0
Total																	Total	325																		$	0

Propane	Propane																Propane
2020	2020																2020
Fixed price swaps	Fixed price swaps	4,049	$	23.06		$	—		$	—		$	—		$	43	Fixed price swaps	1,435		$	23.11			$	—			$	—			$	—			$	2
Two-way costless collars	Two-way costless collars	275	—			—			25.20			29.40			4		Two-way costless collars	92		—				—				25.20				29.40				0
Total	Total	4,324													$	47	Total	1,527																		$	2
2021	2021																2021
Fixed price swaps	Fixed price swaps	2,460	$	21.77		$	—		$	—		$	—		$	17	Fixed price swaps	4,298		$	19.99			$	—			$	—			$	—			$	(3)
2022																	2022
Fixed price swaps																	Fixed price swaps	156		$	19.25			$	—			$	—			$	—			$	0

Normal Butane																	Normal Butane
2020																	2020
Fixed price swaps																	Fixed price swaps	195		$	22.44			$	—			$	—			$	—			$	0

Natural Gasoline																	Natural Gasoline
2020																	2020
Fixed price swaps																	Fixed price swaps	184		$	34.59			$	—			$	—			$	—			$	0

(1)Includes ~~186~~448 MBbls of purchased fixed price oil swaps at ~~$57.46~~$33.94 per barrel with a fair value of ~~($5)~~$3 million and ~~2,628~~1,032 MBbls of sold fixed price oil swaps at ~~$57.73~~$57.44 per barrel with a fair value of ~~$71~~$17 million.

Other Derivative Contracts

Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
March 31, 2020
(in millions)
Sold Call Options – Natural Gas (Net)
2020 51 $ 2.83 $ (2)
2021 57 3.15 (7)
2022 58 3.00 (6)
2023 17 2.84 (3)
2024 9 3.00 (2)
Total 192 $ (20)

໿

Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
March 31, 2020
(in millions)
Sold Call Options – Oil
2021 226 $ 60.00 $ —

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Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
March 31, 2020
(in millions)
Swaps Basis Differential
Storage ⁽¹⁾

2020
Purchased fixed price swaps 3 $ 2.00 $ — $ (1)
Purchased basis swaps 1 — (0.49) —
Sold fixed price swaps 2 1.99 — —
Sold basis swaps 1 — (0.51) —
Total 7 $ (1)
2021
Purchased fixed price swaps 1 $ 2.04 $ — $ —
Sold fixed price swaps 2 2.49 — —
Sold basis swaps 1 — (0.38) —
Total 4 $ —


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2020 (in millions)





Call Options – Natural Gas (Net)
2020	6	$	3.15	$	(2)
2021	57	3.15		(17)
2022	58	3.00		(15)
2023	17	2.84		(4)
2024	9	3.00		(2)
Total	147			$	(40)

໿


	Volume (MBbls)	Weighted Average Strike Price per Bbl		Fair Value at September 30, 2020 (in millions)
Call Options – Oil
2021	226	$	60.00	$	0


	Volume (Bcf)	Weighted Average Strike Price per MMBtu				Fair Value at September 30, 2020 (in millions)
		Swaps		Basis Differential
Storage (1)
2020
Purchased fixed price swaps	1	$	1.94	$	0	$	0
Purchased basis swaps	0	0		(0.63)		0
Fixed price swaps	0	2.09		0		0
Basis swaps	0	0		(0.70)		0
Total	1					$	0
2021
Purchased fixed price swaps	1	$	2.04	$	0	$	0
Fixed price swaps	2	2.49		0		(1)
Basis swaps	1	0		(0.38)		0
Total	4					$	(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⁾	Purchased Fixed Price Swaps – Marketing (Natural Gas) ⁽¹⁾	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2020 (in millions)		Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2020 (in millions)
2020	2020	6	$	2.44	$	(2)	2020	2	$	2.44	$	0
2021	2021	6	2.44		—		2021	6	2.44		3
Total	Total	12			$	(2)	Total	8			$	3

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

At ~~March 31,~~September 30, 2020, the net fair value of the Company’s financial instruments related to commodities was a ~~$402~~$125 million ~~asset~~liability and included a net reduction of ~~less than~~the liability of $1 million related to non-performance risk. See Note 9 10 for additional details regarding the Company’s fair value measurements of its derivative positions.

As of ~~March 31,~~September 30, 2020, 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 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. ~~The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period.~~ Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The Company iswas a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps ~~have~~had a notional amount of $170 million and ~~expire~~expired in June 2020. Changes in the fair value of the interest rate swaps ~~are~~were included in gain (loss) on derivatives on the consolidated statements of operations. ~~At March 31, 2020, the net fair value of the Company’s interest rate swaps was a $1 million liability.~~

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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 ~~March 31,~~September 30, 2020 and December 31, 2019:


Derivative Assets	Derivative Assets								Derivative Assets
			Fair Value											Fair Value
(in millions)	(in millions)	Balance Sheet Classification	March 31, 2020			December 31, 2019			(in millions)	Balance Sheet Classification	September 30, 2020			December 31, 2019
Derivatives not designated as hedging instruments:	Derivatives not designated as hedging instruments:								Derivatives not designated as hedging instruments:

Purchased fixed price swaps – natural gas	Purchased fixed price swaps – natural gas	Derivative assets	$	1		$	—		Purchased fixed price swaps – natural gas	Derivative assets	$	3		$	0

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative assets	181		⁽¹⁾	77		⁽¹⁾	Fixed price swaps – natural gas	Derivative assets	21		(1)	77		(1)
Fixed price swaps – oil	Fixed price swaps – oil	Derivative assets	80			4			Fixed price swaps – oil	Derivative assets	42			4
Fixed price swaps – ethane	Fixed price swaps – ethane	Derivative assets	22			11			Fixed price swaps – ethane	Derivative assets	2			11
Fixed price swaps – propane	Fixed price swaps – propane	Derivative assets	48			21			Fixed price swaps – propane	Derivative assets	5			21
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Derivative assets	13			10			Two-way costless collars – natural gas	Derivative assets	27			10
Two-way costless collars – oil	Two-way costless collars – oil	Derivative assets	28			5			Two-way costless collars – oil	Derivative assets	6			5
Two-way costless collars – propane	Two-way costless collars – propane	Derivative assets	4			2			Two-way costless collars – propane	Derivative assets	0			2
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Derivative assets	189			126			Three-way costless collars – natural gas	Derivative assets	64		(2)	126
Three-way costless collars – oil	Three-way costless collars – oil	Derivative assets	36			3			Three-way costless collars – oil	Derivative assets	19			3
Basis swaps – natural gas	Basis swaps – natural gas	Derivative assets	22			17			Basis swaps – natural gas	Derivative assets	40			17
Purchased call options – natural gas		Derivative assets	3			1
Call options – natural gas									Call options – natural gas	Derivative assets	9			1
Fixed price swaps – natural gas storage	Fixed price swaps – natural gas storage	Derivative assets	—			1			Fixed price swaps – natural gas storage	Derivative assets	0			1

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Other long-term assets	5			7			Fixed price swaps – natural gas	Other long-term assets	1			7
Fixed price swaps – oil	Fixed price swaps – oil	Other long-term assets	35			1			Fixed price swaps – oil	Other long-term assets	10			1
Fixed price swaps – ethane		Other long-term assets	1			—

Fixed price swaps – propane	Fixed price swaps – propane	Other long-term assets	12			3			Fixed price swaps – propane	Other long-term assets	1			3
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Other long-term assets	5			4			Two-way costless collars – natural gas	Other long-term assets	13			4

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Other long-term assets	71			74			Three-way costless collars – natural gas	Other long-term assets	56			74
Three-way costless collars – oil	Three-way costless collars – oil	Other long-term assets	29			7			Three-way costless collars – oil	Other long-term assets	14			7
Basis swaps – natural gas	Basis swaps – natural gas	Other long-term assets	5			15			Basis swaps – natural gas	Other long-term assets	13			15
Purchased call options – natural gas		Other long-term assets	1			2
Call options – natural gas									Call options – natural gas	Other long-term assets	4			2
Total derivative assets	Total derivative assets		$	791		$	391		Total derivative assets		$	350		$	391

(1) Includes $1 million and $9 million at September 30, 2020 and December 31, 2019, respectively, in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance ~~sheet at both March 31, 2020 and December 31, 2019.~~sheet. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

(2)Includes $3 million as of September 30, 2020 in deferred premiums related to certain natural gas three-way costless collars recognized as a component of derivative liabilities within current liabilities on the consolidated balance sheet. As certain natural gas three-way costless collars settle, the premium will be paid and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

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Derivative Liabilities	Derivative Liabilities						Derivative Liabilities
			Fair Value								Fair Value
(in millions)	(in millions)	Balance Sheet Classification	March 31, 2020		December 31, 2019		(in millions)	Balance Sheet Classification	September 30, 2020		December 31, 2019
Derivatives not designated as hedging instruments:	Derivatives not designated as hedging instruments:						Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Purchased fixed price swaps – natural gas	Derivative liabilities	$	3	$	1	Purchased fixed price swaps – natural gas	Derivative liabilities	$	0	$	1
Purchased fixed price swaps – oil		Derivative liabilities	5		—

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Derivative liabilities	—		1		Fixed price swaps – natural gas	Derivative liabilities	15		1
Fixed price swaps – oil	Fixed price swaps – oil	Derivative liabilities	—		6		Fixed price swaps – oil	Derivative liabilities	1		6

Fixed price swaps – ethane							Fixed price swaps – ethane	Derivative liabilities	10		0
Fixed price swaps – propane							Fixed price swaps – propane	Derivative liabilities	5		0
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Derivative liabilities	10		4		Two-way costless collars – natural gas	Derivative liabilities	52		4
Two-way costless collars – oil	Two-way costless collars – oil	Derivative liabilities	9		5		Two-way costless collars – oil	Derivative liabilities	2		5
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Derivative liabilities	194		84		Three-way costless collars – natural gas	Derivative liabilities	164		84
Three-way costless collars – oil	Three-way costless collars – oil	Derivative liabilities	24		4		Three-way costless collars – oil	Derivative liabilities	10		4
Basis swaps – natural gas	Basis swaps – natural gas	Derivative liabilities	12		17		Basis swaps – natural gas	Derivative liabilities	3		17
Sold call options – natural gas		Derivative liabilities	9		3
Interest rate swaps		Derivative liabilities	1		—
Purchased fixed price swaps – natural gas storage		Derivative liabilities	1		—
Call options – natural gas							Call options – natural gas	Derivative liabilities	24		3

Fixed price swaps – natural gas storage							Fixed price swaps – natural gas storage	Derivative liabilities	1		0
Fixed price swaps – natural gas							Fixed price swaps – natural gas	Long-term derivative liabilities	6		0
Fixed price swaps – oil	Fixed price swaps – oil	Other long-term liabilities	—		2		Fixed price swaps – oil	Long-term derivative liabilities	0		2
Fixed price swaps – ethane							Fixed price swaps – ethane	Long-term derivative liabilities	4		0
Fixed price swaps – propane							Fixed price swaps – propane	Long-term derivative liabilities	2		0
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Other long-term liabilities	6		4		Two-way costless collars – natural gas	Long-term derivative liabilities	27		4

Three-way costless collars – natural gas	Three-way costless collars – natural gas	Other long-term liabilities	73		72		Three-way costless collars – natural gas	Long-term derivative liabilities	106		72
Three-way costless collars – oil	Three-way costless collars – oil	Other long-term liabilities	18		8		Three-way costless collars – oil	Long-term derivative liabilities	10		8
Basis swap – natural gas	Basis swap – natural gas	Other long-term liabilities	10		9		Basis swap – natural gas	Long-term derivative liabilities	4		9
Sold call options – natural gas		Other long-term liabilities	15		15
Sold call options – oil		Other long-term liabilities	—		1
Call options – natural gas							Call options – natural gas	Long-term derivative liabilities	29		15
Call options – oil							Call options – oil	Long-term derivative liabilities	0		1
Total derivative liabilities	Total derivative liabilities		$	390	$	236	Total derivative liabilities		$	475	$	236

1820

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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 nine months ended ~~March 31,~~September 30, 2020 and 2019:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings	Unsettled Gain (Loss) on Derivatives Recognized in Earnings																	Unsettled Gain (Loss) on Derivatives Recognized in Earnings

Derivative Instrument		Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled	For the three months ended March 31,
										Consolidated statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled				For the three months ended September 30,							For the nine months ended September 30,
Derivative Instrument	Derivative Instrument	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled					2020					2019	Derivative Instrument			Consolidated statement of Operations Classification of Gain (Loss) on Derivatives, Unsettled			2020				2019				2020				2019

			(in millions)														(in millions)
Purchased fixed price swaps – natural gas	Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(1)	$	—	Purchased fixed price swaps – natural gas			Gain (Loss) on Derivatives				$	4				$	0			$	4			$	0
Purchased fixed price swaps – oil		Gain (Loss) on Derivatives	(5)		4

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Gain (Loss) on Derivatives	103		(2)		Fixed price swaps – natural gas			Gain (Loss) on Derivatives				(138)			(19)				(74)				36
Fixed price swaps – oil	Fixed price swaps – oil	Gain (Loss) on Derivatives	118		(13)		Fixed price swaps – oil			Gain (Loss) on Derivatives				(20)			8				54				5
Fixed price swaps – ethane	Fixed price swaps – ethane	Gain (Loss) on Derivatives	12		7		Fixed price swaps – ethane			Gain (Loss) on Derivatives				(13)			1				(23)				8
Fixed price swaps – propane	Fixed price swaps – propane	Gain (Loss) on Derivatives	36		(4)		Fixed price swaps – propane			Gain (Loss) on Derivatives				(17)			10				(25)				19
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(4)		(1)		Two-way costless collars – natural gas			Gain (Loss) on Derivatives				(34)			(11)				(45)				(2)
Two-way costless collars – oil	Two-way costless collars – oil	Gain (Loss) on Derivatives	19		(7)		Two-way costless collars – oil			Gain (Loss) on Derivatives				(5)			0				4				(3)
Two-way costless collars – propane	Two-way costless collars – propane	Gain (Loss) on Derivatives	2		—		Two-way costless collars – propane			Gain (Loss) on Derivatives				(1)			1				(2)				3
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(51)		2		Three-way costless collars – natural gas			Gain (Loss) on Derivatives				(98)		(1)	3				(194)		(1)		27
Three-way costless collars – oil	Three-way costless collars – oil	Gain (Loss) on Derivatives	25		—		Three-way costless collars – oil			Gain (Loss) on Derivatives				(4)			3				15				4
Basis swaps – natural gas	Basis swaps – natural gas	Gain (Loss) on Derivatives	(1)		(10)		Basis swaps – natural gas			Gain (Loss) on Derivatives				54			12				40				6
Purchased call options – natural gas		Gain (Loss) on Derivatives	1		—
Sold call options – natural gas		Gain (Loss) on Derivatives	(6)		2
Sold call options – oil		Gain (Loss) on Derivatives	1		—
Call options – natural gas							Call options – natural gas			Gain (Loss) on Derivatives				(16)			1				(25)				5

Call options – oil							Call options – oil			Gain (Loss) on Derivatives				0			0				1				0
Purchased fixed price swap – natural gas storage	Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives	(1)		—		Purchased fixed price swap – natural gas storage			Gain (Loss) on Derivatives				1			0				0				0
Fixed price swap – natural gas storage	Fixed price swap – natural gas storage	Gain (Loss) on Derivatives	(1)		—		Fixed price swap – natural gas storage			Gain (Loss) on Derivatives				(2)			2				(2)				1
Interest rate swaps	Interest rate swaps	Gain (Loss) on Derivatives	(1)		—		Interest rate swaps			Gain (Loss) on Derivatives				0			1				0				(1)
Total gain (loss) on unsettled derivatives	Total gain (loss) on unsettled derivatives				$	246		$	(22)		Total gain (loss) on unsettled derivatives						$	(289)			$	12			$	(272)			$	108

Settled Gain (Loss) on Derivatives Recognized in Earnings ⁽¹⁾⁽²⁾	Settled Gain (Loss) on Derivatives Recognized in Earnings ⁽¹⁾⁽²⁾																	Settled Gain (Loss) on Derivatives Recognized in Earnings ⁽¹⁾⁽²⁾

Derivative Instrument		Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled	For the three months ended March 31,
										Consolidated statement of Operations Classification of Gain (Loss) on Derivatives, Settled				For the three months ended September 30,							For the nine months ended September 30,
Derivative Instrument	Derivative Instrument	Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, Settled					2020					2019	Derivative Instrument			Consolidated statement of Operations Classification of Gain (Loss) on Derivatives, Settled			2020				2019				2020				2019

			(in millions)														(in millions)
Purchased fixed price swaps – natural gas	Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(1)	$	—	Purchased fixed price swaps – natural gas			Gain (Loss) on Derivatives				$	(2)				$	0			$	(4)			$	0
Purchased fixed price swaps – oil		Gain (Loss) on Derivatives	—		(1)

Fixed price swaps – natural gas	Fixed price swaps – natural gas	Gain (Loss) on Derivatives	5		(6)		Fixed price swaps – natural gas			Gain (Loss) on Derivatives				61		(3)	45				150		(3)		53
Fixed price swaps – oil	Fixed price swaps – oil	Gain (Loss) on Derivatives	9		2		Fixed price swaps – oil			Gain (Loss) on Derivatives				17			3				44				5
Fixed price swaps – ethane	Fixed price swaps – ethane	Gain (Loss) on Derivatives	6		1		Fixed price swaps – ethane			Gain (Loss) on Derivatives				(2)			6				6				12
Fixed price swaps – propane	Fixed price swaps – propane	Gain (Loss) on Derivatives	10		2		Fixed price swaps – propane			Gain (Loss) on Derivatives				2			11				19				20
Two-way costless collars – natural gas	Two-way costless collars – natural gas	Gain (Loss) on Derivatives	6		(1)		Two-way costless collars – natural gas			Gain (Loss) on Derivatives				(5)			10				1				12
Two-way costless collars – oil	Two-way costless collars – oil	Gain (Loss) on Derivatives	3		1		Two-way costless collars – oil			Gain (Loss) on Derivatives				4			2				13				4
Two-way costless collars – propane	Two-way costless collars – propane	Gain (Loss) on Derivatives	1		—		Two-way costless collars – propane			Gain (Loss) on Derivatives				0			1				2				1
Three-way costless collars – natural gas	Three-way costless collars – natural gas	Gain (Loss) on Derivatives	36		(4)		Three-way costless collars – natural gas			Gain (Loss) on Derivatives				0			15				43				19
Three-way costless collars – oil	Three-way costless collars – oil	Gain (Loss) on Derivatives	1		—		Three-way costless collars – oil			Gain (Loss) on Derivatives				1			0				5				0
Basis swaps – natural gas	Basis swaps – natural gas	Gain (Loss) on Derivatives	16		(4)		Basis swaps – natural gas			Gain (Loss) on Derivatives				20			(3)				29				(11)

Call options – natural gas							Call options – natural gas			Gain (Loss) on Derivatives				0			(1)		(4)		0				(2)		(4)

Fixed price swaps – natural gas storage	Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	1		—		Fixed price swaps – natural gas storage			Gain (Loss) on Derivatives				1			(1)				2				(1)
Total gain (loss) on settled derivatives					$	93		$	(10)

Total gain on settled derivatives							Total gain on settled derivatives							$	97		$	88			$	310			$	112

Total gain (loss) on derivatives	Total gain (loss) on derivatives				$	339		$	(32)		Total gain (loss) on derivatives						$	(192)			$	100			$	38			$	220

(1)Includes $3 million in delayed premiums related to certain natural gas three-way costless collars for the three and nine months ended September 30, 2020, respectively, which is included in gain (loss) on derivatives on the consolidated statements of operations.

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

(3)Includes $4 million and $8 million amortization of premiums paid related to certain natural gas fixed price options for the three and nine months ended September 30, 2020, respectively, which is included in gain (loss) on derivatives on the consolidated statements of operations.

(4)Includes $1 million amortization of premiums paid related to certain natural gas purchased call options for the three and nine months ended September 30, 2019, which is included in gain (loss) on derivatives on the consolidated statements of operations.

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~~(8)~~(9) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

~~In the first quarter of 2020, changes~~Changes in accumulated other comprehensive income for the first nine months of 2020 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 ~~three~~nine months ended ~~March 31,~~September 30, 2020:


(in millions)	(in millions)	Pension and Other Postretirement		Foreign Currency		Total		(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2019	Beginning balance December 31, 2019	$	(19)	$	(14)	$	(33)	Beginning balance December 31, 2019	$	(19)	$	(14)	$	(33)
Other comprehensive income before reclassifications	Other comprehensive income before reclassifications	—		—		—		Other comprehensive income before reclassifications	0		0		0
Amounts reclassified from other comprehensive income ⁽¹⁾	Amounts reclassified from other comprehensive income ⁽¹⁾	—		—		—		Amounts reclassified from other comprehensive income (1)	1		0		1
Net current-period other comprehensive income	Net current-period other comprehensive income	—		—		—		Net current-period other comprehensive income	1		0		1
Ending balance March 31, 2020		$	(19)	$	(14)	$	(33)
Ending balance September 30, 2020								Ending balance September 30, 2020	$	(18)	$	(14)	$	(32)

Details about Accumulated Other Comprehensive Income

Affected Line Item in the Consolidated Statement of Operations

Amount Reclassified from Accumulated Other Comprehensive Income

For the nine months ended
September 30, 2020

(in millions)

Pension and other postretirement:

Amortization of prior service cost and net gain (1)

Other Income (Loss), Net

Provision (Benefit) for Income Taxes

Net Income (Loss)

Total reclassifications for the period

Net Income (Loss)

(1)~~Amounts reclassified from other comprehensive income to earnings were immaterial for the three months ended March 31, 2020.~~ See Note 131 4 for additional details regarding the Company’s pension and other postretirement benefit plans.

~~(9)~~(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 ~~March 31,~~September 30, 2020 and December 31, 2019 were as follows:


		March 31, 2020									December 31, 2019										September 30, 2020						December 31, 2019
(in millions)	(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value			(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	Cash and cash equivalents	$	5		$	5		$	5		$	5		Cash and cash equivalents	$	95		$	95		$	5		$	5
2018 revolving credit facility due April 2024	2018 revolving credit facility due April 2024	149			149			34			34			2018 revolving credit facility due April 2024	0			0			34			34
Senior notes⁽¹⁾	Senior notes⁽¹⁾	2,148			1,460			2,228			2,085			Senior notes (1)	2,471			2,429			2,228			2,085
Derivative instruments, net	Derivative instruments, net	401		⁽²⁾	401		⁽²⁾	155		⁽²⁾	155		⁽²⁾	Derivative instruments, net	(125)		(2)	(125)		(2)	155		(2)	155		(2)

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

(2)Includes $1 million and $9 million in premiums paid as of September 30, 2020 and December 31, 2019, respectively, related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet. Includes $3 million in deferred premiums as of September 30, 2020 related to certain natural gas three-way costless collars recognized as a component of derivative liabilities on the consolidated balance sheet.

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~~Company’s 4.10% Senior Notes

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due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy. The fair values of the ~~Company's~~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

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outstanding derivative position. As of ~~March 31,~~September 30, 2020, the impact of non-performance risk on the fair value of the Company’s net derivative ~~asset~~liability position was a ~~net~~ reduction of ~~less than~~the liability of $1 million.

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 March 31, 2020 are based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s call 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.

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:


		March 31, 2020															September 30, 2020
		Fair Value Measurements Using:													Fair Value Measurements Using:
(in millions)	(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		(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	Assets									Assets
Purchased fixed price swaps	Purchased fixed price swaps	$	—	$	1	$	—	$	1	Purchased fixed price swaps	$	0	$	3	$	0	$	3
Fixed price swaps ⁽¹⁾	Fixed price swaps ⁽¹⁾	—		384		—		384		Fixed price swaps (1)	0		82		0		82
Two-way costless collars	Two-way costless collars	—		50		—		50		Two-way costless collars	0		46		0		46
Three-way costless collars		—		325		—		325
Three-way costless collars (2)										Three-way costless collars (2)	0		153		0		153
Basis swaps	Basis swaps	—		27		—		27		Basis swaps	0		53		0		53
Purchased call options		—		4		—		4
Call options										Call options	0		13		0		13

Liabilities	Liabilities									Liabilities
Purchased fixed price swaps		—		(8)		—		(8)

Fixed price swaps										Fixed price swaps	0		(43)		0		(43)
Two-way costless collars	Two-way costless collars	—		(25)		—		(25)		Two-way costless collars	0		(81)		0		(81)
Three-way costless collars	Three-way costless collars	—		(309)		—		(309)		Three-way costless collars	0		(290)		0		(290)
Basis swaps	Basis swaps	—		(22)		—		(22)		Basis swaps	0		(7)		0		(7)
Sold call options		—		(24)		—		(24)
Purchased fixed price swaps – storage		—		(1)		—		(1)
Interest rate swaps		—		(1)		—		(1)
Call options										Call options	0		(53)		0		(53)
Fixed price swaps – storage										Fixed price swaps – storage	0		(1)		0		(1)

Total⁽²⁾⁽³⁾	Total⁽²⁾⁽³⁾	$	—	$	401	$	—	$	401	Total⁽²⁾⁽³⁾	$	0	$	(125)	$	0	$	(125)

(2)Includes $3 million in deferred premiums related to certain natural gas three-way costless collars recognized as a component of derivative liabilities within current liabilities on the consolidated balance sheet as of September 30, 2020. As certain natural gas three-way costless collars settle, the premium will be paid and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

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

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		December 31, 2019															December 31, 2019
		Fair Value Measurements Using:													Fair Value Measurements Using:
(in millions)	(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		(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	Assets									Assets

Fixed price swaps ⁽¹⁾	Fixed price swaps ⁽¹⁾	$	—	$	124	$	—	$	124	Fixed price swaps (1)	$	0	$	124	$	0	$	124
Two-way costless collars	Two-way costless collars	—		21		—		21		Two-way costless collars	0		21		0		21
Three-way costless collars	Three-way costless collars	—		210		—		210		Three-way costless collars	0		210		0		210
Basis Swaps		—		32		—		32
Purchased call options		—		3		—		3
Basis swaps										Basis swaps	0		32		0		32
Call options										Call options	0		3		0		3
Fixed price swaps - storage	Fixed price swaps - storage	—		1		—		1		Fixed price swaps - storage	0		1		0		1
Liabilities	Liabilities									Liabilities
Purchased fixed price swaps	Purchased fixed price swaps	—		(1)		—		(1)		Purchased fixed price swaps	0		(1)		0		(1)
Fixed price swaps	Fixed price swaps	—		(9)		—		(9)		Fixed price swaps	0		(9)		0		(9)
Two-way costless collars	Two-way costless collars	—		(13)		—		(13)		Two-way costless collars	0		(13)		0		(13)
Three-way costless collars	Three-way costless collars	—		(168)		—		(168)		Three-way costless collars	0		(168)		0		(168)
Basis Swaps		—		(26)		—		(26)
Sold call options		—		(19)		—		(19)
Basis swaps										Basis swaps	0		(26)		0		(26)
Call options										Call options	0		(19)		0		(19)

Total	Total	$	—	$	155	$	—	$	155	Total	$	0	$	155	$	0	$	155

(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.

The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would use. There were no Level 3 derivatives in the ~~first~~third quarters of 2020 and 2019.

~~(10)~~

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(11) DEBT

The components of debt as of ~~March 31,~~September 30, 2020 and December 31, 2019 consisted of the following:


		March 31, 2020																	September 30, 2020
(in millions)	(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total		(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total

Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility due April 2024		$	149	$	—	⁽¹⁾	$	—	$	149
Variable rate (1.60% at September 30, 2020) 2018 revolving credit facility due April 2024											Variable rate (1.60% at September 30, 2020) 2018 revolving credit facility due April 2024	$	0	$	0	(1)	$	0	$	0
4.10% Senior Notes due March 2022	4.10% Senior Notes due March 2022	210		(1)			—		209		4.10% Senior Notes due March 2022	207		0			0		207
4.95% Senior Notes due January 2025⁽²⁾	4.95% Senior Notes due January 2025⁽²⁾	864		(5)			(1)		858		4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	7.50% Senior Notes due April 2026	621		(6)			—		615		7.50% Senior Notes due April 2026	618		(6)			0		612
7.75% Senior Notes due October 2027	7.75% Senior Notes due October 2027	453		(5)			—		448		7.75% Senior Notes due October 2027	440		(5)			0		435
8.375% Senior Notes due September 2028 (3)											8.375% Senior Notes due September 2028 (3)	350		(5)			0		345
Total long-term debt	Total long-term debt	$	2,297	$	(17)		$	(1)	$	2,279	Total long-term debt	$	2,471	$	(20)		$	(1)	$	2,450

		December 31, 2019																	December 31, 2019
(in millions)	(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total		(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:	Long-term debt:										Long-term debt:
Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	$	34	$	—	⁽¹⁾	$	—	$	34	Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	$	34	$	0	(1)	$	0	$	34
4.10% Senior Notes due March 2022	4.10% Senior Notes due March 2022	213		(1)			—		212		4.10% Senior Notes due March 2022	213		(1)			0		212
4.95% Senior Notes due January 2025⁽²⁾	4.95% Senior Notes due January 2025⁽²⁾	892		(5)			(1)		886		4.95% Senior Notes due January 2025 (2)	892		(5)			(1)		886
7.50% Senior Notes due April 2026	7.50% Senior Notes due April 2026	639		(7)			—		632		7.50% Senior Notes due April 2026	639		(7)			0		632
7.75% Senior Notes due October 2027	7.75% Senior Notes due October 2027	484		(6)			—		478		7.75% Senior Notes due October 2027	484		(6)			0		478
Total long-term debt	Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242	Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242

(1)At ~~March 31,~~September 30, 2020 and December 31, 2019, unamortized issuance expense of $10 million and $11 million, respectively, associated with the 2018 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.

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(2)~~At March 31, 2020 and December 31, 2019, respectively,~~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. ~~This rate has been in effect since January 2019.~~ On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which ~~has~~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 will be paid in January 2021.

(3)The $350 million of Senior Notes due 2028 are subject to special mandatory redemption if the Montage Merger does not close on or prior to February 12, 2021.

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, ~~at March 31,~~in October 2020, ~~had a~~the banks participating in the 2018 credit facility reaffirmed the elected borrowing base ~~of $2.1 billion with~~and aggregate ~~bank~~ commitments ~~of $2.0~~to be $1.8 billion. ~~The Company may utilize the credit facility in the form of loans and letters of credit.~~ The borrowing base is subject to redetermination at least twice a year, in April and October. On April 13, 2020, the banks participating in the 2018 credit facility redetermined the borrowing base to be $1.8 billion, which also changed the aggregate commitments to that amount. The 2018 credit facilityOctober, and is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in ~~the~~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 ~~1.50%~~1.75% to ~~2.50%~~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 ~~0.50%~~0.75% to ~~1.50%~~1.75% based on the Company’s utilization of the 2018 credit facility.

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In conjunction with the October 2020 redetermination process, the Company entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters:

•limit the Company’s unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions; and

•increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility.

In addition, certain amendments and redeterminations were made conditioned upon the closing of the Merger. Upon the closing of the Merger and satisfaction of related conditions and pursuant to the amendment and the semi-annual borrowing base redetermination, the elected borrowing base and total aggregate commitments will be increased to $2.0 billion, the maximum permitted lien amount based on provisions in certain of the Company’s senior note indentures, and the credit agreement will be further amended to, among other matters:

•include certain Montage entities owning gas and oil properties as guarantors to the 2018 credit facility; and

•deem any Montage letters of credit issued prior to the merger close to have been issued under 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, (i) with respect to each fiscal quarter ending during the period from June 30, 2018 through March 31, 2019, 4.50 to 1.00, (ii) with respect to each fiscal quarter ending during the period from June 30, 2019 through March 31, 2020, 4.25 to 1.00, and (iii) 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 ~~March 31,~~September 30, 2020, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility. Beginning late in the first quarter of 2020, decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions reduced the demand for

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oil-based products such as gasoline, jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between the Organization of Petroleum Exporting Countries (“OPEC”) and Russia on production levels, have caused a significant decline in commodity pricing since the beginning of 2020. Additionally, space to store oil and condensate production is reaching or may reach capacity in some areas, which has prompted purchasers of oil and condensate to reduce future purchase levels and, in some cases, to claim force majeure for purchases already contracted. Consequently, during the second half of April 2020, the Company received notices from two companies asserting force majeure and curtailing approximately 3,200 gross barrels per day of condensate. To the extent that this decreased demand for the Company’s commodities continues or storage for its production is not available, Southwestern expects to reduce production from or completely shut in portions of its currently producing wells. If the current market conditions persist or deteriorate further, the Company would proactively continue to adjust its activities and plans. Absent any actions taken by Southwestern, and under these conditions or if they worsen, current modeling indicates that the Company would not be in compliance with its Net Leverage Ratio covenant under the 2018 credit facility in late 2020. Under such circumstances, Southwestern would seek waivers or a modification of the covenant package from the lenders in advance of any covenant non-compliance. Additionally, the Company has other mitigating options including but not limited to the monetization of derivative asset positions, the reduction or elimination of non-essential expenditures or the sale of non-core assets.

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 ~~March 31,~~September 30, 2020, the Company had ~~$172~~$203 million in letters of credit and ~~$149 million~~0 borrowings outstanding under the 2018 credit facility. ~~As of April 28, 2020, the Company had been requested to post an additional $150 million in letters of credit related to firm transportation.~~ 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 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 the Company. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (“SOFR”).

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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. ~~At March 31, 2020,~~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. ~~This rate has been in effect since January 2019.~~ 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 will be paid in January 2021. In the event of future downgrades, the coupons for this series of notes have been capped at 6.95%.

In the first ~~quarter~~half of 2020, the Company repurchased $3$6 million of its 4.10% Senior Notes due 2022, ~~$28~~$36 million of its 4.95% Senior Notes due 2025, ~~$18~~$21 million of its 7.50% Senior Notes due 2026 and ~~$31~~$44 million of its 7.75% Senior Notes due 2027 for ~~$52~~$72 million, and recognized a ~~$28~~$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 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 are intended to be used, in conjunction with the net proceeds from the recent common stock offering and borrowings under the revolving credit facility, to fund a redemption of $510 million of Montage’s Notes in connection with the closing of the Merger. Pending the consummation of the Merger, a portion of these net proceeds has temporarily been used to repay revolving credit facility borrowings until the anticipated redemption of the Montage Notes. The 2028 Notes are subject to special mandatory redemption at par plus accrued and unpaid interest if the Merger does not close on or prior to February 12, 2021 or the Company determines in its sole discretion that the consummation of the Merger cannot or is not reasonably likely to be satisfied by February 12, 2021.

~~(11)~~

(12) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of ~~March 31,~~September 30, 2020, 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 ~~$7.6~~$7.1 billion, ~~$411~~$405 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 ~~$1.1~~$1.0 billion of that amount. As of ~~March 31,~~September 30, 2020, future payments under non-cancelable firm transportation and gathering agreements were as follows:


		Payments Due by Period																							Payments Due by Period
(in millions)	(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years		(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	Infrastructure currently in service	$	7,199	$	753	$	1,339	$	1,098	$	1,524	$	2,485	Infrastructure currently in service	$	6,704	$	582	$	1,308	$	1,078	$	1,411	$	2,325
Pending regulatory approval and/or construction ⁽¹⁾	Pending regulatory approval and/or construction ⁽¹⁾	411		1		17		23		74		296		Pending regulatory approval and/or construction (1)	405		3		9		23		52		318
Total transportation charges	Total transportation charges	$	7,610	$	754	$	1,356	$	1,121	$	1,598	$	2,781	Total transportation charges	$	7,109	$	585	$	1,317	$	1,101	$	1,463	$	2,643

(1)Based on estimated in-service dates as of ~~March 31,~~September 30, 2020.

In December 2018, the Company closed the Fayetteville Shale sale and retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of ~~March 31,~~

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September 30, 2020, approximately ~~$81~~$27 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately ~~$45~~$13 million through December 2020 depending on the buyer’s actual use, and has recorded a ~~$36~~$10 million liability for the estimated future payments, down from $46 million recorded at December 31, 2019.

In the first quarter of 2019, the Company agreed to ~~purchase~~acquire firm transportation contracts with pipelines in the Appalachian Basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments, which is presented in the table above; the ~~seller~~releasing shipper has agreed to reimburse $133 million of these commitments.

In February 2020, the Company was notified that the proposed Constitution pipeline project was cancelled and that the Company was released from a firm transportation agreement with its sponsor. Prior to its cancellation, the Company had contractual commitments totaling $512 million over the next 17 years related to the Constitution pipeline project.

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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.

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 ~~March 31,~~September 30, 2020, 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, ~~which remains pending.~~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 has accepted coverage. The Company denies all allegations and intends to continue to defend this case vigorously. The Company does not expect this case to have a material adverse effect on the results of operations, financial position or cash flows of the Company after taking insurance into account. Additionally, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible.

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. NaN material liabilities have been recognized in connection with these indemnifications.

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~~(12)~~(13) INCOME TAXES

The Company’s effective tax rate was approximately ~~(36)~~0% and (16)% for the three and nine months ended ~~March 31, 2020.~~September 30, 2020, respectively. The change in the effective tax rate for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 related to the effects of recording 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.

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Due to significant pricing declines and the material write-down of the carrying value of the Company’s natural gas and oil properties in ~~the three months ended March 31, 2020,~~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 ~~in the period~~ of $408 million for the increase in its valuation ~~allowance.~~allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. The Company also has 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.

The Company’s effective tax rate was approximately ~~(254)~~18% and (105)% for the three and nine months ended ~~March 31, 2019.~~September 30, 2019, respectively. The effective tax rate for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 was primarily the effect of releasing the valuation allowances previously recorded against the Company’s deferred tax assets. As of the first quarter of 2019, the Company had sustained and projected to sustain a three-year cumulative level of profitability. Based on this factor and other positive evidence available at the time, the Company concluded that it was more likely than not that the deferred tax assets would be realized and determined $522 million of the valuation allowance would be released during 2019, of which ~~$426~~$400 million was released on a discrete basis in the first ~~quarter~~nine months of 2019.

~~(13)~~(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. Net periodic pension costs include the following components for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019:


		Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended March 31,									Consolidated Statements of Operations Classification of Net Periodic Benefit Cost			For the three months ended September 30,						For the nine months ended September 30,
(in millions)	(in millions)				2020			2019		(in millions)	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost			2020			2019			2020			2019
Service cost	Service cost	General and administrative expenses	$	2		$	2	Service cost	General and administrative expenses			$	2		$	1		$	6		$	5
Interest cost	Interest cost	Other Income (Loss), Net	1			1		Interest cost	Other Income (Loss), Net			1			2			3			4
Expected return on plan assets	Expected return on plan assets	Other Income (Loss), Net	(1)			(2)		Expected return on plan assets	Other Income (Loss), Net			(2)			(1)			(5)			(4)
Amortization of prior service cost	Amortization of prior service cost	Other Income (Loss), Net	—			—		Amortization of prior service cost	Other Income (Loss), Net			0			0			0			0
Amortization of net loss	Amortization of net loss	Other Income (Loss), Net	—			1		Amortization of net loss	Other Income (Loss), Net			1			0			1			1

Settlement loss								Settlement loss	Other Income (Loss), Net			0			1			0			5
Net periodic benefit cost	Net periodic benefit cost		$	2		$	2	Net periodic benefit cost				$	2		$	3		$	5		$	11

The Company’s other postretirement benefit plan had a net periodic benefit cost of ~~$1 million and~~ less than $1 million for the three months ended ~~March 31,~~September 30, 2020 and 2019, respectively, and $2 million and $1 million for the nine months ended September 30, 2020 and 2019, respectively.

As of ~~March 31,~~September 30, 2020, the Company has contributed $5$12 million to the pension and other postretirement benefit plans and ~~expects~~does 0t expect to contribute ~~an additional $7 million~~ to its pension plan during the remainder of 2020. The Company recognized liabilities of ~~$27~~$22 million and ~~$13~~$14 million related to its pension and other postretirement benefits, respectively, as of ~~March 31,~~September 30, 2020, compared to liabilities of $30 million and $13 million as of December 31, 2019, respectively.

In the first nine months of 2019, the Company recognized a $5 million non-cash settlement loss related to $19 million of lump-sum payments from the pension plan for employees who were terminated as a result of the Fayetteville Shale sale.

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 3,632 shares and 5,115 shares at ~~March 31,~~September 30, 2020 and December 31, 2019, respectively.

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~~(14)~~(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. In March 2020, the Company issued its first long-term fixed cash-based awards. ~~The resulting impact to general and administrative expenses as well as capitalized expenses was immaterial for the first quarter~~

Table of ~~2020.~~Contents

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 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 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company’s organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. 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 nine months ended ~~March 31,~~September 30, 2020 and 2019:

For the three months ended March 31,
(in millions) 2020 2019
Stock-based compensation cost – expensed $ —
⁽¹⁾
$ 7
Stock-based compensation cost – capitalized —
⁽¹⁾
4

~~(1)For the three months ended March 31, 2020, a decrease in the value of liability-based awards approximately offset the amounts expensed and capitalized for equity-based awards.~~


	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Stock-based compensation cost – expensed	$	2	$	1	$	8	$	12
Stock-based compensation cost – capitalized	2		1		3		7

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019:


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Equity-classified awards – expensed	Equity-classified awards – expensed	$	1	$	2	Equity-classified awards – expensed	$	0	$	2	$	2	$	6
Equity-classified awards – capitalized	Equity-classified awards – capitalized	—		1		Equity-classified awards – capitalized	1		1		1		3

As of ~~March 31,~~September 30, 2020, there was $4$2 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 ~~0.9~~0.5 years.

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Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 and provides information for options outstanding and options exercisable as of ~~March 31,~~September 30, 2020:


		Number of Options	Weighted Average Exercise Price			Number of Options	Weighted Average Exercise Price
		(in thousands)				(in thousands)
Outstanding at December 31, 2019	Outstanding at December 31, 2019	4,635	$	15.26	Outstanding at December 31, 2019	4,635	$	15.26
Granted	Granted	—	$	—	Granted	0	$	0
Exercised	Exercised	—	$	—	Exercised	0	$	0
Forfeited or expired	Forfeited or expired	(62)	$	15.11	Forfeited or expired	(357)	$	7.06
Outstanding at March 31, 2020		4,573	$	15.27
Exercisable at March 31, 2020		4,478	$	15.48
Outstanding at September 30, 2020					Outstanding at September 30, 2020	4,278	$	15.95
Exercisable at September 30, 2020					Exercisable at September 30, 2020	4,278	$	15.95

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Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 and provides information for unvested shares as of ~~March 31,~~September 30, 2020:


		Number of Shares	Weighted Average Fair Value			Number of Shares	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested shares at December 31, 2019	Unvested shares at December 31, 2019	1,480	$	7.00	Unvested shares at December 31, 2019	1,480	$	7.00
Granted	Granted	12	$	2.42	Granted	570	$	2.88
Vested	Vested	(522)	$	7.75	Vested	(1,083)	$	5.30
Forfeited	Forfeited	(167)	$	8.59	Forfeited	(246)	$	7.71
Unvested shares at March 31, 2020		803	$	6.11
Unvested shares at September 30, 2020					Unvested shares at September 30, 2020	721	$	6.05

Equity-Classified Performance Units

The following table summarizes equity-classified performance unit activity for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 and provides information for unvested units as of ~~March 31,~~September 30, 2020. The performance unit awards granted in 2018 include a market condition based exclusively on the Total Shareholder Return (“TSR”), with their fair value calculated by a Monte Carlo model. The total fair value of the performance units is amortized to compensation expense on a straight line basis over the vesting period of the award. The grant date fair value is calculated using the closing price of the Company’s common stock at the grant date.


		Number of Units ⁽¹⁾	Weighted Average Fair Value			Number of Units (1)	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2019	Unvested units at December 31, 2019	178	$	10.47	Unvested units at December 31, 2019	178	$	10.47
Granted	Granted	—	$	—	Granted	0	$	0
Vested	Vested	(178)	$	10.47	Vested	(178)	$	10.47
Forfeited	Forfeited	—	$	—	Forfeited	0	$	0
Unvested units at March 31, 2020		—	$	—
Unvested units at September 30, 2020					Unvested units at September 30, 2020	0	$	0

(1)The actual payout of shares may range from a minimum of ~~zero~~0 shares to a maximum of ~~two~~2 shares per unit contingent upon TSR. The performance units have a ~~three-year~~three-year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the ~~three-year~~three-year vesting period.

Liability-Classified Awards

The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three and nine months ended ~~March 31,~~September 30, 2020:


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Liability-classified stock-based compensation cost – expensed	Liability-classified stock-based compensation cost – expensed	$	(1)	$	5	Liability-classified stock-based compensation cost – expensed	$	2	$	(1)	$	6	$	6
Liability-classified stock-based compensation cost – capitalized	Liability-classified stock-based compensation cost – capitalized	—		3		Liability-classified stock-based compensation cost – capitalized	1		0		2		4

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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 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 ~~March 31,~~September 30, 2020, there was ~~$26~~$21 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 ~~3.0~~2.5 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			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2019	Unvested units at December 31, 2019	12,992	$	2.42	Unvested units at December 31, 2019	12,992	$	2.42
Granted	Granted	6,172	$	1.41	Granted	6,172	$	1.41
Vested	Vested	(3,852)	$	1.38	Vested	(3,946)	$	1.42
Forfeited	Forfeited	(1,464)	$	1.67	Forfeited	(3,060)	$	1.53
Unvested units at March 31, 2020		13,848	$	1.69
Unvested units at September 30, 2020					Unvested units at September 30, 2020	12,158	$	2.17

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~~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. The fair values of the market conditions are calculated by Monte Carlo models on a quarterly basis. As of ~~March 31,~~September 30, 2020, there was ~~$15~~$14 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 ~~2.6~~2.2 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			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at December 31, 2019	Unvested units at December 31, 2019	5,142	$	2.42	Unvested units at December 31, 2019	5,142	$	2.42
Granted	Granted	6,172	$	1.41	Granted	6,172	$	1.41
Vested	Vested	—	$	—	Vested	0	$	0
Forfeited	Forfeited	—	$	—	Forfeited	(2,300)	$	3.06
Unvested units at March 31, 2020		11,314	$	1.69
Unvested units at September 30, 2020					Unvested units at September 30, 2020	9,014	$	2.10

Cash-Based Compensation

Performance Cash Awards

In 2020, the Company granted performance cash awards that vest over a ~~four-year~~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 2020 include a performance condition determined annually by the Company. In 2020, 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 ~~March 31,~~September 30, 2020, there was ~~$19~~$16 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average ~~3.9~~3.4 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.

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		Number of Units	Weighted Average Fair Value			Number of Units	Weighted Average Fair Value
		(in thousands)				(in thousands)
Unvested units at 12/31/2019		—	$	—
Unvested units at December 31, 2019					Unvested units at December 31, 2019	0	$	0
Granted	Granted	20,044	$	1.00	Granted	20,044	$	1.00
Vested	Vested	—	$	—	Vested	(100)	$	1.00
Forfeited	Forfeited	(135)	$	1.00	Forfeited	(729)	$	1.00
Unvested units at March 31, 2020		19,909	$	1.00
Unvested units at September 30, 2020					Unvested units at September 30, 2020	19,215	$	1.00

~~(15)~~(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 2019 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.~~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			E&P			Marketing		Other			Total

Three months ended March 31, 2020		(in millions)
													(in millions)
Three months ended September 30, 2020												Three months ended September 30, 2020
Revenues from external customers	Revenues from external customers	$	353		$	239	$	—		$	592	Revenues from external customers	$	308		$	219	$	0		$	527
Intersegment revenues	Intersegment revenues	(9)			309		—			300		Intersegment revenues	(10)			276		0			266
Depreciation, depletion and amortization expense	Depreciation, depletion and amortization expense	111			2		—			113		Depreciation, depletion and amortization expense	68			2		0			70
Impairments	Impairments	1,479			—		—			1,479		Impairments	361			0		0			361
Operating income (loss)		(1,486)		⁽¹⁾	(4)		—			(1,490)
Interest expense⁽²⁾		19			—		—			19
Gain on derivatives		339			—		—			339
Gain on early extinguishment of debt		—			—		28			28
Other income, net		1			—		—			1
Provision for income taxes ⁽²⁾		406			—		—			406
Assets		4,900		⁽³⁾	214		161		⁽⁴⁾	5,275
Capital investments⁽⁵⁾		237			—		—			237

Three months ended March 31, 2019
Revenues from external customers		$	551		$	439	$	—		$	990
Intersegment revenues		(9)			502		—			493
Depreciation, depletion and amortization expense		110			2		—			112

Operating income		210		⁽¹⁾	3		—			213
Operating loss												Operating loss	(379)		(1)	(2)		0			(381)
Interest expense⁽²⁾	Interest expense⁽²⁾	14			—		—			14		Interest expense (2)	22			0		0			22
Loss on derivatives	Loss on derivatives	(32)			—		—			(32)		Loss on derivatives	(192)			0		0			(192)

Other income, net	Other income, net	1			—		—			1		Other income, net	2			0		0			2
Benefit from income taxes⁽²⁾		(426)			—		—			(426)

Assets	Assets	5,562		⁽³⁾	342		542		⁽⁴⁾	6,446		Assets	3,705		(3)	240		212		(4)	4,157
Capital investments⁽⁵⁾	Capital investments⁽⁵⁾	325			—		—			325		Capital investments (5)	223			0		0			223

Three months ended September 30, 2019												Three months ended September 30, 2019
Revenues from external customers												Revenues from external customers	$	357		$	279	$	0		$	636
Intersegment revenues												Intersegment revenues	(9)			313		0			304
Depreciation, depletion and amortization expense												Depreciation, depletion and amortization expense	123			2		0			125
Impairments												Impairments	0			2		0			2
Operating loss												Operating loss	(21)		(1)	(8)		0			(29)
Interest expense (2)												Interest expense (2)	17			0		0			17
Gain on derivatives												Gain on derivatives	100			0		0			100
Gain on early extinguishment of debt												Gain on early extinguishment of debt	0			0		7			7
Other income (loss), net												Other income (loss), net	(4)			0		2			(2)
Provision for income taxes (2)												Provision for income taxes (2)	10			0		0			10
Assets												Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)												Capital investments (5)	239			0		1			240

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	E&P			Marketing		Other			Total

Nine months ended September 30, 2020	(in millions)
Revenues from external customers	$	884		$	645	$	0		$	1,529
Intersegment revenues	(31)			787		0			756
Depreciation, depletion and amortization expense	260			7		0			267
Impairments	2,495			0		0			2,495
Operating loss	(2,613)		(1)	(14)		0			(2,627)
Interest expense (2)	63			0		0			63
Gain on derivatives	38			0		0			38
Gain on early extinguishment of debt	0			0		35			35
Other income, net	2			0		1			3
Provision for income taxes (2)	406			0		0			406
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	705			0		0			705

Nine months ended September 30, 2019
Revenues from external customers	$	1,288		$	1,005	$	0		$	2,293
Intersegment revenues	(27)			1,154		0			1,127
Depreciation, depletion and amortization expense	345			7		0			352
Impairments	6			2		0			8
Operating income (loss)	219		(1)	(13)		0			206
Interest expense (2)	46			0		0			46
Gain on derivatives	220			0		0			220
Gain on early extinguishment of debt	0			0		7			7
Other income (loss), net	(8)			0		1			(7)
Benefit from income taxes (2)	(401)			0		0			(401)
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	931			0		2			933

(1)Operating income (loss) for the E&P segment includes ~~$10 million and $3~~$4 million of restructuring charges for the three months ended ~~March 31,~~September 30, 2019 and $12 million and $9 million of restructuring charges for the nine months ended September 30, 2020 and 2019, respectively. The E&P segment operating income (loss) also includes $3 million for the three and nine months ended September 30, 2020 related to acquisition-related charges.

(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. ~~For the three months ended March 31, 2019, this~~E&P assets also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

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(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At ~~March 31,~~September 30, 2020 and 2019, other assets included approximately $5$95 million and ~~$366~~$29 million, respectively, in cash and cash equivalents, ~~$32~~$74 million and ~~$68~~$84 million in right-of-use lease assets, respectively, ~~in income taxes receivable, $23~~$18 million and ~~$56~~$31 million, respectively, in property, plant and equipment, $10 million and ~~$10~~$9 million, respectively, in unamortized debt expense, ~~$9 million and $10 million, respectively, in prepayments,~~ $5 million and $7 million, respectively, in a non-qualified retirement plan and ~~$77~~$3 million and ~~$25~~$7 million in ~~right-of-use lease assets,~~prepayments, respectively. Additionally, the September 30, 2019 other asset balance includes $61 million in income taxes receivable and the September 30, 2020 other asset balance includes $7 million in account receivable assets.

(5)Capital investments include ~~increases~~decreases of $8$7 million and ~~$66~~$53 million for the three months ended ~~March 31,~~September 30, 2020 and 2019, respectively, and increases of $1 million and $52 million for the nine months ended September 30, 2020 and 2019, respectively, relating to the change in accrued expenditures between years.

(17) NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted

In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”), which modifies the disclosure requirements on fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. As a result of adoption, this standard did not have a material impact on the Company’s consolidated financial statements.

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments -– Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“Update 2016-13”). Update 2016-13 replaced the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to

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trade receivables. For public business entities, the new standard became effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period.

From an evaluation of the Company’s existing credit portfolio, which includes trade receivables from commodity sales, joint interest billings due from partners and other receivables and cash equivalents, historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business ~~partners.~~counterparties. Update 2016-13 did not have a significant impact on the Company’s consolidated financial statements or related control environment upon adoption on January 1, 2020.

Issued but Not Yet Adopted

In August 2018, the FASB issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). This ASU 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, with early adoption permitted. This ASU will result in expanded disclosures within the Company’s interim and annual footnote disclosures, however, the adoption of ASU 2018-14 is not expected to have a material impact on the Company’s consolidated financial statements.

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 2019 Annual Report and analyzes the changes in the results of operations between the three and nine month periods ended ~~March 31,~~September 30, 2020 and 2019. 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 2019 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, in Item 1A, “Risk Factors” in Part I and elsewhere in our 2019 Annual Report, and Item 1A, “Risk Factors” in Part II in this Quarterly Report and any other quarterly report on Form 10-Q filed during the fiscal year. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report.

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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 NGL 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” but previously referred to as “Midstream” when it included the operations of gathering systems. 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 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 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 and West Virginia are herein referred to as “Appalachia.” We also operate drilling rigs located in Pennsylvania and West Virginia, and we provide certain oilfield products and services, principally serving our E&P ~~operations~~activities through vertical integration.

On August 12, 2020, we entered into the Merger Agreement pursuant to which we will acquire all of the outstanding shares of common stock of Montage in exchange for 1.8656 shares of our common stock per share of Montage common stock. Upon the closing of the Merger, Montage will merge with and into Southwestern, with Southwestern continuing as the surviving company. The transaction is expected to close in the fourth quarter of 2020, subject to customary closing conditions, including the approval of the Montage shareholders. The Merger will expand our footprint in Appalachia by supplementing our Northeast Appalachia and Southwest Appalachia operations and by expanding our operations into Ohio.

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.

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Recent Financial and Operating Results

Significant ~~first~~third quarter 2020 operating and financial results include:

Total Company

•Net loss of ~~$1,547~~$593 million, or ($~~2.86)~~1.04) per diluted share, decreased compared to net income of ~~$594~~$49 million, or ~~$1.10~~$0.09 per diluted share, for the same period in 2019. The decrease was primarily due to a ~~$1,479~~$361 million non-cash full cost ceiling test impairment, ~~and~~ a ~~$408~~$292 million ~~tax valuation allowance, which were only partially offset by a $371 million positive~~reduction in the impact of derivatives ~~including~~(which included a ~~$103~~$9 million improvement in settled derivatives and a $301 million reduced impact of unsettled derivatives related to improved forward strip pricing across all commodities, as compared to the same period in ~~2019.~~2019) and lower margins associated with reduced commodity prices.

•Operating loss of ~~$1,490~~$381 million ~~decreased~~increased compared to operating ~~income~~loss of ~~$213~~$29 million for the same period in 2019 on a consolidated basis primarily due to a ~~$1,479~~$361 million non-cash full cost ceiling test impairment in the ~~first~~third quarter of 2020. Excluding the non-cash impairment, operating loss of ~~$11~~$20 million ~~decreased 105%~~improved $9 million compared to the same period in 2019 ~~primarily due to~~as lower margins associated with reduced commodity ~~prices.~~prices were more than offset by increased natural gas and liquids production, lower depreciation, depletion and amortization and general and administrative expenses.

•Net cash provided by operating activities of ~~$160~~$153 million decreased ~~64%~~22% from ~~$442~~$196 million for the same period in 2019 primarily due to the decrease in operating income net of depreciation, depletion and amortization and impairments, and a reduction in net cash flow associated with working capital, partially offset by the improvementas improvements in settled derivatives discussed ~~above.~~above and working capital combined with higher production was more than offset by lower commodity prices and an increase in operating expenses associated with higher liquids production, along with a decrease in capitalized interest expense.

•Total capital ~~investing~~investment of ~~$237~~$223 million decreased ~~27%~~7% from ~~$325~~$240 million for the same period in 2019.

•~~We repurchased $80~~Completion of a public offering of 63,250,000 shares of common stock at $2.50 per share with net proceeds of approximately $152 million inafter underwriting discounts and offering expenses.

•Closed an offering of $350 million aggregate principal amount of ~~our outstanding senior notes at a discount~~8.375% Senior Notes due 2028 with net proceeds of $345 million after underwriting discounts and ~~recognized a gain on the extinguishment of debt of $28 million.~~offering expenses.

E&P

•E&P segment operating loss of ~~$1,486~~$379 million ~~decreased~~increased from operating ~~income~~loss of ~~$210~~$21 million for the same period in 2019, primarily related to the non-cash full cost ceiling test impairment of ~~$1,479~~$361 million in the ~~first~~third quarter of ~~2020.~~2020 and lower margins associated with reduced commodity prices.

•Total net production of ~~201~~221 Bcfe, which was comprised of 78% natural gas and 22% oil and NGLs, increased ~~10%~~9% from ~~182~~202 Bcfe in the same period in 2019, and our liquids production increased ~~17%~~9% over the same period primarily associated with our ~~oil~~NGL production.

•Excluding the effect of derivatives, our realized natural gas price of ~~$1.53~~$1.09 per Mcf decreased ~~48%~~25%, our realized oil price of ~~$36.72~~$29.46 per barrel decreased ~~19%~~37% and our realized NGL price of ~~$8.16~~$10.34 per barrel ~~decreased 44%~~increased 16% as compared to the same period in 2019. ~~Our~~Excluding the effect of derivatives, our total weighted average realized price ~~excluding the effect~~ of ~~derivatives of $1.69~~$1.34 per Mcfe decreased ~~43%~~22% from the same period in 2019.

•E&P segment invested ~~$237~~$223 million in capital; drilling 3816 wells, completing 2225 wells and placing 1230 wells to sales.

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Outlook

We expect to continue to exercise capital discipline in our 2020 capital investment program, and we remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities, looking for ways to optimize our cost structure and maximize margins in each core area of our business and further developing our knowledge of our asset base. The proposed Merger and the associated expected cost and operational synergies is a reflection of this strategy.

Lower natural gas, oil and NGL prices present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described in “Risk Factors” in our 2019 Annual ~~Report.~~Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. During the first ~~quarter~~nine months of 2020, the economic impact of the COVID-19 pandemic and related governmental and societal measures (discussed below), along with the disagreements between OPEC and Russia on production levels, have caused oil prices to decrease ~~66%~~34% since the beginning of 2020. In ~~the~~ first ~~quarter~~nine months of 2020, gains on settled derivatives offset a large portion of the impact of the recent decline in prices, and as of ~~April 28,~~October 27, 2020, we currently have derivative positions in place for ~~81%~~over 90% of our expected remaining 2020 production. There can be no assurance that we will be able to add derivative positions to cover the remainder of our

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expected production at favorable prices. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 3 and Note 78 - Derivatives and Risk Management, in the consolidated financial statements included in this Quarterly Report for further details.

~~The Impact of COVID-19 on Our Business~~Market Conditions and Commodity Prices

During the first ~~quarter~~three quarters of 2020, 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. In early March 2020, we instituted additional health measures at our facilities and banned nonessential travel. In mid-March, in advance of state and local governments restricting business operations and imposing ~~“stay at home”~~“stay-at-home” directives in Pennsylvania, West Virginia and Texas (where our operations and offices are located), we notified employees that those whose work does not require a physical presence should work from home. ~~Almost all~~In late September 2020, based on the totality of the relevant data in each community, we reinstituted a phased return program of office-based employees, ~~working at our sites today are engaged in the physical drilling, completion and operation of wells,~~ and we have instituted additional measures designed to prevent the possible spread of the virus, including social distancing and appropriate personal protective ~~equipment (PPE).~~equipment. The Cybersecurity and Infrastructure Security Agency in 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.

Beginning late in the first quarter and extending into the third quarter of 2020, decreased transportation, manufacturing and general economic activity levels prompted by governmental and societal actions to COVID-19 reduced the demand for refined products such as gasoline, distillate and jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between OPEC and Russia on production levels, have caused a significant decline in commodity pricing since the beginning of 2020. Although prices for oil dropped substantially during ~~March~~the first three quarters of 2020, by early in the first quarter we had protected the price of 99% of our expected 2020 oil production through derivatives. ~~During the first quarter,~~In addition, although natural gas prices were not impacted as severely as oil prices, ~~and~~ as of ~~March 31,~~September 30, 2020, we have protected the price of approximately ~~87%~~96% of expected remaining 2020 gas production through derivatives. ~~However, as decreased transportation, manufacturing~~

Late in the second quarter of 2020 and ~~general economic activity levels prompted by COVID-19~~extending into the third quarter of 2020, certain states and ~~related governmental~~local governments began the process of loosening restrictions, allowing businesses to reopen and ~~societal actions have reduced the demand for oil-based products such as gasoline, jet fuel~~lifting stay-at-home orders. In addition, OPEC and other ~~refined products, as well as NGLs, space to store~~countries instituted oil production curtailments. During this same period, oil and ~~condensate~~NGL prices have improved from historic lows in April due to lower industry-wide production ~~is reaching or may reach capacity in some areas, which is prompting purchasers of oil and condensate to reduce future purchase~~ levels and ~~in some cases, to claim force majeure for purchases already contracted.~~increased export demand, respectively. Further, although the reduced production of natural gas associated with oil wells ~~has~~ dampened the effect of lower natural gas demand early in the second quarter, high natural gas storage inventories and lower LNG demand for U.S. cargoes led to a natural gas price decline late in the second quarter. During the third quarter of 2020, as more clarity emerged regarding the projected path for European natural gas storage, global LNG prices rallied substantially and signaled a resumption of U.S. LNG exports beginning in late September 2020. In addition, the recovery of U.S. natural gas production was less robust than most market estimates, lessening concerns of domestic storage balances exceeding capacity towards the end of the injection season in October 2020. As a result of these events, the demand and related pricing for natural gas ~~and liquefied natural gas to be exported has fallen. These situations may lead to production greater than storage capacity later~~have improved from earlier in the year, ~~depending on weather~~ and ~~other seasonal factors. In addition, commodity~~we continue to mitigate pricing ~~challenges may cause our production costs to exceed the revenues associated with such production. To the extent that this decreased demand~~risk for all of our commodities ~~continues and~~through our margins are not at acceptable levels or storage for our production is not available, we may have to reduce production from or completely shut in portions of our currently producing wells. The inability to sell our production or the decision to potentially reduce or shut in our production could materially and adversely affect our operating results and our ability to comply with the financial covenants under our 2018 credit facility.proactive derivative program.

~~There is uncertainty around the extent and duration of the disruption.~~ 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 highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, 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 are continually adjusting our 2020 capital investment program to take into account these changed conditions. If depressed market conditions return, we would proactively continue to adjust our activities and plans. Therefore, while ~~we expect~~ this matter ~~will likely~~could potentially disrupt our operations, the degree of the adverse financial impact cannot be reasonably estimated at this time.

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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.

E&P


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Revenues	Revenues	$	344	$	542	Revenues	$	298	$	348	$	853	$	1,261
Operating costs and expenses⁽¹⁾	Operating costs and expenses⁽¹⁾	1,830		332		Operating costs and expenses (1)	677		369		3,466		1,042
Operating income (loss)	Operating income (loss)	$	(1,486)	$	210	Operating income (loss)	$	(379)	$	(21)	$	(2,613)	$	219

Gain on derivatives, settled ⁽²⁾	Gain on derivatives, settled ⁽²⁾	$	93	$	(10)	Gain on derivatives, settled (2)	$	97	$	88	$	310	$	112

(1)Includes ~~$1,479~~$361 million and $2,490 million related to non-cash full cost ceiling test ~~impairment~~impairments for the three and nine months ended ~~March 31,~~September 30, 2020, respectively, and $5 million related to the non-cash impairment of other non-core assets for the nine months ended September 30, 2020.

(2)Represents the gain on settled commodity derivatives and is not included in operating income (loss).

Operating Income (Loss)

•~~Operating income (loss) for the~~ E&P segment ~~decreased $1,696~~operating loss increased $358 million for the three months ended ~~March 31,~~September 30, 2020, compared to the same period in 2019, primarily due to a ~~$1,479~~$361 million non-cash full cost ceiling test impairment. Excluding the ~~impact~~effect of the impairment, operating loss improved $3 million compared to the same period in 2019 primarily due to lower depreciation, depletion and amortization and general and administrative expenses, partially offset by lower margins associated with decreased commodity pricing.

•Operating income (loss) for the E&P segment decreased $2,832 million for the nine months ended September 30, 2020, compared to the same period in 2019, primarily due to $2,490 million of non-cash full cost ceiling test impairments. Excluding the impact of the ceiling test impairments, operating income (loss) decreased ~~$217~~$342 million compared to the same period in 2019 primarily due to lower margins associated with decreased commodity pricing.

Revenues

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


		Three months ended March 31,																						Three months ended September 30,
(in millions except percentages)	(in millions except percentages)	Natural Gas			Oil			NGLs			Total			(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues ⁽¹⁾	2019 sales revenues ⁽¹⁾	$	421		$	39		$	81		$	541		2019 sales revenues ⁽¹⁾	$	230		$	66		$	52		$	348
Changes associated with prices	Changes associated with prices	(221)			(12)			(39)			(272)			Changes associated with prices	(62)			(21)			9			(74)
Changes associated with production volumes	Changes associated with production volumes	39			25			8			72			Changes associated with production volumes	22			(6)			7			23
2020 sales revenues ⁽²⁾⁽¹⁾	2020 sales revenues ⁽²⁾⁽¹⁾	$	239		$	52		$	50		$	341		2020 sales revenues ⁽²⁾⁽¹⁾	$	190		$	39		$	68		$	297
Increase (decrease) from 2019	Increase (decrease) from 2019	(43)		%	33		%	(38)		%	(37)		%	Increase (decrease) from 2019	(17)		%	(41)		%	31		%	(15)		%


	Nine months ended September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues (2)	$	918		$	151		$	191		$	1,260
Changes associated with prices	(412)			(71)			(55)			(538)
Changes associated with production volumes	78			27			22			127
2020 sales revenues (3)	$	584		$	107		$	158		$	849
Decrease from 2019	(36)		%	(29)		%	(17)		%	(33)		%

(1)Excludes $1 million in other operating revenues for the three months ended ~~March 31,~~September 30, 2020 primarily related to gas balancing gains.

(2)Excludes $1 million in other operating revenues for the nine months ended September 30, 2019 primarily related to third-party water sales.

~~(2)~~(3)Excludes $3$4 million in other operating revenues for the ~~three~~nine months ended ~~March 31,~~September 30, 2020 primarily related to gains on purchaser imbalances associated with certain NGLs.

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Production Volumes


		For the three months ended March 31,					Increase/(Decrease)				For the three months ended September 30,				Increase/(Decrease)		For the nine months ended September 30,			Increase/(Decrease)
Production volumes:	Production volumes:	2020		2019				Production volumes:	2020		2019		Increase/(Decrease)	2020			2019		Increase/(Decrease)
Natural Gas (Bcf)	Natural Gas (Bcf)							Natural Gas (Bcf)
Northeast Appalachia	Northeast Appalachia	114		112		2%		Northeast Appalachia	121		118		3%		348		343		1%
Southwest Appalachia	Southwest Appalachia	42		31		35%		Southwest Appalachia	52		40		30%		139		106		31%

Total	Total	156		143		9%		Total	173		158		9%		487		449		8%

Oil (MBbls)	Oil (MBbls)							Oil (MBbls)
Southwest Appalachia	Southwest Appalachia	1,395		849		64%		Southwest Appalachia	1,290		1,413		(9)%		3,764		3,193		18%
Other	Other	4		5		(20)%		Other	4		6		(33)%		12		17		(29)%
Total	Total	1,399		854		64%		Total	1,294		1,419		(9)%		3,776		3,210		18%

NGL (MBbls)	NGL (MBbls)							NGL (MBbls)
Southwest Appalachia	Southwest Appalachia	6,127		5,602		9%		Southwest Appalachia	6,687		5,908		13%		18,924		17,003		11%
Other	Other	1		1		—%		Other	—		3		(100)%		2		8		(75)%
Total	Total	6,128		5,603		9%		Total	6,687		5,911		13%		18,926		17,011		11%

Production volumes by area: (Bcfe)	Production volumes by area: (Bcfe)							Production volumes by area: (Bcfe)
Northeast Appalachia	Northeast Appalachia	114		112		2%		Northeast Appalachia	121		118		3%		348		343		1%
Southwest Appalachia⁽¹⁾		87		70		24%
Southwest Appalachia								Southwest Appalachia	100		84		19%		275		227		21%

Total		201		182		10%
Total (1)								Total (1)	221		202		9%		623		570		9%

Production percentage: (Bcfe)	Production percentage: (Bcfe)							Production percentage: (Bcfe)
Natural gas	Natural gas	78	%	79	%			Natural gas	78	%	78	%			78	%	79	%
Oil	Oil	4	%	3	%			Oil	4	%	4	%			4	%	3	%
NGL	NGL	18	%	18	%			NGL	18	%	18	%			18	%	18	%

(1)Approximately 87221 Bcfe and 69201 Bcfe for the three months ended ~~March 31,~~September 30, 2020 and ~~March 31,~~2019, respectively, and 622 Bcfe and 569 Bcfe for the nine months ended September 30, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.

•~~Production volumes for our~~ E&P ~~segment~~production volumes increased by 19 Bcfe for the three months ended ~~March 31,~~September 30, 2020 compared to the same period in 2019, primarily due to a ~~24%~~19% increase in production volumes in Southwest Appalachia.

•E&P production volumes increased by 53 Bcfe for the nine months ended September 30, 2020 compared to the same period in 2019, primarily due to a 21% increase in production volumes in Southwest Appalachia.

•Oil production decreased 9% and NGL production increased ~~64% and 9%, respectively,~~13% for the three months ended ~~March 31,~~September 30, 2020, compared to the same period in 2019.

•Oil and NGL production increased 18% and 11%, respectively, for the nine months ended September 30, 2020, compared to the same period in 2019.

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 cannot control or 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 March 31,							Increase/(Decrease)					For the three months ended September 30,					Increase/(Decrease)			For the nine months ended September 30,				Increase/(Decrease)
		2020			2019						2020			2019			Increase/(Decrease)	2020				2019			Increase/(Decrease)
Natural Gas Price:	Natural Gas Price:									Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾	NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾	$	1.95		$	3.15		(38)%		NYMEX Henry Hub Price ($/MMBtu) (1)	$	1.98		$	2.23		(11)%		$	1.88		$	2.67		(30)%
Discount to NYMEX ⁽²⁾	Discount to NYMEX ⁽²⁾	(0.42)			(0.20)			(110)%		Discount to NYMEX (2)	(0.89)			(0.78)			14%		(0.68)			(0.63)			8%
Average realized gas price, excluding derivatives ($/Mcf)	Average realized gas price, excluding derivatives ($/Mcf)	$	1.53		$	2.95		(48)%		Average realized gas price, excluding derivatives ($/Mcf)	$	1.09		$	1.45		(25)%		$	1.20		$	2.04		(41)%
Gain (loss) on settled financial basis derivatives ($/Mcf)	Gain (loss) on settled financial basis derivatives ($/Mcf)	0.10			(0.03)					Gain (loss) on settled financial basis derivatives ($/Mcf)	0.12			(0.01)					0.06			(0.02)
Gain (loss) on settled commodity derivatives ($/Mcf)	Gain (loss) on settled commodity derivatives ($/Mcf)	0.31			(0.08)					Gain (loss) on settled commodity derivatives ($/Mcf)	0.31			0.43					0.39			0.18
Average realized gas price, including derivatives ($/Mcf)	Average realized gas price, including derivatives ($/Mcf)	$	1.94		$	2.84		(32)%		Average realized gas price, including derivatives ($/Mcf)	$	1.52		$	1.87		(19)%		$	1.65		$	2.20		(25)%

Oil Price:	Oil Price:									Oil Price:
WTI oil price ($/Bbl)	WTI oil price ($/Bbl)	$	46.17		$	54.90		(16)%		WTI oil price ($/Bbl)	$	40.93		$	56.45		(27)%		$	38.32		$	57.06		(33)%
Discount to WTI	Discount to WTI	(9.45)			(9.42)			—%		Discount to WTI	(11.47)			(9.91)			16%		(10.12)			(9.92)			2%
Average oil price, excluding derivatives ($/Bbl)	Average oil price, excluding derivatives ($/Bbl)	$	36.72		$	45.48		(19)%		Average oil price, excluding derivatives ($/Bbl)	$	29.46		$	46.54		(37)%		$	28.20		$	47.14		(40)%
Gain on settled derivatives ($/Bbl)	Gain on settled derivatives ($/Bbl)	9.25			2.34					Gain on settled derivatives ($/Bbl)	17.23			3.13					16.77			2.60
Average oil price, including derivatives ($/Bbl)	Average oil price, including derivatives ($/Bbl)	$	45.97		$	47.82		(4)%		Average oil price, including derivatives ($/Bbl)	$	46.69		$	49.67		(6)%		$	44.97		$	49.74		(10)%

NGL Price:	NGL Price:									NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	Average realized NGL price, excluding derivatives ($/Bbl)	$	8.16		$	14.45		(44)%		Average realized NGL price, excluding derivatives ($/Bbl)	$	10.34		$	8.89		16%		$	8.37		$	11.24		(26)%
Gain on settled derivatives ($/Bbl)	Gain on settled derivatives ($/Bbl)	2.62			0.60					Gain on settled derivatives ($/Bbl)	0.16			3.04					1.48			1.94
Average realized NGL price, including derivatives ($/Bbl)	Average realized NGL price, including derivatives ($/Bbl)	$	10.78		$	15.05		(28)%		Average realized NGL price, including derivatives ($/Bbl)	$	10.50		$	11.93		(12)%		$	9.85		$	13.18		(25)%
Percentage of WTI, excluding derivatives	Percentage of WTI, excluding derivatives	18		%	26		%			Percentage of WTI, excluding derivatives	25		%	16		%			22		%	20		%

Total Weighted Average Realized Price:	Total Weighted Average Realized Price:									Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	Excluding derivatives ($/Mcfe)	$	1.69		$	2.98		(43)%		Excluding derivatives ($/Mcfe)	$	1.34		$	1.72		(22)%		$	1.36		$	2.21		(38)%
Including derivatives ($/Mcfe)	Including derivatives ($/Mcfe)	$	2.16		$	2.92		(26)%		Including derivatives ($/Mcfe)	$	1.78		$	2.16		(18)%		$	1.86		$	2.41		(23)%

(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 hedges.

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, 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 78 to the consolidated financial statements, included in this Quarterly Report.

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The table below presents the amount of our future production in which the basis is protected as of ~~March 31,~~September 30, 2020:

Volume (Bcf) Basis Differential
Basis Swaps – Natural Gas
2020 199 $ (0.44)
2021 103 (0.03)
2022 88 (0.48)
Total 390
Physical NYMEX Sales Arrangements – Natural Gas
2020 178 $ (0.28)
2021 94 (0.29)
Total 272

~~Table of Contents~~


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas
2020	66	$	(0.37)
2021	155	(0.12)
2022	127	(0.38)
Total	348

Physical NYMEX Sales Arrangements – Natural Gas
2020	85	$	(0.21)
2021	181	(0.26)
2022	35	(0.37)
2023	18	(0.35)
2024	15	(0.50)
2025	12	(0.50)
Total	346

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of ~~March 31,~~September 30, 2020:


		Remaining 2020	Full Year 2021	Full Year 2022		Remaining 2020	Full Year 2021	Full Year 2022	Full Year 2023
Natural gas (Bcf)	Natural gas (Bcf)	438	330	120	Natural gas (Bcf)	173	550	185	25
Oil (MBbls)	Oil (MBbls)	4,383	3,773	1,104	Oil (MBbls)	1,249	4,019	1,428	111
Ethane (MBbls)	Ethane (MBbls)	6,952	3,017	—	Ethane (MBbls)	2,629	6,473	325	—
Propane (MBbls)	Propane (MBbls)	4,324	2,460	—	Propane (MBbls)	1,527	4,298	156	—
Normal Butane (MBbls)					Normal Butane (MBbls)	195	—	—	—
Natural Gasoline (MBbls)					Natural Gasoline (MBbls)	184	—	—	—
Total financial protection on future production (Bcfe)	Total financial protection on future production (Bcfe)	532	386	127	Total financial protection on future production (Bcfe)	208	639	196	26

We refer you to Note 78 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 March 31,					Increase/(Decrease)				For the three months ended September 30,					Increase/(Decrease)		For the nine months ended September 30,					Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)	2020		2019				(in millions except percentages)	2020		2019			Increase/(Decrease)	2020			2019			Increase/(Decrease)
Lease operating expenses	Lease operating expenses	$	194	$	166	17%		Lease operating expenses	$	203	$	189			7%	$	579	$	524			10%
General & administrative expenses	General & administrative expenses	23		34		(32)%		General & administrative expenses	27		39		(1)	(31)%		79		108		(1)	(27)%

Montage acquisition-related expenses								Montage acquisition-related expenses	3		—			100%		3		—			100%
Restructuring charges	Restructuring charges	10		3		233%		Restructuring charges	—		4			(100)%		12		9			33%
Taxes, other than income taxes	Taxes, other than income taxes	13		19		(32)%		Taxes, other than income taxes	15		14			7%		38		50			(24)%
Full cost pool amortization	Full cost pool amortization	106		103		3%		Full cost pool amortization	65		123			(47)%		248		328			(24)%
Non-full cost pool DD&A	Non-full cost pool DD&A	5		7		(29)%		Non-full cost pool DD&A	3		—			100%		12		17			(29)%
Impairments	Impairments	1,479		—		100%		Impairments	361		—			100%		2,495		6			41,483%
Total operating costs	Total operating costs	$	1,830	$	332	451%		Total operating costs	$	677	$	369		83%		$	3,466	$	1,042		233%

(1)Includes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $3 million of legal settlement charges for the three and nine months ended September 30, 2019.

For the three months ended March 31, Increase/
Average unit costs per Mcfe: 2020 2019 (Decrease)
Lease operating expenses ⁽¹⁾
$ 0.96 $ 0.90 7%
General & administrative expenses $ 0.11
⁽²⁾
$ 0.19
⁽³⁾
(42)%
Taxes, other than income taxes $ 0.07 $ 0.10 (30)%
Full cost pool amortization $ 0.53 $ 0.57 (7)%

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	For the three months ended September 30,						Increase/	For the nine months ended September 30,						Increase/
Average unit costs per Mcfe:	2020			2019			(Decrease)	2020			2019			(Decrease)
Lease operating expenses (1)	$	0.91		$	0.94		(3)%	$	0.93		$	0.92		1%
General & administrative expenses	$	0.12	(2)	$	0.15	(3)	(20)%	$	0.13	(2)	$	0.17	(3)	(24)%
Taxes, other than income taxes	$	0.07		$	0.08		(13)%	$	0.06		$	0.09		(33)%
Full cost pool amortization	$	0.29		$	0.58		(50)%	$	0.40		$	0.57		(30)%

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

(2)Excludes ~~a $10~~$3 million in Montage acquisition-related expenses for the three and nine months ended September 30, 2020 and $12 million in restructuring charges for the ~~three~~nine months ended ~~March 31,~~September 30, 2020.

(3)Excludes $3$4 million and $9 million of restructuring charges for the three and nine months ended ~~March 31,~~September 30, 2019, respectively. Excludes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $3 million of legal settlement charges for the three and nine months ended September 30, 2019.

~~Lease~~ Operating Costs and Expenses


	For the three months ended September 30,					Increase/(Decrease)	For the nine months ended September 30,					Increase/(Decrease)
(in millions except percentages)	2020		2019				2020		2019
Lease operating expenses	$	203	$	189		7%	$	579	$	524		10%
General & administrative expenses	27		39		(1)	(31)%	79		108		(1)	(27)%
Montage acquisition-related expenses	3		—			100%	3		—			100%
Restructuring charges	—		4			(100)%	12		9			33%
Taxes, other than income taxes	15		14			7%	38		50			(24)%
Full cost pool amortization	65		123			(47)%	248		328			(24)%
Non-full cost pool DD&A	3		—			100%	12		17			(29)%
Impairments	361		—			100%	2,495		6			41,483%
Total operating costs	$	677	$	369		83%	$	3,466	$	1,042		233%

•(1)~~Lease operating expenses per Mcfe increased $0.06~~Includes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $3 million of legal settlement charges for the three and nine months ended March 31, 2020, compared to the same period of 2019, due to a $0.04 per Mcfe increase related to a shift towards liquids production, which includes processing fees, and a $0.02 per Mcfe increase related to increased compression costs.September 30, 2019.

~~General and Administrative Expenses~~

•General and administrative expenses decreased $11 million for the three months ended March 31, 2020, compared to the same period of 2019, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

~~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 decreased $0.03 for the three months ended March 31, 2020, compared to the same period of 2019, primarily due to lower effective severance tax rates in Southwest Appalachia.

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~~Full Cost Pool Amortization~~


	For the three months ended September 30,						Increase/	For the nine months ended September 30,						Increase/
Average unit costs per Mcfe:	2020			2019			(Decrease)	2020			2019			(Decrease)
Lease operating expenses (1)	$	0.91		$	0.94		(3)%	$	0.93		$	0.92		1%
General & administrative expenses	$	0.12	(2)	$	0.15	(3)	(20)%	$	0.13	(2)	$	0.17	(3)	(24)%
Taxes, other than income taxes	$	0.07		$	0.08		(13)%	$	0.06		$	0.09		(33)%
Full cost pool amortization	$	0.29		$	0.58		(50)%	$	0.40		$	0.57		(30)%

•(1)~~Our full cost pool amortization rate decreased $0.04 per Mcfe~~Includes post-production costs such as gathering, processing, fractionation and compression.

(2)Excludes $3 million in Montage acquisition-related expenses for the three and nine months ended ~~March 31,~~September 30, 2020 ~~as compared to~~and $12 million in restructuring charges for the same period in 2019. The average amortization rate decreased primarily as a result of the impact of capital investment and the further evaluation of our unproved properties during the past twelve months.nine months ended September 30, 2020.

•(3)~~The amortization rate is impacted by the timing~~Excludes $4 million 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 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 $1.4 billion at March 31, 2020, compared to $1.5 billion at December 31, 2019. The unevaluated costs excluded from amortization decreased as the impact of $15$9 million of ~~unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $84 million.~~

~~Marketing~~

For the three months ended March 31, Increase/
(Decrease)
(in millions except percentages) 2020 2019
Marketing revenues $ 548 $ 940 (42)%
Other operating revenues — 1 (100)%
Marketing purchases 547 934 (41)%
Operating costs and expenses 5 5 —%
Gain on sale of operating assets — (1) (100)%
Operating income (loss) $ (4) $ 3 (233)%

Volumes marketed (Bcfe)
263 289 (9)%

Percent natural gas production marketed from affiliated E&P operations 87 % 69 %
Percent oil and NGL production marketed from affiliated E&P operations 77 % 75 %

~~Operating Income (Loss)~~

•~~Marketing operating income (loss) decreased $7 million~~restructuring charges for the three and nine months ended ~~March 31, 2020, compared~~September 30, 2019, respectively. Excludes a $6 million residual value guarantee short-fall payment to the ~~same period in 2019, primarily due to a $5~~previous lessor of our headquarters building and $3 million ~~decrease in the marketing margin. In addition, marketing operating income for the first quarter~~ of ~~2019 included a $1 million gain on the sale of operating assets and a $1 million gain on the sale of gas in storage.~~

•~~The margin generated from marketing activities was $1 million and $6 million~~legal settlement charges for the three and nine months ended March 31, 2020 and 2019, respectively. The decrease in marketing margin for the three months ended March 31, 2020, compared to the same period in 2019, reflects our efforts to optimize the cost of our transportation through the purchase and sale of third-party natural gas.September 30, 2019.

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 marketing purchase expenses. Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.

~~Revenues~~

•For the three months ended March 31, 2020, revenues from our marketing activities decreased $392 million compared to the same period in 2019, primarily due to a 26 Bcfe decrease in the volumes marketed and a 36% decrease in the price received for volumes marketed.

Operating Costs and Expenses


	For the three months ended September 30,					Increase/(Decrease)	For the nine months ended September 30,					Increase/(Decrease)
(in millions except percentages)	2020		2019				2020		2019
Lease operating expenses	$	203	$	189		7%	$	579	$	524		10%
General & administrative expenses	27		39		(1)	(31)%	79		108		(1)	(27)%
Montage acquisition-related expenses	3		—			100%	3		—			100%
Restructuring charges	—		4			(100)%	12		9			33%
Taxes, other than income taxes	15		14			7%	38		50			(24)%
Full cost pool amortization	65		123			(47)%	248		328			(24)%
Non-full cost pool DD&A	3		—			100%	12		17			(29)%
Impairments	361		—			100%	2,495		6			41,483%
Total operating costs	$	677	$	369		83%	$	3,466	$	1,042		233%

•(1)~~Marketing operating costs~~Includes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and ~~expenses remained flat~~$3 million of legal settlement charges for the three and nine months ended ~~March 31, 2020, compared to the same period in~~September 30, 2019.

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	For the three months ended September 30,						Increase/	For the nine months ended September 30,						Increase/
Average unit costs per Mcfe:	2020			2019			(Decrease)	2020			2019			(Decrease)
Lease operating expenses (1)	$	0.91		$	0.94		(3)%	$	0.93		$	0.92		1%
General & administrative expenses	$	0.12	(2)	$	0.15	(3)	(20)%	$	0.13	(2)	$	0.17	(3)	(24)%
Taxes, other than income taxes	$	0.07		$	0.08		(13)%	$	0.06		$	0.09		(33)%
Full cost pool amortization	$	0.29		$	0.58		(50)%	$	0.40		$	0.57		(30)%

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

(2)Excludes $3 million in Montage acquisition-related expenses for the three and nine months ended September 30, 2020 and $12 million in restructuring charges for the nine months ended September 30, 2020.

(3)Excludes $4 million and $9 million of restructuring charges for the three and nine months ended September 30, 2019, respectively. Excludes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $3 million of legal settlement charges for the three and nine months ended September 30, 2019.

Lease Operating Expenses

•Lease operating expenses per Mcfe decreased $0.03 for the three months ended September 30, 2020, compared to the same period of 2019, as a decrease related to temporarily reduced gathering and transportation rates in Southwest Appalachia, that became effective late in the second quarter of 2020, was only partially offset by an increase related to a shift towards liquids production, which includes processing fees.

•Lease operating expenses per Mcfe increased $0.01 for the nine months ended September 30, 2020, compared to the same period of 2019, as an increase related to a shift towards liquids production, which includes processing fees, was only partially offset by a decrease related to temporarily reduced gathering and transportation rates in Southwest Appalachia, that became effective late in the second quarter of 2020.

General and Administrative Expenses

•General and administrative expenses for the three and nine months ended September 30, 2019 included a $6 million residual value guarantee shortfall payment to the previous lessor of our headquarters building and $3 million in legal settlement charges. Excluding these amounts, general and administrative expenses decreased $3 million and $20 million for the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

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 decreased $0.01 and $0.03 for the three and nine months ended September 30, 2020, respectively, compared to the same periods of 2019, primarily due to lower commodity pricing and lower effective severance tax rates in Southwest Appalachia.

Full Cost Pool Amortization

•Our full cost pool amortization rate decreased $0.29 and $0.17 per Mcfe for the three and nine months ended September 30, 2020, respectively, as compared to the same periods in 2019. The average amortization rate decreased primarily as a result of the impact of $2,129 million in non-cash full cost ceiling test impairments recorded during the first half of 2020.

•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 $1.4 billion at September 30, 2020, compared to $1.5 billion at December 31, 2019. The unevaluated costs excluded from amortization decreased as the impact of $84 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $211 million.

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Impairments

•For the three and nine months ended September 30, 2020, we recognized non-cash full cost ceiling test impairments of $361 million and $2,490 million, respectively, primarily due to decreased commodity pricing over the prior twelve months. Additionally, for the nine months ended September 30, 2020, we recognized a $5 million impairment related to other non-core assets.

•During the nine months ended September 30, 2019, we recognized a $6 million impairment to non-core gathering assets.

Marketing


	For the three months ended September 30,						Increase/ (Decrease)	For the nine months ended September 30,						Increase/ (Decrease)
(in millions except volumes and percentages)	2020			2019				2020			2019
Marketing revenues	$	495		$	592		(16)%	$	1,432		$	2,158		(34)%
Other operating revenues	—			—			—%	—			1			(100)%
Marketing purchases	491			592			(17)%	1,429			2,148			(33)%
Operating costs and expenses	6			6			—%	17			19			(11)%
Impairments	—			2			(100)%	—			2			(100)%
Loss on sale of operating assets	—			—			—%	—			3			(100)%
Operating loss	$	(2)		$	(8)		(75)%	$	(14)		$	(13)		8%

Volumes marketed (Bcfe)	294			279			5%	822			823			—%

Percent natural gas production marketed from affiliated E&P operations	88		%	81		%		87		%	77		%
Percent oil and NGL production marketed from affiliated E&P operations	83		%	73		%		81		%	74		%

Operating Loss

•Marketing operating loss decreased $6 million for the three months ended September 30, 2020, compared to the same period in 2019, primarily due to a $4 million increase in the marketing margin. In addition, marketing operating loss for the third quarter of 2019 included $2 million in impairments.

•Marketing operating loss increased $1 million for the nine months ended September 30, 2020, compared to the same period in 2019, as a $7 million decrease in the marketing margin was only partially offset by a $2 million decrease in operating costs and expenses. In addition, marketing operating loss for the nine months ended September 30, 2019 included a $3 million loss on the sale of operating assets and $1 million in gas storage gains recorded in other operating revenues.

•The margin generated from marketing activities was $4 million for the three months ended September 30, 2020, less than $1 million for the same period in 2019 and $3 million and $10 million for the nine months ended September 30, 2020 and 2019, respectively. The increase in the marketing margin for the three months ended September 30, 2020, compared to the same period in 2019, resulted primarily from utilizing existing transportation capacity to take advantage of low in-basin pricing on the purchase and sale of third-party natural gas, as well as certain demand charge credits for pipeline downtime. The decrease in marketing margin for the nine months ended September 30, 2020, compared to the same period in 2019, reflects our efforts to optimize the cost of our transportation through the purchase and sale of third-party natural gas.

Revenues

•Revenues from our marketing activities decreased $97 million for the three months ended September 30, 2020 compared to the same period in 2019, as a 21% decrease in the price received for volumes marketed was only partially offset by a 15 Bcfe increase in volumes marketed.

•For the nine months ended September 30, 2020, revenues from our marketing activities decreased $726 million compared to the same period in 2019, primarily due to a 34% decrease in the price received for volumes marketed as volumes marketed remained flat.

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Operating Costs and Expenses

•Operating costs and expenses for the marketing segment remained flat for the three months ended September 30, 2020 and decreased $2 million for the nine months ended September 30, 2020, compared to the same periods in 2019 primarily due to decreased general and administrative expenses associated with decreased personnel costs and the implementation of cost reduction initiatives.

Consolidated

Restructuring Charges

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 ~~$10~~$12 million for the ~~three~~nine months ended ~~March 31,~~months ended September 30, 2020 related to cash severance, including payroll taxes.

In the ~~first~~third quarter of 2019, we recognized $3$4 million in restructuring charges consisting of cash severance payments and office consolidation expenses related to the Fayetteville Shale sale, which closed in December 2018. For the nine months ended September 30, 2019, we recognized total restructuring charges of $9 million, of which $4 million was related to cash severance, including payroll taxes withheld, and $5 million primarily related to office consolidation related to the 2018 Fayetteville Shale sale. We refer you to Note 2 3 to the consolidated financial statements included in this Quarterly Report for additional details about our restructuring charges.

Interest Expense


		For the three months ended March 31,					Increase/(Decrease)				For the three months ended September 30,				Increase/(Decrease)		For the nine months ended September 30,			Increase/(Decrease)
(in millions except percentages)	(in millions except percentages)	2020		2019				(in millions except percentages)	2020		2019		Increase/(Decrease)	2020			2019		Increase/(Decrease)
Gross interest expense:	Gross interest expense:							Gross interest expense:
Senior notes	Senior notes	$	37	$	39	(5)%		Senior notes	$	39	$	39	—%		$	112	$	117	(4)%
Credit arrangements	Credit arrangements	3		3		—%		Credit arrangements	4		2		100%		11		7		57%
Amortization of debt costs	Amortization of debt costs	2		1		100%		Amortization of debt costs	2		3		(33)%		7		6		17%
Total gross interest expense	Total gross interest expense	42		43		(2)%		Total gross interest expense	45		44		2%		130		130		—%
Less: capitalization	Less: capitalization	(23)		(29)		(21)%		Less: capitalization	(23)		(27)		(15)%		(67)		(84)		(20)%
Net interest expense	Net interest expense	$	19	$	14	36%		Net interest expense	$	22	$	17	29%		$	63	$	46	37%

•Interest expense related to our senior notes ~~decreased~~remained flat for the three months ended ~~March 31,~~September 30, 2020 and decreased for the nine months ended September 30, 2020, compared to the same ~~period~~periods of 2019, as we repurchased ~~$80~~$107 million and $114 million of our outstanding senior notes during the first half of 2020 and the last half of 2019, respectively. The decrease during and nine months ended September 30, 2020 was partially 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 decreased for the three and nine months ended ~~March 31,~~September 30, 2020, respectively, compared to the same ~~period~~periods in 2019, 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 nine months ended ~~March 31,~~September 30, 2020, compared to the same ~~period~~periods in 2019, primarily related to a larger percentage decrease in our unevaluated natural gas and oil properties balance as compared to the smaller percentage decrease in our gross interest expense over the same period.

Gain (Loss) on Derivatives


		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
Gain (loss) on unsettled derivatives	Gain (loss) on unsettled derivatives	$	246	$	(22)	Gain (loss) on unsettled derivatives	$	(289)	$	12	$	(272)	$	108
Gain (loss) on settled derivatives		93		(10)
Gain on settled derivatives						Gain on settled derivatives	97		88		310		112
Gain (loss) on derivatives	Gain (loss) on derivatives	$	339	$	(32)	Gain (loss) on derivatives	$	(192)	$	100	$	38	$	220

We refer you to Note 78 to the consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.

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Gain/Loss on Early Extinguishment of Debt

For the ~~three~~nine months ended ~~March 31,~~September 30, 2020, we recorded a gain on early extinguishment of debt of ~~$28~~$35 million as a result of our repurchase of ~~$80~~$107 million in aggregate principal amount of our outstanding senior notes for ~~$52~~$72 million. There were no debt repurchases in the third quarter of 2020.

For the three months ended September 30, 2019, we recorded a gain on early extinguishment of debt of $7 million as a result of our repurchase of $50 million in aggregate principal amount of our outstanding senior notes. See Note 1 011 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes

For the three months ended March 31,
(in millions except percentages) 2020 2019
Income tax (benefit) expense $ 406 $ (426)
Effective tax rate (36) % (254) %

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	For the three months ended September 30,						For the nine months ended September 30,
(in millions except percentages)	2020			2019			2020			2019
Income tax (benefit) expense	$	—		$	10		$	406		$	(401)
Effective tax rate	0		%	18		%	(16)		%	(105)		%

•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, ~~as of March 31, 2019,~~ we concluded that it was more likely than not that the deferred tax asset would be realized and ~~determined that $426 million~~released substantially all of the valuation ~~allowance would be released as~~allowance. This resulted in a discrete tax benefit of ~~March 31,~~$400 million being recorded in the first three quarters of 2019. However, due to commodity price declines during ~~the first quarter of~~ 2020 and the write-down of the carrying value of our natural gas and oil properties, ~~for the three months ended March 31, 2020,~~ 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 ~~in the period~~ of $408 million for the increase in our valuation ~~allowance.~~allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. 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 1 67 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which have been implemented.

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 1 67 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards which 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. ~~On April 13,~~In October 2020, the banks participating in our 2018 credit facility ~~redetermined~~reaffirmed our elected borrowing base and aggregate commitments to be $1.8 ~~billion, which also changed our~~billion. Upon the anticipated closing of the Merger in the fourth quarter of 2020, and satisfaction of related conditions, the elected borrowing base and total aggregate commitments will be increased from $1.8 billion to ~~that amount.~~$2.0 billion, the maximum permitted lien amount based on provisions in certain of our senior note indentures. As of ~~April 28,~~October 27, 2020, we had ~~$1.3~~approximately $1.7 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 101 1 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.

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. See ~~“The Impact of COVID-19 on Our Business”~~“Market Conditions and Commodity Prices” in the Overview section of Item 2 in Part I for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity hedging activities. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. In the first ~~quarter~~three quarters of 2020, $310 million in realized gains on derivatives have offset a large portion of the impact of ~~the recent decline in~~lower commodity prices, and as of ~~April 28,~~October 27, 2020, we currently have derivative positions in place for ~~81%~~over 90% of our expected remaining 2020 production, including ~~87%~~over 70% of our ~~originally~~ expected ~~condensate~~liquids 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 78 in the consolidated financial statements included in this Quarterly Report for further details.

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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 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 ~~partners~~owners could adversely impact our cash flows.

Due to these above factors, we are unable to forecast with certainty our future level of cash flow 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.

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Credit Arrangements and Financing Activities

In April 2018, we replaced our credit facility 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, ~~at March 31,~~in October 2020, ~~had a~~the banks participating in our 2018 credit facility reaffirmed the borrowing base ~~of $2.1~~to be $1.8 billion, ~~with~~which also reflects our aggregate ~~bank commitments of $2.0 billion.~~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 derivative position, the level of capital ~~investing~~investment and operating costs. Upon the anticipated closing of the Merger in the fourth quarter of 2020, and satisfaction of related conditions, the borrowing base and total aggregate commitments will be increased from $1.8 billion to $2.0 billion. On ~~April 13,~~October 8, 2020, we entered into an amendment to the ~~banks participating in our~~credit agreement governing the 2018 credit facility ~~redetermined~~to, among other matters, limit our unrestricted cash and cash equivalents to $200 million when loans under the ~~borrowing base~~2018 credit facility are outstanding, subject to ~~be $1.8 billion, which also changed our aggregate commitments~~certain exceptions, and to ~~that amount.~~increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in ~~the~~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 ~~March 31,~~September 30, 2020, we had ~~$149~~no borrowings outstanding on our 2018 credit facility and ~~$172~~$203 million in outstanding letters of credit. AsWe refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of ~~April 28, 2020, we have been requested to post an additional $150 million in letters of~~our revolving credit ~~related to firm transportation. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts.~~facility.

As of ~~March 31,~~September 30, 2020, we were in compliance with all of the covenants ofcontained in the credit agreement governing our revolving credit ~~facility in all material respects.~~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. Beginning late in the first quarter of 2020, decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions reduced the demand for oil-based products such as gasoline, jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between OPEC and Russia on production levels, have caused a significant decline in commodity pricing since the beginning of 2020. Additionally, space to store oil and condensate production is reaching or may reach capacity in some areas, which has prompted purchasers of oil and condensate to reduce future purchase levels and, in some cases, to claim force majeure for purchases already contracted. Consequently, during the second half of April 2020, we received notices from two companies asserting force majeure and curtailing approximately 3,200 gross barrels per day of our condensate. We are adjusting our 2020 capital investing program to take into account these changed conditions. To the extent that this decreased demand for our commodities continues or storage for our production is not available, we expect to reduce production from or completely shut in portions of our currently producing wells. If the current market conditions persist or deteriorate further, we would proactively continue to adjust our activities and plans. Absent any actions taken by the Company, and under these conditions or if they worsen, current modeling indicates that we would not be in compliance with our Net Leverage Ratio covenant under our 2018 credit facility in late 2020. Under such circumstances, we would seek waivers or a modification of the covenant package from the lenders in advance of any covenant non-compliance. Additionally, we have other mitigating options including but not limited to the monetization of derivative asset positions, the reduction or elimination of non-essential expenditures or the sale of non-core assets. We refer you to Note 1 01 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 1 01 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 SOFR.

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In August 2020, we completed a public offering of $350 million aggregate principal amount of our 2028 Notes, with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses. The 2028 Notes were sold at 100% of their face value and are subject to special mandatory redemption at par plus accrued and unpaid interest if the merger does not close on or prior to February 12, 2021 or we determine, in our sole discretion, that the consummation of the merger cannot or is not reasonably likely to be satisfied by February 12, 2021. Concurrent with our 2028 Notes offering, we amended our 2018 credit facility to, among other things, add a springing maturity trigger if at least $450 million of the Montage Notes have not been redeemed, refinanced or amended prior to April 15, 2023, such that their maturity date is extended to a date on or after July 24, 2024.

In August 2020, we completed a public offering of 63,250,000 shares of our 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. The proceeds from the common stock offering, in conjunction with the issuance of the 2028 Notes and additional borrowings on our revolving credit facility, will be used to fund a redemption of $510 million aggregate principal amount of Montage Notes in connection with the closing of the Merger. Pending the consummation of the Merger, a portion of these net proceeds has temporarily been used to repay revolving credit facility borrowings until the anticipated redemption of the Montage Notes.

During the first ~~quarter~~nine months of 2020, we repurchased $3$6 million of our 4.10% Senior Notes due 2022, ~~$28~~$36 million of our 4.95% Senior Notes due 2025, ~~$18~~$21 million of our 7.50% Senior Notes due 2026 and ~~$31~~$44 million of our 7.75% Senior Notes due 2027 for ~~$52~~$72 million, and recognized a ~~$28~~$35 million gain on the extinguishment of debt.

InFor the ~~second half of~~three months ended September 30, 2019, we ~~purchased $35 million of our 4.95% Senior Notes due 2025, $11 million of our 7.50% Senior Notes due 2026 and $16 million of our 7.75% Senior Notes due 2027, and recognized an $8~~recorded a $7 million gain on extinguishment of ~~debt. Additionally,~~debt as a result of our repurchase of $50 million in ~~December 2019, we retired the remaining $52 million outstanding~~aggregate principal amount of our ~~4.05% Senior Notes due 2020.~~outstanding senior notes. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our senior notes.

Because of the focused work on refinancing and repayment of our debt during the last three years, only ~~$210~~$207 million of our senior notes outstanding as of ~~March 31,~~September 30, 2020 isare scheduled to become due prior to 2025.

At ~~April 28,~~October 27, 2020, we had a long-term issuer credit rating of Ba2 by Moody’s ~~(affirmed~~(rating and stable outlook affirmed on April 2, 2020), a long-term debt rating of BB- by S&P (rating affirmed and outlook upgraded to stable on October 15, 2020) and a long-term issuer default rating of BB by Fitch Ratings. On April 7, 2020, S&P downgraded our bond rating to BB-, which has the effect of increasing the interest rate on the 2025 Notes to 6.45%. The first coupon payment to the bondholders at the higher interest rate will be January 2021. 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 three months ended March 31,							For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019
Net cash provided by operating activities	Net cash provided by operating activities	$	160	$	442	Net cash provided by operating activities	$	407	$	739
Net cash used in investing activities	Net cash used in investing activities	(228)		(258)		Net cash used in investing activities	(698)		(835)
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	68		(19)		Net cash provided by (used in) financing activities	381		(76)

Cash Flow from Operating Activities


		For the three months ended March 31,							For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019
Net cash provided by operating activities	Net cash provided by operating activities	$	160	$	442	Net cash provided by operating activities	$	407	$	739
Add back (subtract) changes in working capital	Add back (subtract) changes in working capital	21		(136)		Add back (subtract) changes in working capital	(9)		(88)
Net cash provided by operating activities, net of changes in working capital	Net cash provided by operating activities, net of changes in working capital	$	181	$	306	Net cash provided by operating activities, net of changes in working capital	$	398	$	651

•Net cash provided by operating activities decreased ~~64%~~45%, or ~~$282~~$332 million, for the ~~three~~nine months ended ~~March 31,~~September 30, 2020, compared to the same period in 2019, primarily due to a ~~$272~~$538 million decrease resulting from lower commodity prices, a ~~$157~~$79 million ~~decrease in~~decreased impact of working capital, ~~a $19~~an $18 million increase in operating costs, a $7 million decrease in marketing margin and a $5$17 million ~~increase~~decrease in ~~net~~ interest ~~costs.~~expense. These decreases were partially offset by a ~~$103~~$198 million increase in our settled derivatives and a ~~$72~~$127 million increase associated with increased production.

•Net cash generated from operating activities, net of changes in working capital, provided ~~76%~~56% of our cash requirements for capital investments for the ~~three~~nine months ended ~~March 31,~~September 30, 2020, compared to providing ~~94%~~70% of our cash requirements for capital investments for the same period in 2019. ~~While we front-load~~Consistent with past years, our capital ~~programs into~~program for 2020 is weighted to the ~~earlier quarters in~~first half of the ~~year, we~~year. We remain committed to our disciplined capital ~~discipline~~ strategy.

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Cash Flow from Investing Activities

•Total capital ~~investing~~investments decreased ~~$88~~$17 million for the three months ended ~~March 31,~~September 30, 2020, compared to the same period in 2019, primarily due to an $8 million decrease in direct E&P capital investments and an $8 million decrease in capitalized interest and internal costs.

•Total capital investments decreased $228 million for the nine months ended September 30, 2020, compared to the same period in 2019, due to a ~~$75~~$192 million decrease in direct E&P capital ~~investing~~investments and a ~~$13~~$34 million decrease in capitalized interest and internal costs, as compared to the same period in 2019.


		For the three months ended March 31,							For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019
Additions to properties and equipment	Additions to properties and equipment	$	228	$	258	Additions to properties and equipment	$	700	$	877
Adjustments for capital investments	Adjustments for capital investments					Adjustments for capital investments
Changes in capital accruals	Changes in capital accruals	8		66		Changes in capital accruals	1		52
Other ⁽¹⁾	Other ⁽¹⁾	1		1		Other (1)	4		4
Total capital investing		$	237	$	325
Total capital investment						Total capital investment	$	705	$	933

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

Capital ~~Investing~~Investment

For the three months ended March 31, Increase/(Decrease)
(in millions except percentages) 2020 2019
E&P capital investing $ 237 $ 325 (27)%
Other capital investing⁽¹⁾
— — —%
Total capital investing $ 237 $ 325 (27)%


	For the three months ended September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
(in millions except percentages)	2020		2019			2020		2019
E&P capital investment	$	223	$	239	(7)%	$	705	$	931	(24)%
Other capital investment (1)	—		1		(100)%	—		2		(100)%
Total capital investment	$	223	$	240	(7)%	$	705	$	933	(24)%

(1)Other capital ~~investing~~investment was immaterial for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019.

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		For the three months ended March 31,							For the three months ended September 30,				For the nine months ended September 30,
(in millions)	(in millions)	2020		2019		(in millions)	2020		2019		2020		2019
E&P Capital Investments by Type:	E&P Capital Investments by Type:					E&P Capital Investments by Type:
Exploratory and development drilling, including workovers	Exploratory and development drilling, including workovers	$	190	$	251	Exploratory and development drilling, including workovers	$	163	$	176	$	550	$	711
Acquisitions of properties		6		7
Acquisition of properties						Acquisition of properties	15		9		29		32
Seismic expenditures	Seismic expenditures	—		1		Seismic expenditures	—		—		—		2
Water infrastructure project	Water infrastructure project	1		15		Water infrastructure project	5		6		8		32
Other	Other	4		2		Other	3		3		12		14
Capitalized interest and expenses	Capitalized interest and expenses	36		49		Capitalized interest and expenses	37		45		106		140
Total E&P capital investments	Total E&P capital investments	$	237	$	325	Total E&P capital investments	$	223	$	239	$	705	$	931

E&P Capital Investments by Area:	E&P Capital Investments by Area:					E&P Capital Investments by Area:
Northeast Appalachia	Northeast Appalachia	$	86	$	106	Northeast Appalachia	$	98	$	74	$	299	$	306
Southwest Appalachia	Southwest Appalachia	146		198		Southwest Appalachia	117		154		386		575
Other E&P ⁽¹⁾	Other E&P ⁽¹⁾	5		21		Other E&P (1)	8		11		20		50
Total E&P capital investments	Total E&P capital investments	$	237	$	325	Total E&P capital investments	$	223	$	239	$	705	$	931

(1)Includes $1$5 million and ~~$15~~$6 million for the three months ended ~~March 31,~~September 30, 2020 and 2019, respectively, and $8 million and $32 million for the nine months ended September 30, 2020 and 2019, respectively, related to our water infrastructure project.


		For the three months ended March 31,				For the three months ended September 30,		For the nine months ended September 30,
		2020	2019		2020	2019	2020	2019
Gross Operated Well Count Summary:	Gross Operated Well Count Summary:			Gross Operated Well Count Summary:
Drilled	Drilled	38	30	Drilled	16	24	84	95
Completed	Completed	22	31	Completed	25	30	78	101
Wells to sales	Wells to sales	12	19	Wells to sales	30	34	73	89

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.

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Cash Flow from Financing Activities

(in millions except percentages) March 31, 2020 December 31, 2019 Increase/(Decrease)
Debt ⁽¹⁾
$ 2,279 $ 2,242 $ 37
Equity 1,701 3,246 (1,545)
Total debt to capitalization ratio 57 % 41 %

~~(1)~~•The increase in total debt as of March 31, 2020, as compared to December 31, 2019, primarily relates to the use of the 2018 credit facility to supplement our capital investing, which is front-loaded to the first half of the year, partially offset by the repurchase of certain of our outstanding senior notes at a discount during the first quarter of 2020.

In the first ~~quarter~~nine months of 2020, we repurchased ~~$80~~$107 million in aggregate principal amount of our outstanding senior notes at a discount for ~~$52~~$72 million, and recognized a ~~$28~~$35 million gain on the extinguishment of debt. In addition, we completed the previously mentioned debt offering which resulted in $345 million in net proceeds and an equity offering which resulted in $152 million in net proceeds.

We refer you to Note 1 01 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

•We had ~~positive~~negative working capital of ~~$58~~$256 million at ~~March 31,~~September 30, 2020, ~~a $227~~an $87 million ~~increase~~decrease from December 31, 2019, as a ~~$206~~$90 million ~~positive change~~increase in cash and cash equivalents, a $109 million decrease in accounts payable and a $23 million decrease in firm transportation liabilities, as compared to December 31, 2019, were more than offset by a $106 million decrease in accounts receivable and a $202 million reduction in the current mark-to-market value of our derivative position ~~a $60 million decrease in accounts payable and a $7 million decrease in taxes payable,~~related to improved forward strip pricing across all commodities, as compared to December ~~31, 2019, were only partially offset by a $53 million decrease~~2019. We believe that our existing cash and cash equivalents, our anticipated cash flows from operations and our available credit facility will be sufficient to meet our working capital and operational spending requirements. We expect to use our revolving credit facility to redeem the Montage Notes and repay the Montage credit facility upon the anticipated closing of the pending Merger in ~~accounts receivable, as compared~~the fourth quarter of 2020. See Note 2 to ~~December 2019, related to lower commodity prices.~~the consolidated financial statements included in this Quarterly Report for additional discussion about the 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 ~~March 31,~~September 30, 2020, our material off-balance sheet arrangements and transactions include operating service arrangements ~~$172~~and $203 million in letters of credit outstanding against our 2018 credit ~~facility and $115 million in outstanding surety bonds.~~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

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regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” in our 2019 Annual Report.

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 2019 Annual Report.

Contingent Liabilities and Commitments

As of ~~March 31,~~September 30, 2020, 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 totaled approximately ~~$7.6~~$7.1 billion, ~~$411~~$405 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 ~~$1.1~~$1.0 billion. As of ~~March 31,~~September 30, 2020, future payments under non-cancelable firm transportation and gathering agreements are as follows:


		Payments Due by Period																							Payments Due by Period
(in millions)	(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years		(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	Infrastructure currently in service	$	7,199	$	753	$	1,339	$	1,098	$	1,524	$	2,485	Infrastructure currently in service	$	6,704	$	582	$	1,308	$	1,078	$	1,411	$	2,325
Pending regulatory approval and/or construction ⁽¹⁾	Pending regulatory approval and/or construction ⁽¹⁾	411		1		17		23		74		296		Pending regulatory approval and/or construction (1)	405		3		9		23		52		318
Total transportation charges	Total transportation charges	$	7,610	$	754	$	1,356	$	1,121	$	1,598	$	2,781	Total transportation charges	$	7,109	$	585	$	1,317	$	1,101	$	1,463	$	2,643

(1)Based on the estimated in-service dates as of ~~March 31,~~September 30, 2020.

Included in the transportation charges above are ~~$81~~$27 million (due in less than one year) related to certain agreements that remain in the name of our marketing affiliate but are expected to be paid in full by ~~Flywheel Energy Operating, LLC,~~ the purchaser of the Fayetteville Shale assets. Of these amounts, we may be obligated to reimburse ~~Flywheel Energy Operating, LLC~~the purchaser for a portion of volumetric shortfalls during 2020 (up to ~~$45~~$13 million) under these transportation agreements and have currently recorded a ~~$36~~$10 million liability as of ~~March 31,~~September 30, 2020, down from $46 million recorded at December 31, 2019.

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In the first quarter of 2019, we agreed to purchase firm transportation with pipelines in the Appalachian Basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments of which the seller has agreed to reimburse $133 million of these commitments.

In February 2020, we were notified that the proposed Constitution pipeline project was cancelled and that we were released from a firm transportation agreement with its sponsor. Prior to its cancellation, we had contractual commitments totaling $512 million over the next 17 years related to the Constitution pipeline project.

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. For the ~~three~~nine months ended ~~March 31,~~September 30, 2020, we have contributed $5$12 million to the pension and postretirement benefit plans, and we expect tono further ~~contribute an additional $7 million~~contributions to our pension plan during the remainder of 2020. We recognized liabilities of ~~$40~~$36 million and $43 million as of ~~March 31,~~September 30, 2020 and December 31, 2019, respectively, as a result of the underfunded status of our pension and other postretirement benefit plans. See Note 1 34 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.

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For further information, we refer you to “Litigation” and “Environmental Risk” in Note 1 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 1 01, 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 which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes.

Upon the anticipated closing of the Company’s merger with Montage in the fourth quarter of 2020, certain Montage entities owning oil and gas properties will become guarantors to the 2018 credit facility.

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, 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 Guarantors 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.

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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 ~~basis swaps~~ and ~~interest rate~~basis swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain ~~NGLs along with interest rates.~~NGLs. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. ~~Utilization of financial products for the reduction of interest rate risks is also overseen by our Board of Directors.~~ 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. However, at ~~March 31,~~September 30, 2020, one purchaser accounted for ~~12%~~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. As of December 31, 2019, no single purchaser accounted for greater than 10% of revenues. 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 ~~March 31,~~September 30, 2020, we had approximately ~~$2.1~~$2.5 billion of outstanding senior notes with a weighted average interest rate of ~~6.70%~~7.02%, and we had ~~$149 million in~~no borrowings under our revolving credit facility. ~~We currently have an interest rate swap in effect to mitigate a portion of our exposure to volatility in interest rates.~~ At ~~March 31,~~September 30, 2020, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of BBBB- by S&P and a long-term issuer default rating of BB by Fitch Ratings. OnIn April 7, 2020, S&P downgraded our bond rating to BB-, which ~~has~~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 will be paid in January 2021. 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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		Expected Maturity Date																																								Expected Maturity Date
($ in millions)	($ in millions)	2021			2022			2023			2024			2025			Thereafter			Total			($ in millions)	2021			2022			2023			2024			2025			Thereafter				Total
Fixed rate payments ⁽¹⁾	Fixed rate payments ⁽¹⁾	$	—		$	210		$	—		$	—		$	864		$	1,074		$	2,148		Fixed rate payments (1)	$	—		$	207		$	—		$	—		$	856		$	1,408			$	2,471
Weighted average interest rate	Weighted average interest rate	—		%	4.10		%	—		%	—		%	6.20		%	7.61		%	6.70		%	Weighted average interest rate	—		%	4.10		%	—		%	—		%	6.45		%	7.80		%		7.02		%

Variable rate payments ⁽¹⁾	Variable rate payments ⁽¹⁾	$	—		$	—		$	—		$	149		$	—		$	—		$	149		Variable rate payments (1)	$	—		$	—		$	—		$	—		$	—		$	—			$	—
Weighted average interest rate	Weighted average interest rate	—		%	—		%	—		%	2.12		%	—		%	—		%	2.12		%	Weighted average interest rate	—		%	—		%	—		%	—		%	—		%	—		%		—		%

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

Commodities Risk

We use over-the-counter 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 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 78 and Note 9 10 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

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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, 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, 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, concluded that our disclosure controls and procedures were effective as of ~~March 31,~~September 30, 2020 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 ~~March 31,~~September 30, 2020 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 1 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.

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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 2019 Annual Report and Item 1A of Part II in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, except as set forth below.

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

Although we expect to complete the Merger by the end of 2020, there can be no assurances as to the exact timing of the completion of the Merger or that the Merger will be completed at all. The ~~widespread outbreak~~completion of ~~an illness, pandemic (such~~the Merger is subject to numerous conditions, including, among others, (i) the approval of the Merger Agreement by the holders of a majority of the outstanding shares of Montage common stock entitled to vote, (ii) the absence of any law, order or injunction prohibiting the Merger, (iii) the expiration or earlier termination of the waiting period under the Hart–Scott–Rodino Antitrust Improvements Act of 1976, as ~~COVID-19)~~amended, (iv) the SEC having declared effective Southwestern’s Registration Statement on Form S-4 filed in connection with the Merger, (v) the accuracy of each party’s representations and warranties, and (vi) each party’s compliance with its covenants and agreements contained in the Merger Agreement. There can be no assurance that the conditions required to complete the Merger will be satisfied or waived on the anticipated schedule, or at all.

If the Merger does not close, Southwestern will not benefit from the expenses incurred in connection therewith.

If the Merger is not completed, Southwestern will have incurred substantial expenses for which no ultimate benefit will have been received. Southwestern has incurred out-of-pocket expenses in connection with the 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 Merger is not completed. The expenses we incur in connection with the Merger will likely exceed any expense reimbursement or termination fee payment that we may be entitled to receive under the Merger Agreement.

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

Termination of the Merger Agreement or any ~~other public health crisis~~failure to otherwise complete the Merger may result in various consequences, including:

•Southwestern’s business may have ~~material adverse effects~~been adversely impacted by the failure to pursue other beneficial opportunities due to the focus of management on ~~our~~the Merger, without realizing any of the anticipated benefits of completing the Merger;

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•the market price of the notes may decline to the extent that the market price prior to termination reflects a market assumption that the Merger will be completed; and

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

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

Potential litigation against Southwestern or Montage could result in an injunction preventing the completion of the Merger or a judgment resulting in the payment of damages.

Stockholders of Southwestern and/or Montage may file lawsuits against Southwestern or Montage and/or the directors and officers of either company in connection with the Merger. These lawsuits could prevent or delay the completion of the Merger and result in significant costs to Southwestern, including any costs associated with the indemnification of directors and officers. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Merger is completed may adversely affect Southwestern’s business, financial condition, results of operations orand cash flows.

If the Merger is completed, Southwestern may not achieve the anticipated benefits of the Merger, and the Merger may disrupt its current plans or operations.

~~In December 2019, COVID-19 was reported~~The success of the Merger will depend, in part, on Southwestern’s ability to ~~have surfaced~~realize the anticipated benefits and cost savings from combining Southwestern’s and Montage’s businesses, and there can be no assurance that Southwestern and Montage will be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. Difficulties in ~~China. The spread of this virus has caused business disruptions beginning in January 2020, including disruptions~~integrating Southwestern and Montage may result in the ~~oil~~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 Montage in a manner that permits the achievement of full revenue, expected cash flows and ~~natural gas industry. In March 2020,~~cost savings anticipated from the ~~World Health Organization declared~~Merger;

•not realizing anticipated operating synergies;

•integrating personnel from the ~~outbreak of COVID-19 to be a pandemic,~~two companies and the ~~U.S. economy began to experience pronounced effects. The COVID-19 pandemic has negatively impacted~~loss of key employees;

•potential unknown liabilities and unforeseen expenses or delays associated with and following the ~~global economy, disrupted global supply chains, reduced global demand for oil~~completion of the Merger;

•integrating relationships with customers, vendors and ~~gas,~~business partners;

•performance shortfalls as a result of the diversion of management’s attention caused by completing the Merger and ~~created significant volatility~~integrating Montage’s operations; and

•the disruption of, ~~financial~~or the loss of momentum in, Southwestern’s ongoing business or inconsistencies in standards, controls, procedures and ~~commodity markets. The extent~~policies.

Completion of the ~~impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives~~Merger may trigger change in ~~the expected time frame, is uncertain and depends on various factors, including the demand for natural gas, oil, NGLs and~~control or other products derived from these commodities, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of the disruption. The degreeprovisions in certain agreements to which ~~the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments,~~Montage is a party, which ~~are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its~~may have an adverse impact on the ~~economy~~combined company’s business and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while the Company expects this matter will likely disrupt its operations, the degreeresults of operations.

The completion of the Merger may trigger change in control and other provisions in certain agreements to which Montage is a party. For those agreements for which we and Montage are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. The foregoing or similar developments may have an adverse impact on the combined company’s business and results of operations.

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.

We will account for the merger as an acquisition of a business in accordance with GAAP. Under the acquisition method of accounting, the assets and liabilities of Montage and its subsidiaries will be recorded, as of completion, at their respective fair values and added to ours. Our reported financial ~~impact cannot~~condition and results of operations for periods after completion of the merger will reflect Montage’s balances and results after completion of the merger but will not be ~~reasonably estimated at this time.~~restated retroactively to reflect the historical financial position or results of operations of Montage and its subsidiaries for periods prior to the merger.

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Under the acquisition method of accounting, the total purchase price will be allocated to Montage’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the 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.

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, is 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.

ITEM 5. OTHER INFORMATION

On April 28, 2020, the Board of Directors of the Company amended the Company’s bylaws (as so amended, the “Amended and Restated Bylaws”) to provide that litigation against the Company or its officers, directors, employees or agents under the federal Securities Act of 1933, as amended, must be brought in federal courts and modified existing provisions requiring various actions arising under Delaware law to be brought in Delaware courts. This description is qualified in its entirely by Section 7.5 of the Company’s Amended and Restated Bylaws, which are filed with this Quarterly Report as Exhibit 3.2.Not applicable.

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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)
(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)
(4.1)			F ourth Supplemental Indenture, dated as of August 27, 2020 among Southwestern Energy Company, U.S. Bank National Association, as trustee and the guarantors named therein (Incorporated by reference to Exhibit 4.2 to the Registrant ’s Current Report on Form 8-K filed August 27, 2020)
(4.2)			Form of 8.375% Notes due 2028 (Incorporated by reference to Exhibit 4.3 to the Registrant ’s Current Report on Form 8-K filed August 27, 2020)
(10.1)			Support Agreement, dated as of August 12, 2020, by and among certain stockholders affiliated with EnCap Investments L.P. and Southwestern Energy Company (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed August 12, 2020)
(10.2)*			Amendment No. 6 to Credit Agreement, dated as of July 31, 2020, among Southwestern Energy Company, the lenders party thereto and JP Morgan Chase Bank, N.A., as administrative agent for the lenders
(10.3)			Amendment No. 7 to Credit Agreement, dated as of August 18, 2020, among Southwestern Energy Company, 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 August 20, 2020)
(10.4)			Amendment No. 8 to Credit Agreement, dated as of October 8, 2020, among Southwestern Energy Company, 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 October 8, 2020)
(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

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:	~~April 30,~~October 29, 2020	/s/ JULIAN M. BOTT
		Julian M. Bott Executive Vice President and Chief Financial Officer

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