10-Q

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 September 30, 2020

Or

☐ 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 October 27, 2020
Common Stock, Par Value $0.01	605,559,524

SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED 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		9
		Note 1. Basis of Presentation	9
		Note 2. Acquisition	9
		Note 3. Restructuring Charges	10
		Note 4. Revenue Recognition	11
		Note 5. Cash and Cash Equivalents	12
		Note 6. Natural Gas and Oil Properties	13
		Note 7. Earnings per Share	13
		Note 8. Derivatives and Risk Management	14
		Note 9. Reclassifications From Accumulated Other Comprehensive Income (Loss)	22
		Note 10. Fair Value Measurements	22
		Note 11. Debt	25
		Note 12. Commitments and Contingencies	27
		Note 13. Income Taxes	28
		Note 14. Pension Plan and Other Postretirement Benefits	29
		Note 15. Long-Term Incentive Compensation	29
		Note 16. Segment Information	33
		Note 17. New Accounting Pronouncements	34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	Results of Operations		38
	Liquidity and Capital Resources		45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		51
Item 4.	Controls and Procedures		52
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		52
Item 1A.	Risk Factors		52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		54
Item 3.	Defaults Upon Senior Securities		54
Item 4.	Mine Safety Disclosures		54
Item 5.	Other Information		54
Item 6.	Exhibits		55

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.

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

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

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

•our ability to fund our planned capital investments;

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

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

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

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

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

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

•our ability to realize the expected benefits from acquisitions, including the 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 September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2020		2019		2020		2019
Operating Revenues:
Gas sales	$	199	$	238	$	611	$	943
Oil sales	40		67		111		153
NGL sales	68		52		158		191
Marketing	219		279		645		1,004
Other	1		—		4		2
	527		636		1,529		2,293
Operating Costs and Expenses:
Marketing purchases	226		288		675		1,022
Operating expenses	202		189		577		523
General and administrative expenses	31		42		89		119
Montage acquisition-related expenses	3		—		3		—
Restructuring charges	—		4		12		9
Loss on sale of operating assets	—		—		—		3
Depreciation, depletion and amortization	70		125		267		352
Impairments	361		2		2,495		8
Taxes, other than income taxes	15		15		38		51
	908		665		4,156		2,087
Operating Income (Loss)	(381)		(29)		(2,627)		206
Interest Expense:
Interest on debt	43		42		123		125
Other interest charges	2		2		7		5
Interest capitalized	(23)		(27)		(67)		(84)
	22		17		63		46
Gain (Loss) on Derivatives	(192)		100		38		220
Gain on Early Extinguishment of Debt	—		7		35		7
Other Income (Loss), Net	2		(2)		3		(7)
Income (Loss) Before Income Taxes	(593)		59		(2,614)		380
Provision (Benefit) for Income Taxes:
Current	—		(1)		(2)		(1)
Deferred	—		11		408		(400)
	—		10		406		(401)
Net Income (Loss)	$	(593)	$	49	$	(3,020)	$	781
Earnings (Loss) Per Common Share:
Basic	$	(1.04)	$	0.09	$	(5.48)	$	1.45
Diluted	$	(1.04)	$	0.09	$	(5.48)	$	1.44
Weighted Average Common Shares Outstanding:
Basic	571,872,413		539,221,101		551,162,559		539,315,170
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 September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Net income (loss)	$	(593)	$	49	$	(3,020)	$	781
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost (1)	1		1		1		5
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)

	September 30, 2020		December 31, 2019
ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	95	$	5
Accounts receivable, net	239		345
Derivative assets	238		278
Other current assets	41		51
Total current assets	613		679
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	500		520
Less: Accumulated depreciation, depletion and amortization	(23,247)		(20,503)
Total property and equipment, net	3,222		5,267
Operating lease assets	145		159
Deferred tax assets	—		407
Other long-term assets	177		205
Total long-term assets	322		771
TOTAL ASSETS	$	4,157	$	6,717
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	416	$	525
Taxes payable	47		59
Interest payable	56		51
Derivative liabilities	287		125
Current operating lease liabilities	33		34
Other current liabilities	30		54
Total current liabilities	869		848
Long-term debt	2,450		2,242
Long-term operating lease liabilities	107		119
Long-term derivative liabilities	188		111
Pension and other postretirement liabilities	35		43
Other long-term liabilities	124		108
Total long-term liabilities	2,904		2,623
Commitments and contingencies (Note 12)
Equity:
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	4,882		4,726
Accumulated deficit	(4,271)		(1,251)
Accumulated other comprehensive loss	(32)		(33)
Common stock in treasury, 44,353,224 shares as of September 30, 2020 and December 31, 2019	(202)		(202)
Total equity	384		3,246
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 nine months ended September 30,
(in millions)	2020		2019
Cash Flows From Operating Activities:
Net income (loss)	$	(3,020)	$	781
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	267		352
Amortization of debt issuance costs	6		5
Impairments	2,495		8
Deferred income taxes	408		(400)
(Gain) loss on derivatives, unsettled	272		(108)
Stock-based compensation	2		6
Gain on early extinguishment of debt	(35)		(7)
Loss on sale of assets	—		3
Other	3		11
Change in assets and liabilities:
Accounts receivable	106		257
Accounts payable	(129)		(124)
Taxes payable	(12)		(3)
Interest payable	3		2
Inventories	3		(2)
Other assets and liabilities	38		(42)
Net cash provided by operating activities	407		739
Cash Flows From Investing Activities:
Capital investments	(700)		(877)
Proceeds from sale of property and equipment	2		42
Net cash used in investing activities	(698)		(835)
Cash Flows From Financing Activities:
Payments on long-term debt	(72)		(43)
Payments on revolving credit facility	(1,449)		—
Borrowings under revolving credit facility	1,415		—
Change in bank drafts outstanding	(9)		(11)
Proceeds from issuance of long-term debt	350		—
Debt issuance costs	(5)		—
Purchase of treasury stock	—		(21)
Proceeds from issuance of common stock, net	152		—
Cash paid for tax withholding	(1)		(1)
Net cash provided by (used in) financing activities	381		(76)
Increase (decrease) in cash and cash equivalents	90		(172)
Cash and cash equivalents at beginning of year	5		201
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
	Shares Issued	Amount								Shares	Amount
	(in millions, except share amounts)
Balance at December 31, 2019	585,555,923	$	6	$	4,726	$	(1,251)	$	(33)	44,353,224	$	(202)	$	3,246
Comprehensive loss:
Net loss	—	—		—		(1,547)		—		—	—		(1,547)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(1,547)
Stock-based compensation	—	—		1		—		—		—	—		1
Issuance of restricted stock	12,397	—		—		—		—		—	—		—
Cancellation of restricted stock	(167,130)	—		—		—		—		—	—		—
Restricted units granted	1,005,976	—		1		—		—		—	—		1
Tax withholding – stock compensation	(383,731)	—		—		—		—		—	—		—
Balance at March 31, 2020	586,023,435	$	6	$	4,728	$	(2,798)	$	(33)	44,353,224	$	(202)	$	1,701
Comprehensive loss:
Net loss	—	—		—		(880)		—		—	—		(880)
Other comprehensive income	—	—		—		—		—		—	—		—
Total comprehensive loss	—	—		—		—		—		—	—		(880)
Stock-based compensation	—	—		1		—		—		—	—		1
Issuance of restricted stock	222,489	—		—		—		—		—	—		—
Cancellation of restricted stock	(1,079,515)	—		—		—		—		—	—		—
Restricted units granted	1,649,294	—		2		—		—		—	—		2
Tax withholding – stock compensation	(222,163)	—		(1)		—		—		—	—		(1)
Balance at June 30, 2020	586,593,540	$	6	$	4,730	$	(3,678)	$	(33)	44,353,224	$	(202)	$	823
Comprehensive loss:
Net loss	—	—		—		(593)		—		—	—		(593)
Other comprehensive income	—	—		—		—		1		—	—		1
Total comprehensive loss	—	—		—		—		—		—	—		(592)
Stock-based compensation	—	—		1		—		—		—	—		1
Issuance of common stock	63,250,000	1		151		—		—		—	—		152
Issuance of restricted stock	63,344	—		—		—		—		—	—		—
Cancellation of restricted stock	(5,196)	—		—		—		—		—	—		—
Treasury stock	—	—		—		—		—		—	—		—
Tax withholding – stock compensation	(2,035)	—		—		—		—		—	—		—
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
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 two segments: E&P and Marketing.

E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania 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 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

9

$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 nine months ended September 30, 2020, and were substantially complete by the end of the first quarter of 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. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. 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. As of September 30, 2019, the Company 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 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 third quarter of 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 September 30, 2020 and 2019:

	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Severance (including payroll taxes)	$	—	$	1	$	12	$	4
Office consolidation	—		3		—		5
Total restructuring charges (1)	$	—	$	4	$	12	$	9

(1)Total restructuring charges were $12 million for the Company’s E&P segment for the nine months ended 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 September 30, 2020, which is reflected in accounts payable on the consolidated balance sheet:

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

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(4) REVENUE RECOGNITION

Revenues from Contracts with Customers

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

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

Marketing.  The Company, through its marketing affiliate, markets natural gas, oil and NGLs for its affiliated E&P company as well as other joint interest owners that choose to market with the Company.  In addition, the Company markets some products purchased from third parties.  Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point.  The pricing provisions of the Company’s contracts are primarily tied to market indices with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions.  Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled.  Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer.  Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date.  As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

Disaggregation of Revenues

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

(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended September 30, 2020
Gas sales	$	190	$	—	$	9	$	199
Oil sales	39		—		1		40
NGL sales	68		—		—		68
Marketing	—		495		(276)		219
Other	1		—		—		1
Total	$	298	$	495	$	(266)	$	527
Three months ended September 30, 2019
Gas sales	$	230	$	—	$	8	$	238
Oil sales	66		—		1		67
NGL sales	52		—		—		52
Marketing	—		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	$	—	$	27	$	611
Oil sales	107		—		4		111
NGL sales	158		—		—		158
Marketing	—		1,432		(787)		645
Other (1)	4		—		—		4
Total	$	853	$	1,432	$	(756)	$	1,529
Nine months ended September 30, 2019
Gas sales	$	918	$	—	$	25	$	943
Oil sales	151		—		2		153
NGL sales	191		—		—		191
Marketing	—		2,158		(1,154)		1,004
Other (2)	1		1		—		2
Total	$	1,261	$	2,159	$	(1,127)	$	2,293

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

(2)For the nine months ended 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 September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Northeast Appalachia	$	131	$	175	$	443	$	740
Southwest Appalachia	166		173		409		519
Other	1		—		1		2
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)	September 30, 2020		December 31, 2019
Receivables from contracts with customers	$	218	$	284
Other accounts receivable	21		61
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 September 30, 2020 and 2019.  The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

(5) CASH AND CASH EQUIVALENTS

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

(in millions)	September 30, 2020		December 31, 2019
Cash	$	93	$	5
Marketable securities (1)	2		—
Total	$	95	$	5

(1)Consists of government stable value money market funds.

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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 no hedge positions that were designated for hedge accounting as of September 30, 2020. Prices used to calculate the ceiling value of reserves were as follows:

	September 30, 2020		September 30, 2019
Natural gas (per MMBtu)	$	1.97	$	2.87
Oil (per Bbl)	$	43.40	$	57.77
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 $361 million at 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 the first three quarters of 2020, an additional non-cash impairment of the Company’s assets may occur in the 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 oil properties.

The Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at September 30, 2019, and the Company had no derivative positions that were designated for hedge accounting as of 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.

(7) EARNINGS PER SHARE

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

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

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 September 30, 2020 and 2019:

	For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2020		2019		2020		2019
Net income (loss)	$	(593)	$	49	$	(3,020)	$	781
Number of common shares:
Weighted average outstanding	571,872,413		539,221,101		551,162,559		539,315,170
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	—		187,706		—		400,120
Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	—		629,380		—		727,359
Weighted average and potential dilutive outstanding	571,872,413		540,038,187		551,162,559		540,442,649
Earnings per common share
Basic	$	(1.04)	$	0.09	$	(5.48)	$	1.45
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 September 30, 2020 and 2019, as they would have had an antidilutive effect:

	For the three months ended September 30,		For the nine months ended September 30,
	2020	2019	2020	2019
Unexercised stock options	4,425,886	5,102,882	4,519,385	5,115,334
Unvested share-based payment	939,941	2,136,453	946,547	1,797,963
Restricted stock units	1,935,781	—	2,001,621	—
Performance units	2,282,211	240,450	2,027,985	247,443
Total	9,583,819	7,479,785	9,495,538	7,160,740

(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 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. The Company’s interest rate 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 were used to fix or float interest rates on existing or anticipated indebtedness.  The purpose of these instruments was 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 10 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 September 30, 2020:

Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2020 (in millions)
Natural Gas
2020
Fixed price swaps	91	$	2.46	$	—	$	—	$	—	$	—	$	16	(1)
Two-way costless collars	57	—		—		2.45		2.75		—		(7)
Three-way costless collars	25	—		2.19		2.58		2.96		—		(11)		(2)
Total	173											$	(2)
2021
Fixed price swaps	93	$	2.67	$	—	$	—	$	—	$	—	$	(13)
Two-way costless collars	166	—		—		2.51		2.89		—		(27)
Three-way costless collars	291	—		2.16		2.49		2.84		—		(113)		(3)
Total	550											$	(153)
2022
Fixed price swaps	37	$	2.75	$	—	$	—	$	—	$	—	$	(2)
Two-way costless collars	32	—		—		2.17		2.88		—		(5)
Three-way costless collars	116	—		2.07		2.44		2.87		—		(24)
Total	185											$	(31)
2023
Three-way costless collars	25	$	—	$	2.07	$	2.48	$	3.18	$	—	$	(2)
Basis Swaps
2020	66	$	—	$	—	$	—	$	—	$	(0.37)	$	21
2021	155	—		—		—		—		(0.12)		21
2022	127	—		—		—		—		(0.38)		4
Total	348											$	46

(1)Includes $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 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 September 30, 2020 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2020
Fixed price swaps (1)	584	$	75.44	$	—	$	—	$	—	$	20
Two-way costless collars	261	—		—		56.76		59.75		4
Three-way costless collars	404	—		43.71		52.85		57.78		3
Total	1,249									$	27
2021
Fixed price swaps	2,574	$	52.84	$	—	$	—	$	—	$	27
Three-way costless collars	1,445	—		43.52		53.25		58.14		8
Total	4,019									$	35
2022
Fixed price swaps	762	$	48.85	$	—	$	—	$	—	$	4
Three-way costless collars	666	—		42.50		53.20		58.00		2
Total	1,428									$	6
2023
Three-way costless collars	111	$	—	$	30.00	$	40.00	$	57.85	$	—
Ethane
2020
Fixed price swaps	2,629	$	8.62	$	—	$	—	$	—	$	—
2021
Fixed price swaps	5,889	$	7.12	$	—	$	—	$	—	$	(12)
Two-way costless collar	584	—		—		7.14		10.40		—
Total	6,473									$	(12)
2022
Fixed price swaps	190	$	7.41	$	—	$	—	$	—	$	—
Two-way costless collar	135	—		—		7.56		9.66		—
Total	325									$	—
Propane
2020
Fixed price swaps	1,435	$	23.11	$	—	$	—	$	—	$	2
Two-way costless collars	92	—		—		25.20		29.40		—
Total	1,527									$	2
2021
Fixed price swaps	4,298	$	19.99	$	—	$	—	$	—	$	(3)
2022
Fixed price swaps	156	$	19.25	$	—	$	—	$	—	$	—
Normal Butane
2020
Fixed price swaps	195	$	22.44	$	—	$	—	$	—	$	—
Natural Gasoline
2020
Fixed price swaps	184	$	34.59	$	—	$	—	$	—	$	—

(1)Includes 448 MBbls of purchased fixed price oil swaps at $33.94 per barrel with a fair value of $3 million and 1,032 MBbls of sold fixed price oil swaps at $57.44 per barrel with a fair value of $17 million.

17

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	$	—

	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	$	—	$	—
Purchased basis swaps	—	—		(0.63)		—
Fixed price swaps	—	2.09		—		—
Basis swaps	—	—		(0.70)		—
Total	1					$	—
2021
Purchased fixed price swaps	1	$	2.04	$	—	$	—
Fixed price swaps	2	2.49		—		(1)
Basis swaps	1	—		(0.38)		—
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)	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2020 (in millions)
2020	2	$	2.44	$	—
2021	6	2.44		3
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 September 30, 2020, the net fair value of the Company’s financial instruments related to commodities was a $125 million liability and included a net reduction of the liability of $1 million related to non-performance risk. See Note 10 for additional details regarding the Company’s fair value measurements of its derivative positions.

As of 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. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The Company was 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 had a notional amount of $170 million and expired in June 2020.  Changes in the fair value of the interest rate swaps were included in gain (loss) on derivatives on the consolidated statements of operations.

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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 September 30, 2020 and December 31, 2019:

Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2020			December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative assets	$	3		$	—
Fixed price swaps – natural gas	Derivative assets	21		(1)	77		(1)
Fixed price swaps – oil	Derivative assets	42			4
Fixed price swaps – ethane	Derivative assets	2			11
Fixed price swaps – propane	Derivative assets	5			21
Two-way costless collars – natural gas	Derivative assets	27			10
Two-way costless collars – oil	Derivative assets	6			5
Two-way costless collars – propane	Derivative assets	—			2
Three-way costless collars – natural gas	Derivative assets	64		(2)	126
Three-way costless collars – oil	Derivative assets	19			3
Basis swaps – natural gas	Derivative assets	40			17
Call options – natural gas	Derivative assets	9			1
Fixed price swaps – natural gas storage	Derivative assets	—			1
Fixed price swaps – natural gas	Other long-term assets	1			7
Fixed price swaps – oil	Other long-term assets	10			1
Fixed price swaps – propane	Other long-term assets	1			3
Two-way costless collars – natural gas	Other long-term assets	13			4
Three-way costless collars – natural gas	Other long-term assets	56			74
Three-way costless collars – oil	Other long-term assets	14			7
Basis swaps – natural gas	Other long-term assets	13			15
Call options – natural gas	Other long-term assets	4			2
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. 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
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2020		December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative liabilities	$	—	$	1
Fixed price swaps – natural gas	Derivative liabilities	15		1
Fixed price swaps – oil	Derivative liabilities	1		6
Fixed price swaps – ethane	Derivative liabilities	10		—
Fixed price swaps – propane	Derivative liabilities	5		—
Two-way costless collars – natural gas	Derivative liabilities	52		4
Two-way costless collars – oil	Derivative liabilities	2		5
Three-way costless collars – natural gas	Derivative liabilities	164		84
Three-way costless collars – oil	Derivative liabilities	10		4
Basis swaps – natural gas	Derivative liabilities	3		17
Call options – natural gas	Derivative liabilities	24		3
Fixed price swaps – natural gas storage	Derivative liabilities	1		—
Fixed price swaps – natural gas	Long-term derivative liabilities	6		—
Fixed price swaps – oil	Long-term derivative liabilities	—		2
Fixed price swaps – ethane	Long-term derivative liabilities	4		—
Fixed price swaps – propane	Long-term derivative liabilities	2		—
Two-way costless collars – natural gas	Long-term derivative liabilities	27		4
Three-way costless collars – natural gas	Long-term derivative liabilities	106		72
Three-way costless collars – oil	Long-term derivative liabilities	10		8
Basis swap – natural gas	Long-term derivative liabilities	4		9
Call options – natural gas	Long-term derivative liabilities	29		15
Call options – oil	Long-term derivative liabilities	—		1
Total derivative liabilities		$	475	$	236

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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 September 30, 2020 and 2019:

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
	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		2020			2019			2020			2019
		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	4		$	—		$	4		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(138)			(19)			(74)			36
Fixed price swaps – oil	Gain (Loss) on Derivatives	(20)			8			54			5
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(13)			1			(23)			8
Fixed price swaps – propane	Gain (Loss) on Derivatives	(17)			10			(25)			19
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(34)			(11)			(45)			(2)
Two-way costless collars – oil	Gain (Loss) on Derivatives	(5)			—			4			(3)
Two-way costless collars – propane	Gain (Loss) on Derivatives	(1)			1			(2)			3
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(98)		(1)	3			(194)		(1)	27
Three-way costless collars – oil	Gain (Loss) on Derivatives	(4)			3			15			4
Basis swaps – natural gas	Gain (Loss) on Derivatives	54			12			40			6
Call options – natural gas	Gain (Loss) on Derivatives	(16)			1			(25)			5
Call options – oil	Gain (Loss) on Derivatives	—			—			1			—
Purchased 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	Gain (Loss) on Derivatives	—			1			—			(1)
Total gain (loss) on unsettled derivatives		$	(289)		$	12		$	(272)		$	108
Settled Gain (Loss) on Derivatives Recognized in Earnings (2)
	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		2020			2019			2020			2019
		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(2)		$	—		$	(4)		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	61		(3)	45			150		(3)	53
Fixed price swaps – oil	Gain (Loss) on Derivatives	17			3			44			5
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(2)			6			6			12
Fixed price swaps – propane	Gain (Loss) on Derivatives	2			11			19			20
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(5)			10			1			12
Two-way costless collars – oil	Gain (Loss) on Derivatives	4			2			13			4
Two-way costless collars – propane	Gain (Loss) on Derivatives	—			1			2			1
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	—			15			43			19
Three-way costless collars – oil	Gain (Loss) on Derivatives	1			—			5			—
Basis swaps – natural gas	Gain (Loss) on Derivatives	20			(3)			29			(11)
Call options – natural gas	Gain (Loss) on Derivatives	—			(1)		(4)	—			(2)		(4)
Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	1			(1)			2			(1)
Total gain on settled derivatives		$	97		$	88		$	310		$	112
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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(9) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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 nine months ended September 30, 2020:

(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2019	$	(19)	$	(14)	$	(33)
Other comprehensive income before reclassifications	—		—		—
Amounts reclassified from other comprehensive income (1)	1		—		1
Net current-period other comprehensive income	1		—		1
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	$	1
	Provision (Benefit) for Income Taxes	—
	Net Income (Loss)	$	1
Total reclassifications for the period	Net Income (Loss)	$	1

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

(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 September 30, 2020 and December 31, 2019 were as follows:

	September 30, 2020						December 31, 2019
(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	95		$	95		$	5		$	5
2018 revolving credit facility due April 2024	—			—			34			34
Senior notes (1)	2,471			2,429			2,228			2,085
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 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 remaining senior notes are considered the be a Level 1 measurement. The carrying values of the borrowings under the Company’s revolving credit facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates.  The Company considers the fair value of its revolving credit facility to be a Level 1 measurement on the fair value hierarchy.

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

	September 30, 2020
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	3	$	—	$	3
Fixed price swaps (1)	—		82		—		82
Two-way costless collars	—		46		—		46
Three-way costless collars (2)	—		153		—		153
Basis swaps	—		53		—		53
Call options	—		13		—		13
Liabilities
Fixed price swaps	—		(43)		—		(43)
Two-way costless collars	—		(81)		—		(81)
Three-way costless collars	—		(290)		—		(290)
Basis swaps	—		(7)		—		(7)
Call options	—		(53)		—		(53)
Fixed price swaps – storage	—		(1)		—		(1)
Total (3)	$	—	$	(125)	$	—	$	(125)

(1)Includes $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 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 $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 of $1 million related to estimated nonperformance risk.

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	December 31, 2019
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Fixed price swaps (1)	$	—	$	124	$	—	$	124
Two-way costless collars	—		21		—		21
Three-way costless collars	—		210		—		210
Basis swaps	—		32		—		32
Call options	—		3		—		3
Fixed price swaps - storage	—		1		—		1
Liabilities
Purchased fixed price swaps	—		(1)		—		(1)
Fixed price swaps	—		(9)		—		(9)
Two-way costless collars	—		(13)		—		(13)
Three-way costless collars	—		(168)		—		(168)
Basis swaps	—		(26)		—		(26)
Call options	—		(19)		—		(19)
Total	$	—	$	155	$	—	$	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 third quarters of 2020 and 2019.

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(11) DEBT

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

	September 30, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (1.60% at September 30, 2020) 2018 revolving credit facility due April 2024	$	—	$	—	(1)	$	—	$	—
4.10% Senior Notes due March 2022	207		—			—		207
4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(6)			—		612
7.75% Senior Notes due October 2027	440		(5)			—		435
8.375% Senior Notes due September 2028 (3)	350		(5)			—		345
Total long-term debt	$	2,471	$	(20)		$	(1)	$	2,450
	December 31, 2019
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	$	34	$	—	(1)	$	—	$	34
4.10% Senior Notes due March 2022	213		(1)			—		212
4.95% Senior Notes due January 2025 (2)	892		(5)			(1)		886
7.50% Senior Notes due April 2026	639		(7)			—		632
7.75% Senior Notes due October 2027	484		(6)			—		478
Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242

(1)At 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.

(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate 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, in October 2020, the banks participating in the 2018 credit facility reaffirmed the elected borrowing base and aggregate commitments to be $1.8 billion. The borrowing base is subject to redetermination at least twice a year, in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets.

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

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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, 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 September 30, 2020, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility.

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

As of September 30, 2020, the Company had $203 million in letters of credit and no borrowings outstanding under the 2018 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

The Company’s 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.  Effective in July 2018, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the 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 half of 2020, the Company repurchased $6 million of its 4.10% Senior Notes due 2022, $36 million of its 4.95% Senior Notes due 2025, $21 million of its 7.50% Senior Notes due 2026 and $44 million of its 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

In August 2020, the Company completed a public offering of $350 million aggregate principal amount of its 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.

(12) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

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

	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Infrastructure currently in service	$	6,704	$	582	$	1,308	$	1,078	$	1,411	$	2,325
Pending regulatory approval and/or construction (1)	405		3		9		23		52		318
Total transportation charges	$	7,109	$	585	$	1,317	$	1,101	$	1,463	$	2,643

(1)Based on estimated in-service dates as of 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 September 30, 2020, approximately $27 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $13 million through December 2020 depending on the buyer’s actual use, and has recorded a $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 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 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 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, 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. No material liabilities have been recognized in connection with these indemnifications.

(13) INCOME TAXES

The Company’s effective tax rate was approximately 0% and (16)% for the three and nine months ended September 30, 2020, respectively. The change in the effective tax rate for the nine months ended 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 addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in its valuation allowance 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 18% and (105)% for the three and nine months ended September 30, 2019, respectively. The effective tax rate for the nine months ended 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 $400 million was released on a discrete basis in the first nine months of 2019.

(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 September 30, 2020 and 2019:

	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)		2020		2019		2020		2019
Service cost	General and administrative expenses	$	2	$	1	$	6	$	5
Interest cost	Other Income (Loss), Net	1		2		3		4
Expected return on plan assets	Other Income (Loss), Net	(2)		(1)		(5)		(4)
Amortization of prior service cost	Other Income (Loss), Net	—		—		—		—
Amortization of net loss	Other Income (Loss), Net	1		—		1		1
Settlement loss	Other Income (Loss), Net	—		1		—		5
Net periodic benefit cost		$	2	$	3	$	5	$	11

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million for the three months ended 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 September 30, 2020, the Company has contributed $12 million to the pension and other postretirement benefit plans and does not expect to contribute to its pension plan during the remainder of 2020.  The Company recognized liabilities of $22 million and $14 million related to its pension and other postretirement benefits, respectively, as of 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 September 30, 2020 and December 31, 2019, respectively.

(15) LONG-TERM INCENTIVE COMPENSATION

The Company’s long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but subject to meeting annual performance thresholds. In March 2020, the Company issued its first long-term fixed cash-based awards.

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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 September 30, 2020 and 2019:

	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 September 30, 2020 and 2019:

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

As of September 30, 2020, there was $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 0.5 years.

Equity-Classified Stock Options

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

	Number of Options	Weighted Average Exercise Price
	(in thousands)
Outstanding at December 31, 2019	4,635	$	15.26
Granted	—	$	—
Exercised	—	$	—
Forfeited or expired	(357)	$	7.06
Outstanding at September 30, 2020	4,278	$	15.95
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 nine months ended September 30, 2020 and provides information for unvested shares as of September 30, 2020:

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

Equity-Classified Performance Units

The following table summarizes equity-classified performance unit activity for the nine months ended September 30, 2020 and provides information for unvested units as of 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
	(in thousands)
Unvested units at December 31, 2019	178	$	10.47
Granted	—	$	—
Vested	(178)	$	10.47
Forfeited	—	$	—
Unvested units at September 30, 2020	—	$	—

(1)The actual payout of shares may range from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR.  The performance units have a 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 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 September 30, 2020:

	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Liability-classified stock-based compensation cost – expensed	$	2	$	(1)	$	6	$	6
Liability-classified stock-based compensation cost – capitalized	1		—		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 September 30, 2020, there was $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 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
	(in thousands)
Unvested units at December 31, 2019	12,992	$	2.42
Granted	6,172	$	1.41
Vested	(3,946)	$	1.42
Forfeited	(3,060)	$	1.53
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 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 September 30, 2020, there was $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 2.2 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
	(in thousands)
Unvested units at December 31, 2019	5,142	$	2.42
Granted	6,172	$	1.41
Vested	—	$	—
Forfeited	(2,300)	$	3.06
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 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 September 30, 2020, there was $16 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 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
	(in thousands)
Unvested units at December 31, 2019	—	$	—
Granted	20,044	$	1.00
Vested	(100)	$	1.00
Forfeited	(729)	$	1.00
Unvested units at September 30, 2020	19,215	$	1.00

(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 (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
	(in millions)
Three months ended September 30, 2020
Revenues from external customers	$	308		$	219	$	—		$	527
Intersegment revenues	(10)			276		—			266
Depreciation, depletion and amortization expense	68			2		—			70
Impairments	361			—		—			361
Operating loss	(379)		(1)	(2)		—			(381)
Interest expense (2)	22			—		—			22
Loss on derivatives	(192)			—		—			(192)
Other income, net	2			—		—			2
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	223			—		—			223
Three months ended September 30, 2019
Revenues from external customers	$	357		$	279	$	—		$	636
Intersegment revenues	(9)			313		—			304
Depreciation, depletion and amortization expense	123			2		—			125
Impairments	—			2		—			2
Operating loss	(21)		(1)	(8)		—			(29)
Interest expense (2)	17			—		—			17
Gain on derivatives	100			—		—			100
Gain on early extinguishment of debt	—			—		7			7
Other income (loss), net	(4)			—		2			(2)
Provision for income taxes (2)	10			—		—			10
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	239			—		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	$	—		$	1,529
Intersegment revenues	(31)			787		—			756
Depreciation, depletion and amortization expense	260			7		—			267
Impairments	2,495			—		—			2,495
Operating loss	(2,613)		(1)	(14)		—			(2,627)
Interest expense (2)	63			—		—			63
Gain on derivatives	38			—		—			38
Gain on early extinguishment of debt	—			—		35			35
Other income, net	2			—		1			3
Provision for income taxes (2)	406			—		—			406
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	705			—		—			705
Nine months ended September 30, 2019
Revenues from external customers	$	1,288		$	1,005	$	—		$	2,293
Intersegment revenues	(27)			1,154		—			1,127
Depreciation, depletion and amortization expense	345			7		—			352
Impairments	6			2		—			8
Operating income (loss)	219		(1)	(13)		—			206
Interest expense (2)	46			—		—			46
Gain on derivatives	220			—		—			220
Gain on early extinguishment of debt	—			—		7			7
Other income (loss), net	(8)			—		1			(7)
Benefit from income taxes (2)	(401)			—		—			(401)
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	931			—		2			933

(1)Operating income (loss) for the E&P segment includes $4 million of restructuring charges for the three months ended 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. E&P assets also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At September 30, 2020 and 2019, other assets included approximately $95 million and $29 million, respectively, in cash and cash equivalents, $74 million and $84 million in right-of-use lease assets, respectively, $18 million and $31 million, respectively, in property, plant and equipment, $10 million and $9 million, respectively, in unamortized debt expense, $5 million and $7 million, respectively, in a non-qualified retirement plan and $3 million and $7 million in 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 decreases of $7 million and $53 million for the three months ended 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 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 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.

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 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 third quarter 2020 operating and financial results include:

Total Company

•Net loss of $593 million, or ($1.04) per diluted share, decreased compared to net income of $49 million, or $0.09 per diluted share, for the same period in 2019. The decrease was primarily due to a $361 million non-cash full cost ceiling test impairment, a $292 million reduction in the impact of derivatives (which included a $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) and lower margins associated with reduced commodity prices.

•Operating loss of $381 million increased compared to operating loss of $29 million for the same period in 2019 on a consolidated basis primarily due to a $361 million non-cash full cost ceiling test impairment in the third quarter of 2020. Excluding the non-cash impairment, operating loss of $20 million improved $9 million compared to the same period in 2019 as lower margins associated with reduced commodity 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 $153 million decreased 22% from $196 million for the same period in 2019 as improvements in settled derivatives discussed 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 investment of $223 million decreased 7% from $240 million for the same period in 2019.

•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 after underwriting discounts and offering expenses.

•Closed an offering of $350 million aggregate principal amount of 8.375% Senior Notes due 2028 with net proceeds of $345 million after underwriting discounts and offering expenses.

E&P

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

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

•Excluding the effect of derivatives, our realized natural gas price of $1.09 per Mcf decreased 25%, our realized oil price of $29.46 per barrel decreased 37% and our realized NGL price of $10.34 per barrel increased 16% as compared to the same period in 2019. Excluding the effect of derivatives, our total weighted average realized price of $1.34 per Mcfe decreased 22% from the same period in 2019.

•E&P segment invested $223 million in capital; drilling 16 wells, completing 25 wells and placing 30 wells to sales.

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 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. During the first 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 34% since the beginning of 2020. In first nine months of 2020, gains on settled derivatives offset a large portion of the impact of the recent decline in prices, and as of October 27, 2020, we currently have derivative positions in place for 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 8 - Derivatives and Risk Management, in the consolidated financial statements included in this Quarterly Report for further details.

Market Conditions and Commodity Prices

During the first 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” 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. 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, and we have instituted additional measures designed to prevent the possible spread of the virus, including social distancing and appropriate personal protective 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 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. In addition, although natural gas prices were not impacted as severely as oil prices, as of September 30, 2020, we have protected the price of approximately 96% of expected remaining 2020 gas production through derivatives.

Late in the second quarter of 2020 and extending into the third quarter of 2020, certain states and local governments began the process of loosening restrictions, allowing businesses to reopen and lifting stay-at-home orders. In addition, OPEC and other countries instituted oil production curtailments. During this same period, oil and NGL prices have improved from historic lows in April due to lower industry-wide production levels and increased export demand, respectively. Further, although the reduced production of natural gas associated with oil wells 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 have improved from earlier in the year, and we continue to mitigate pricing risk for all of our commodities through our proactive derivative program.

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 this matter 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 September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Revenues	$	298	$	348	$	853	$	1,261
Operating costs and expenses (1)	677		369		3,466		1,042
Operating income (loss)	$	(379)	$	(21)	$	(2,613)	$	219
Gain on derivatives, settled (2)	$	97	$	88	$	310	$	112

(1)Includes $361 million and $2,490 million related to non-cash full cost ceiling test impairments for the three and nine months ended 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)

•E&P segment operating loss increased $358 million for the three months ended September 30, 2020, compared to the same period in 2019, primarily due to a $361 million non-cash full cost ceiling test impairment. Excluding the 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 $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 September 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues	$	230		$	66		$	52		$	348
Changes associated with prices	(62)			(21)			9			(74)
Changes associated with production volumes	22			(6)			7			23
2020 sales revenues (1)	$	190		$	39		$	68		$	297
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 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.

(3)Excludes $4 million in other operating revenues for the nine months ended 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 September 30,				Increase/(Decrease)	For the nine months ended September 30,				Increase/(Decrease)
Production volumes:	2020		2019			2020		2019
Natural Gas (Bcf)
Northeast Appalachia	121		118		3%	348		343		1%
Southwest Appalachia	52		40		30%	139		106		31%
Total	173		158		9%	487		449		8%
Oil (MBbls)
Southwest Appalachia	1,290		1,413		(9)%	3,764		3,193		18%
Other	4		6		(33)%	12		17		(29)%
Total	1,294		1,419		(9)%	3,776		3,210		18%
NGL (MBbls)
Southwest Appalachia	6,687		5,908		13%	18,924		17,003		11%
Other	—		3		(100)%	2		8		(75)%
Total	6,687		5,911		13%	18,926		17,011		11%
Production volumes by area: (Bcfe)
Northeast Appalachia	121		118		3%	348		343		1%
Southwest Appalachia	100		84		19%	275		227		21%
Total (1)	221		202		9%	623		570		9%
Production percentage: (Bcfe)
Natural gas	78	%	78	%		78	%	79	%
Oil	4	%	4	%		4	%	3	%
NGL	18	%	18	%		18	%	18	%

(1)Approximately 221 Bcfe and 201 Bcfe for the three months ended September 30, 2020 and 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.

•E&P production volumes increased by 19 Bcfe for the three months ended September 30, 2020 compared to the same period in 2019, primarily due to a 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 13% for the three months ended 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 September 30,						Increase/(Decrease)	For the nine months ended September 30,						Increase/(Decrease)
	2020			2019				2020			2019
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	1.98		$	2.23		(11)%	$	1.88		$	2.67		(30)%
Discount to NYMEX (2)	(0.89)			(0.78)			14%	(0.68)			(0.63)			8%
Average realized gas price, excluding derivatives ($/Mcf)	$	1.09		$	1.45		(25)%	$	1.20		$	2.04		(41)%
Gain (loss) on settled financial basis derivatives ($/Mcf)	0.12			(0.01)				0.06			(0.02)
Gain (loss) on settled commodity derivatives ($/Mcf)	0.31			0.43				0.39			0.18
Average realized gas price, including derivatives ($/Mcf)	$	1.52		$	1.87		(19)%	$	1.65		$	2.20		(25)%
Oil Price:
WTI oil price ($/Bbl)	$	40.93		$	56.45		(27)%	$	38.32		$	57.06		(33)%
Discount to WTI	(11.47)			(9.91)			16%	(10.12)			(9.92)			2%
Average oil price, excluding derivatives ($/Bbl)	$	29.46		$	46.54		(37)%	$	28.20		$	47.14		(40)%
Gain on settled derivatives ($/Bbl)	17.23			3.13				16.77			2.60
Average oil price, including derivatives ($/Bbl)	$	46.69		$	49.67		(6)%	$	44.97		$	49.74		(10)%
NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	10.34		$	8.89		16%	$	8.37		$	11.24		(26)%
Gain on settled derivatives ($/Bbl)	0.16			3.04				1.48			1.94
Average realized NGL price, including derivatives ($/Bbl)	$	10.50		$	11.93		(12)%	$	9.85		$	13.18		(25)%
Percentage of WTI, excluding derivatives	25		%	16		%		22		%	20		%
Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	1.34		$	1.72		(22)%	$	1.36		$	2.21		(38)%
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 8 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 September 30, 2020:

	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 September 30, 2020:

	Remaining 2020	Full Year 2021	Full Year 2022	Full Year 2023
Natural gas (Bcf)	173	550	185	25
Oil (MBbls)	1,249	4,019	1,428	111
Ethane (MBbls)	2,629	6,473	325	—
Propane (MBbls)	1,527	4,298	156	—
Normal Butane (MBbls)	195	—	—	—
Natural Gasoline (MBbls)	184	—	—	—
Total financial protection on future production (Bcfe)	208	639	196	26

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

Operating Costs and Expenses

	For the three months ended 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)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.

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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.

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

•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 $12 million for the nine months ended months ended September 30, 2020 related to cash severance, including payroll taxes.

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

•Interest expense related to our senior notes remained flat for the three months ended September 30, 2020 and decreased for the nine months ended September 30, 2020, compared to the same periods of 2019, as we repurchased $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 September 30, 2020, respectively, compared to the same 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 September 30, 2020, compared to the same 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 September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Gain (loss) on unsettled derivatives	$	(289)	$	12	$	(272)	$	108
Gain on settled derivatives	97		88		310		112
Gain (loss) on derivatives	$	(192)	$	100	$	38	$	220

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

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Gain/Loss on Early Extinguishment of Debt

For the nine months ended September 30, 2020, we recorded a gain on early extinguishment of debt of $35 million as a result of our repurchase of $107 million in aggregate principal amount of our outstanding senior notes for $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 11 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.

Income Taxes

	For the three months ended 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, we concluded that it was more likely than not that the deferred tax asset would be realized and released substantially all of the valuation allowance. This resulted in a discrete tax benefit of $400 million being recorded in the first three quarters of 2019. However, due to commodity price declines during 2020 and the write-down of the carrying value of our natural gas and oil properties, in addition to other negative evidence, we concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in our valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. We also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.

New Accounting Standards Implemented in this Report

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

New Accounting Standards Not Yet Implemented in this Report

Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards 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. In October 2020, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $1.8 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 $2.0 billion, the maximum permitted lien amount based on provisions in certain of our senior note indentures. As of October 27, 2020, we had 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 11 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2018 credit facility and related covenant requirements.

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 “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 three quarters of 2020, $310 million in realized gains on derivatives have offset a large portion of the impact of lower commodity prices, and as of October 27, 2020, we currently have derivative positions in place for over 90% of our expected remaining 2020 production, including over 70% of our expected 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 8 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 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.

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, in October 2020, the banks participating in our 2018 credit facility reaffirmed the borrowing base to be $1.8 billion, which also reflects our aggregate commitments. The borrowing base is subject to redetermination at least twice a year, in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital 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 October 8, 2020, we entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters, limit our unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions, and to 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 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 September 30, 2020, we had no borrowings outstanding on our 2018 credit facility and $203 million in outstanding letters of credit. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility.

As of September 30, 2020, we were in compliance with all of the covenants contained in the credit agreement governing our revolving credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas and liquids. We refer you to Note 11 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2018 credit facility.

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

Our exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and Southwestern. The alternative rate will be based on the prevailing market convention and is expected to be 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 nine months of 2020, we repurchased $6 million of our 4.10% Senior Notes due 2022, $36 million of our 4.95% Senior Notes due 2025, $21 million of our 7.50% Senior Notes due 2026 and $44 million of our 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

For the three months ended September 30, 2019, we recorded a $7 million gain on extinguishment of debt as a result of our repurchase of $50 million in aggregate principal amount of our 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 $207 million of our senior notes outstanding as of September 30, 2020 are scheduled to become due prior to 2025.

At October 27, 2020, we had a long-term issuer credit rating of Ba2 by Moody’s (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.

Cash Flows

	For the nine months ended September 30,
(in millions)	2020		2019
Net cash provided by operating activities	$	407	$	739
Net cash used in investing activities	(698)		(835)
Net cash provided by (used in) financing activities	381		(76)

Cash Flow from Operating Activities

	For the nine months ended September 30,
(in millions)	2020		2019
Net cash provided by operating activities	$	407	$	739
Add back (subtract) changes in working capital	(9)		(88)
Net cash provided by operating activities, net of changes in working capital	$	398	$	651

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

•Net cash generated from operating activities, net of changes in working capital, provided 56% of our cash requirements for capital investments for the nine months ended September 30, 2020, compared to providing 70% of our cash requirements for capital investments for the same period in 2019. Consistent with past years, our capital program for 2020 is weighted to the first half of the year. We remain committed to our disciplined capital strategy.

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Cash Flow from Investing Activities

•Total capital investments decreased $17 million for the three months ended 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 $192 million decrease in direct E&P capital investments and a $34 million decrease in capitalized interest and internal costs, as compared to the same period in 2019.

	For the nine months ended September 30,
(in millions)	2020		2019
Additions to properties and equipment	$	700	$	877
Adjustments for capital investments
Changes in capital accruals	1		52
Other (1)	4		4
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 Investment

	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 investment was immaterial for the three and nine months ended September 30, 2020 and 2019.

	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
E&P Capital Investments by Type:
Exploratory and development drilling, including workovers	$	163	$	176	$	550	$	711
Acquisition of properties	15		9		29		32
Seismic expenditures	—		—		—		2
Water infrastructure project	5		6		8		32
Other	3		3		12		14
Capitalized interest and expenses	37		45		106		140
Total E&P capital investments	$	223	$	239	$	705	$	931
E&P Capital Investments by Area:
Northeast Appalachia	$	98	$	74	$	299	$	306
Southwest Appalachia	117		154		386		575
Other E&P (1)	8		11		20		50
Total E&P capital investments	$	223	$	239	$	705	$	931

(1)Includes $5 million and $6 million for the three months ended 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 September 30,		For the nine months ended September 30,
	2020	2019	2020	2019
Gross Operated Well Count Summary:
Drilled	16	24	84	95
Completed	25	30	78	101
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 the first nine months of 2020, we repurchased $107 million in aggregate principal amount of our outstanding senior notes at a discount for $72 million, and recognized a $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 11 of the consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

We had negative working capital of $256 million at September 30, 2020, an $87 million decrease from December 31, 2019, as a $90 million 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 related to improved forward strip pricing across all commodities, as compared to December 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 the fourth quarter of 2020. See Note 2 to 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 September 30, 2020, our material off-balance sheet arrangements and transactions include operating service arrangements and $203 million in letters of credit outstanding against our 2018 credit facility.  There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.  For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” 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 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 $7.1 billion, $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 $1.0 billion.  As of September 30, 2020, future payments under non-cancelable firm transportation and gathering agreements are as follows:

	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 years		More than 8 Years
Infrastructure currently in service	$	6,704	$	582	$	1,308	$	1,078	$	1,411	$	2,325
Pending regulatory approval and/or construction (1)	405		3		9		23		52		318
Total transportation charges	$	7,109	$	585	$	1,317	$	1,101	$	1,463	$	2,643

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

Included in the transportation charges above are $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 the purchaser of the Fayetteville Shale assets. Of these amounts, we may be obligated to reimburse the purchaser for a portion of volumetric shortfalls during 2020 (up to $13 million) under these transportation agreements and have currently recorded a $10 million liability as of 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 nine months ended September 30, 2020, we have contributed $12 million to the pension and postretirement benefit plans, and we expect no further contributions to our pension plan during the remainder of 2020.  We recognized liabilities of $36 million and $43 million as of 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 14 to the consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

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

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

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

Supplemental Guarantor Financial Information

As discussed in Note 11, in April 2018 the Company entered into the 2018 credit facility.  Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of our senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 credit facility but not of the senior notes.   These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries.  Certain of our operating units 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 and basis swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs.  Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk.  These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our exposure to concentrations of credit risk consists primarily of trade receivables and derivative contracts associated with commodities trading.  Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas.  However, at September 30, 2020, one purchaser accounted for 10% of our revenues. A default on this account could have a material impact on the Company, but we do not believe that there is a material risk of a default. 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 September 30, 2020, we had approximately $2.5 billion of outstanding senior notes with a weighted average interest rate of 7.02%, and we had no borrowings under our revolving credit facility.  At September 30, 2020, we had a long-term issuer credit rating of Ba2 by Moody’s, a long-term debt rating of BB- by S&P and a long-term issuer default rating of BB by Fitch Ratings.  In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on our 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate 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.

	Expected Maturity Date
($ in millions)	2021			2022			2023			2024			2025			Thereafter			Total
Fixed rate payments (1)	$	—		$	207		$	—		$	—		$	856		$	1,408		$	2,471
Weighted average interest rate	—		%	4.10		%	—		%	—		%	6.45		%	7.80		%	7.02		%
Variable rate payments (1)	$	—		$	—		$	—		$	—		$	—		$	—		$	—
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 8 and Note 10 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

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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 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 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 12 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s 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 completion of 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 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 failure to otherwise complete the Merger may result in various consequences, including:

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

52

•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 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 and 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.

The success of the Merger will depend, in part, on Southwestern’s ability to 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 integrating Southwestern and Montage may result in the combined company performing differently than expected, in operational challenges, or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

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

•not realizing anticipated operating synergies;

•integrating personnel from the two companies and the loss of key employees;

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

•integrating relationships with customers, vendors and business partners;

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

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

Completion of the Merger may trigger change in control or other provisions in certain agreements to which Montage is a party, which may have an adverse impact on the combined company’s business and results 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 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 restated retroactively to reflect the historical financial position or results of operations of Montage and its subsidiaries for periods prior to the merger.

53

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

Not applicable.

54

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

໿

55

EX-31.1

Document

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Julian M. Bott, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Southwestern Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

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

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

In connection with the Quarterly Report of Southwestern Energy Company, a Delaware corporation (the “Corporation”) on Form 10-Q for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, William J. Way, Director, President and Chief Executive Officer of the Corporation, certify to my knowledge, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

Dated:   October 29, 2020	/s/ WILLIAM J. WAY
	William J. Way
	Director, President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

In connection with the Quarterly Report of Southwestern Energy Company, a Delaware corporation (the “Corporation”) on Form 10-Q for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Julian M. Bott, Executive Vice President and Chief Financial Officer of the Corporation, certify to my knowledge, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

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

EX-95.1

EXHIBIT 95.1

Mine Safety Disclosure

The following disclosure is provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977.

The table that follows reflects citations, orders, violations and proposed assessments issued by the Mine Safety and Health Administration (the “MSHA”) to A. W. Realty, LLC, an indirect wholly owned subsidiary of Southwestern Energy Company.  The disclosure is with respect to the three months ended September 30, 2020.  Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by the MSHA at www.MSHA.gov.

Southwestern Energy Company

Mine Safety Disclosure

Three Months Ended September 30, 2020

(Unaudited)

Operation(1)

Section 104 S&S Citations

Section 104(b) Orders

Section 104(d) Citations and Orders

Section 110(b)(2) Violations

Section 107(a) Orders

Section 107(a) Orders

Total Dollar Value of Proposed MSHA Assessments (2)

Total Number of Mining Related  Fatalities

Received Notice of Pattern of Violations Under Section 104(e)

Received Notice of Potential to Have Pattern Under Section 104(e)

Legal Actions Pending as of the Last Day of  Period

Legal Actions Initiated During  Period

Legal Actions Resolved During Period

A. W. Realty Company, LLC

—

—

—

—

—

—

$—

—

—

—

—

Total

$—

No

No

(1)The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools, and preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine.

(2)The whole-dollar amounts included are the total dollar value of all proposed or outstanding assessments, regardless of classification, received from MSHA on or before September 30, 2020 regardless of whether the assessment has been challenged or appealed, for alleged violations occurring during the three month period ended September 30, 2020. Citations and orders can be contested and appealed, and as part of that process, are sometimes reduced in severity and amount, and are sometimes dismissed. The number of citations, orders, and proposed assessments vary by inspector and also vary depending on the size and type of the operation.

EX-10.2

AMENDMENT NO. 6 TO CREDIT AGREEMENT

THIS AMENDMENT NO. 6 TO CREDIT AGREEMENT (this “Amendment”) is entered into as of July 31, 2020 by and among SOUTHWESTERN ENERGY COMPANY, a Delaware corporation (the “Borrower”), the Lenders signatory hereto and JPMORGAN CHASE BANK, N.A., as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

RECITALS:

WHEREAS, reference is made to that certain Credit Agreement dated as of April 26, 2018, by and among the Borrower, the Lenders from time to time party thereto and the Administrative Agent (as amended by that certain Amendment No. 1 to Credit Agreement dated as of October 23, 2018, that certain Amendment No. 2 to Credit Agreement dated as of October 8, 2019, that certain Amendment No. 3 to Credit Agreement dated as of November 1, 2019, that certain Amendment No. 4 to Credit Agreement dated as of December 20, 2019, and that certain Amendment No. 5 to Credit Agreement dated as of January 31, 2020, the “Credit Agreement”); and

WHEREAS, the Borrower has requested that the Lenders agree to amend certain provisions of the Credit Agreement, and the Lenders party hereto, which constitute the Majority Lenders, have agreed to amend the Credit Agreement as hereinafter set forth.

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.     Defined Terms. Capitalized terms used but not otherwise defined herein shall have the meanings assigned to them in the Credit Agreement, as amended hereby.

Section 2.    Amendments to Credit Agreement.

(a)    Section 1.01 of the Credit Agreement is amended by amending and restating the following defined term:

“Swap Calculation Date” means each of March 31, 2020, June 30, 2020, September 30, 2020, December 31, 2020, March 31, 2021, June 30, 2021, and September 30, 2021.

(b)    Section 6.13(a)(i)(A) of the Credit Agreement is hereby amended and restated as follows:

(A)    for the period from the date of entering into such hedging transaction through the twenty-fourth (24th) month from the date of entering into such hedging transaction, ninety percent (90%) of the reasonably anticipated projected production of crude oil, natural gas liquids and natural gas (calculated separately on a monthly basis) from Proved Reserves of the Loan Parties evaluated in the most recently delivered Reserve Report (provided that (i) for the period from

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

November 1, 2019 through December 31, 2019, such ninety percent (90%) limitation shall instead be one hundred percent (100%) of the reasonably anticipated projected production of crude oil, natural gas liquids and natural gas (calculated separately on a monthly basis) from Proved Reserves of the Loan Parties evaluated in the most recently delivered Reserve Report, (ii) for natural gas for the period from January 1, 2020 through December 31, 2021, such ninety percent (90%) limitation shall instead be one hundred percent (100%) of the reasonably anticipated projected production of natural gas (calculated on a monthly basis) from Proved Reserves of the Loan Parties evaluated in the most recently delivered Reserve Report and (iii) for crude oil and natural gas liquids for the period from February 1, 2020 through December 31, 2021, such ninety percent (90%) limitation shall instead be one hundred percent (100%) of the reasonably anticipated projected production of crude oil or natural gas liquids (calculated separately on a monthly basis) from Proved Reserves of the Loan Parties evaluated in the most recently delivered Reserve Report); and

(c)    Section 6.13(d) of the Credit Agreement is hereby amended and restated as follows:

(d) The Borrower will not, as of any Swap Calculation Date, permit the aggregate notional volumes for all Swap Agreements in respect of commodities to which the Borrower or any Restricted Subsidiary is a party ((x) excluding basis differential swaps on volumes hedged pursuant to other Swap Agreements, (y) only including the notional volume of one leg of Swap Agreements that are collars, and (z) excluding any Terminating Futures Contracts as of such Swap Calculation Date) to exceed the limits set forth in Section 6.13(a)(i)(A)(ii) or (iii) for any future month ending after such Swap Calculation Date and on or before December 31, 2021 (and for this purpose, Section 6.13(a) shall be recalculated and tested as of the Swap Calculation Date as if all outstanding Swap Agreements in respect of commodities were being entered into on such Calculation Date); provided that, if the foregoing limit is exceeded as of any Swap Calculation Date, it shall not constitute a violation of this Section 6.13(d) if the Borrower shall, no later than sixty (60) days after such Swap Calculation Date, terminate, create off-setting positions or otherwise unwind existing Swap Agreements such that, at such date of termination, creation of offsetting positions or unwind (the “Swap Unwind Date”), after giving effect to such termination, offsetting position or unwind, future hedging volumes will not exceed the limits set forth in Section 6.13(a) (and for this purpose, Section 6.13(a) shall be recalculated and tested as of the Swap Unwind Date as if all outstanding Swap Agreements in respect of commodities (after giving effect to any such termination, offsetting position or unwind) were being entered into on such Swap Unwind Date and the Borrower shall provide the Administrative Agent evidence reasonably satisfactory to it demonstrating such compliance).

Section 3.    Amendment No. 6 Effective Date; Conditions Precedent. This Amendment shall become effective on the date (the “Amendment No. 6 Effective Date”) on which the following conditions have been satisfied:

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

(a)    the Administrative Agent shall have received, in form and substance reasonably satisfactory to the Administrative Agent, a counterpart of this Amendment executed by the Borrower, the Administrative Agent and Lenders constituting the Majority Lenders;

(b)    the Borrower shall have paid to the extent invoiced at or before 1:00 p.m., New York City time, on the Business Day immediately prior to the Amendment No. 6 Effective Date, all out‑of‑pocket expenses required to be reimbursed or paid by the Borrower pursuant to Section 9.03 of the Credit Agreement or any other Loan Document;

(c)    the representations and warranties contained in Section 4 hereof shall be true and correct; and

(d)    no Default or Event of Default shall have occurred and be continuing.

The Administrative Agent shall notify the Borrower and the Lenders of the Amendment No. 6 Effective Date, and such notice shall be conclusive and binding.

Section 4.     Representations and Warranties. To induce the other parties hereto to enter into this Amendment, the Borrower represents and warrants that, before and after giving effect to each of the amendments set forth in this Amendment:

(a)    the representations and warranties set forth in Article III of the Credit Agreement and in the other Loan Documents are true and correct in all material respects (or, in the case of any such representations and warranties that are qualified as to materiality or Material Adverse Effect in the text thereof, such representations and warranties are true and correct in all respects) on and as of the Amendment No. 6 Effective Date, except to the extent made as of a specific date, which representations and warranties shall have been true and correct in all material respects as of such specific date (or, in the case of any such representation and warranties that are qualified as to materiality or Material Adverse Effect in the text thereof, such representations and warranties shall have been true and correct in all respects as of such specific date); and

(b)    no Default or Event of Default has occurred and is continuing on the Amendment No. 6 Effective Date.

Section 5.    Confirmation of Loan Documents. Except as expressly contemplated hereby, the terms, provisions, conditions and covenants of the Credit Agreement, as amended by this Amendment, and the other Loan Documents remain in full force and effect and are hereby ratified and confirmed, and the execution, delivery and performance of this Amendment shall not, except as expressly set forth in this Amendment, operate as a waiver of, consent to or amendment of any term, provision, condition or covenant thereof. Without limiting the generality of the foregoing, except pursuant hereto or as expressly contemplated or amended hereby, nothing contained herein shall be deemed: (a) to constitute a waiver of compliance or consent to noncompliance by any Loan Party with respect to any term, provision, condition or covenant of the Credit Agreement or any other Loan Document; (b) to prejudice any right or remedy that the Administrative Agent or any Lender may now have or may have in the future under or in

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

connection with the Credit Agreement or any other Loan Document; or (c) to constitute a waiver of compliance or consent to noncompliance by the Borrower with respect to the terms, provisions, conditions and covenants of the Credit Agreement and the other Loan Documents made the subject hereof.

Section 6.    Ratification of Collateral Documents. The Borrower hereby acknowledges and ratifies, on behalf of itself and each other Loan Party, the existence and priority of the Liens granted by the Loan Parties in and to the Collateral in favor of the Secured Parties and represents and warrants, on behalf of itself and each other Loan Party, that such Liens and security interests are valid, existing and in full force and effect. The Borrower hereby ratifies and confirms, on behalf of itself and each other Loan Party, each Loan Party’s obligations under the Collateral Documents to which such Loan Party is a party and hereby represents and acknowledges, on behalf of itself and each other Loan Party, that the Loan Parties have no claims, counterclaims, offsets, credits or defenses to the Loan Documents or the performance of their obligations thereunder. Furthermore, the Borrower agrees, on behalf of itself and each other Loan Party, that nothing contained in this Amendment shall adversely affect any right or remedy of the Administrative Agent or the Lenders under the Collateral Documents or any of the other Loan Documents. Finally, the Borrower hereby represents and warrants, on behalf of itself and each other Loan Party, that the execution and delivery of this Amendment and the other documents executed in connection herewith shall in no way change or modify its or any other Loan Party’s obligations as a debtor, pledgor, assignor, obligor, grantor, mortgagor and/or chargor under any Collateral Document and the other Loan Documents and shall not constitute a waiver by the Administrative Agent or the Lenders of any of their rights against any Loan Party.

Section 7.    Effect of Amendment. From and after the Amendment No. 6 Effective Date, each reference in the Credit Agreement to “this Agreement”, “hereof”, or “hereunder” or words of like import, and all references to the Credit Agreement in the Loan Documents and any and all other agreements, instruments, documents, notes, certificates, guaranties and other writings of every kind and nature shall be deemed to mean the Credit Agreement as modified by this Amendment. This Amendment shall constitute a Loan Document for all purposes of the Credit Agreement and the other Loan Documents.

Section 8.    Costs and Expenses. Pursuant to the terms of Section 9.03 of the Credit Agreement, the Borrower agrees to pay all reasonable and documented out-of-pocket expenses incurred by the Administrative Agent and its Affiliates in connection with the preparation, execution and enforcement of this Amendment.

Section 9.    Choice of Law. This Amendment and all other documents executed in connection herewith and the rights and obligations of the parties hereto and thereto, shall be construed in accordance with and governed by the law of the State of New York.

Section 10.    Counterparts; Integration; Effectiveness. This Amendment may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Amendment, the Credit Agreement, the other Loan Documents and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

previous agreements and understandings, oral or written, relating to the subject matter hereof. This Amendment shall become effective on the Amendment No. 6 Effective Date, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page to this Amendment by facsimile, e-mailed .pdf or any other electronic means that reproduces an image of the actual executed signature page shall be effective as delivery of a manually executed counterpart of this Amendment.

Section 11.    Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose.

[Remainder of page intentionally left blank; signature pages follow.]

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.

SOUTHWESTERN ENERGY COMPANY,

a Delaware corporation

By: /s/ Michael Hancock

Name: Michael Hancock

Title: VP, Finance and Treasurer

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

JPMORGAN CHASE BANK, N.A., as

Administrative Agent and as a Lender

By: /s/ Arina Mavilian

Name: Arina Mavilian

Title: Executive Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

BANK OF AMERICA, N.A., as a Lender

By: /s/ Raza Jafferi

Name: Raza Jafferi

Title: Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

CITIBANK, N.A., as a Lender

By: /s/ Ivan Davey

Name: Ivan Davey

Title: Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

MIZUHO BANK, LTD., as a Lender

By: /s/ Edward Sacks

Name: Edward Sacks

Title: Authorized Signatory

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

MUFG BANK, LTD.,

as a Lender

By: /s/ Traci Bankston

Name: Traci Bankston

Title: Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

ROYAL BANK OF CANADA,

as a Lender

By: /s/ Kristan Spivey

Name: Kristan Spivey

Title: Authorized Signatory

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

BANK OF MONTREAL, as a Lender

By: /s/ Hill Taylor

Name: Hill Taylor

Title: Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

SUMITOMO MITSUI BANKING

CORPORATION, as a Lender

By: /s/ Kenji Irie

Name: Kenji Irie

Title: Managing Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

BBVA USA, as a Lender

By: /s/ Gabriela Azcarate

Name: Gabriela Azcarate

Title: Senior Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

CRÉDIT AGRICOLE CORPORATE AND

INVESTMENT BANK, as a Lender

By: /s/ Page C. Dillehunt

Name: Page C. Dillehunt

Title:

By: /s/ Michael Willis

Name: Michael Willis

Title: Managing Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

CANADIAN IMPERIAL BANK OF

COMMERCE, NEW YORK BRANCH

as a Lender

By: /s/ Trudy Nelson

Name: Trudy Nelson

Title: Authorized Signatory

By: /s/ Scott W. Danvers

Name: Scott W. Danvers

Title: Authorized Signatory

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

FIFTH THIRD BANK, NATIONAL

ASSOCIATION,

as a Lender

By: /s/ Larry Hayes

Name: Larry Hayes

Title: Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

CREDIT SUISSE AG, CAYMAN ISLANDS

BRANCH,

as a Lender

By: /s/ Nupur Kumar

Name: Nupur Kumar

Title: Authorized Signatory

By: /s/ Christopher Zybrick

Name: Christopher Zybrick

Title: Authorized Signatory

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

HSBC BANK USA, N.A., as a Lender

By: /s/ Shaun R. Kleinman

Name: Shaun R. Kleinman

Title: Senior Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

REGIONS BANK,

as a Lender

By: /s/ Cody Chance

Name: Cody Chance

Title: Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

PNC BANK, NATIONAL ASSOCIATION,

as a Lender

By: /s/ Denise S. Davis

Name: Denise S. Davis

Title: Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

CITIZENS BANK, N.A.,

as a Lender

By: /s/ David Slye

Name: David Slye

Title: Managing Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

ABN AMRO Capital USA LLC,

as a Lender

By: /s/ David Montgomery

Name: David Montgomery

Title: Managing Director

By: /s/ Darrell Holley

Name: Darrell Holley

Title: Managing Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

WELLS FARGO BANK, N.A., as a Lender

By: /s/ Jonathan Herrick

Name: Jonathan Herrick

Title: Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

NATIXIS, NEW YORK BRANCH,

as a Lender

By: /s/ Yan Meunier

Name: Yan Munier

Title: Executive Director

By: /s/ Ajay Prakash

Name: Ajay Prakash

Title: Director

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By: /s/ George E. McKean

Name: George E. McKean

Title: Senior Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

GOLDMAN SACHS LENDING PARTNERS

LLC, as a Lender

By: /s/ Jamie Minieri

Name: Jamie Minieri

Title: Authorized Signatory

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

MORGAN STANLEY SENIOR FUNDING, INC.,

as a Lender

By: /s/ Tim Kok

Name: Tim Kok

Title: Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

SHELL TRADING RISK MANAGEMENT, LLC,

as a Lender

By: /s/ Carla E. Vincitore

Name: Carla E. Vincitore

Title: President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

TRUIST BANK, fka BRANCH BANKING AND

TRUST COMPANY,

as a Lender

By: /s/ James Giordano

Name: James Giordano

Title: Senior Vice President

Signature Page to Amendment No. 6 to Credit Agreement

(Southwestern Energy Company)

XML

COVER PAGE - shares	9 Months Ended
	Sep. 30, 2020	Oct. 27, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2020
Document Transition Report	false
Entity File Number	001-08246
Entity Registrant Name	Southwestern Energy Company
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Entity Central Index Key	0000007332
Current Fiscal Year End Date	--12-31
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	71-0205415
Entity Address, Address Line One	10000 Energy Drive
Entity Address, City or Town	Spring
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77389
City Area Code	832
Local Phone Number	796-1000
Title of 12(b) Security	Common Stock, Par Value $0.01
Trading Symbol	SWN
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		605,559,524

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Operating Revenues:
Total operating revenues	$ 527	$ 636	$ 1,529	$ 2,293
Operating Costs and Expenses:
Operating expenses	202	189	577	523
General and administrative expenses	31	42	89	119
Montage acquisition-related expenses	3	0	3	0
Restructuring charges	0	4	12	9
Loss on sale of operating assets	0	0	0	3
Depreciation, depletion and amortization	70	125	267	352
Impairments	361	2	2,495	8
Taxes, other than income taxes	15	15	38	51
Total operating costs and expense	908	665	4,156	2,087
Operating Income (Loss)	(381)	(29)	(2,627)	206
Interest Expense:
Interest on debt	43	42	123	125
Other interest charges	2	2	7	5
Interest capitalized	(23)	(27)	(67)	(84)
Total Interest Expense	22	17	63	46
Gain (Loss) on Derivatives	(192)	100	38	220
Gain on Early Extinguishment of Debt	0	7	35	7
Other Income (Loss), Net	2	(2)	3	(7)
Income (Loss) Before Income Taxes	(593)	59	(2,614)	380
Provision (Benefit) for Income Taxes:
Current	0	(1)	(2)	(1)
Deferred	0	11	408	(400)
Total Provision (Benefit) from Income Taxes	0	10	406	(401)
Net Income (Loss)	$ (593)	$ 49	$ (3,020)	$ 781
Earnings (Loss) Per Common Share:
Basic (in dollars per share)	$ (1.04)	$ 0.09	$ (5.48)	$ 1.45
Diluted (in dollars per share)	$ (1.04)	$ 0.09	$ (5.48)	$ 1.44
Weighted Average Common Shares Outstanding:
Basic (in shares)	571,872,413	539,221,101	551,162,559	539,315,170
Diluted (in shares)	571,872,413	540,038,187	551,162,559	540,442,649
Gas sales
Operating Revenues:
Total operating revenues	$ 199	$ 238	$ 611	$ 943
Oil sales
Operating Revenues:
Total operating revenues	40	67	111	153
NGL sales
Operating Revenues:
Total operating revenues	68	52	158	191
Marketing
Operating Revenues:
Total operating revenues	219	279	645	1,004
Other
Operating Revenues:
Total operating revenues	1	0	4	2
Marketing purchases
Operating Costs and Expenses:
Marketing purchases	$ 226	$ 288	$ 675	$ 1,022

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (593)	$ 49	$ (3,020)	$ 781
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost	[1]	1	1	1	5
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.

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Comprehensive Income [Abstract]
Defined benefit plan, tax	$ 1	$ 1	$ 2

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 95	$ 5
Accounts receivable, net	239	345
Derivative assets	238	278
Other current assets	41	51
Total current assets	613	679
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	500	520
Less: Accumulated depreciation, depletion and amortization	(23,247)	(20,503)
Total property and equipment, net	3,222	5,267
Operating lease assets	145	159
Deferred tax assets	0	407
Other long-term assets	177	205
Total long-term assets	322	771
TOTAL ASSETS	4,157	6,717
Current liabilities:
Accounts payable	416	525
Taxes payable	47	59
Interest payable	56	51
Derivative liabilities	287	125
Current operating lease liabilities	33	34
Other current liabilities	30	54
Total current liabilities	869	848
Long-term debt	2,450	2,242
Long-term operating lease liabilities	107	119
Long-term derivative liabilities	188	111
Pension and other postretirement liabilities	35	43
Other long-term liabilities	124	108
Total long-term liabilities	2,904	2,623
Commitments and contingencies (Note 12)
Equity:
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	4,882	4,726
Accumulated deficit	(4,271)	(1,251)
Accumulated other comprehensive loss	(32)	(33)
Common stock in treasury, 44,353,224 shares as of September 30, 2020 and December 31, 2019	(202)	(202)
Total equity	384	3,246
TOTAL LIABILITIES AND EQUITY	$ 4,157	$ 6,717

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$ 1,379	$ 1,506
Common stock, par value (in dollars per shares)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,250,000,000	1,250,000,000
Common stock, shares issued (in shares)	649,899,653	585,555,923
Treasury stock, shares (in shares)	44,353,224	44,353,224

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Cash Flows From Operating Activities:
Net income (loss)	$ (593)	$ 49	$ (3,020)	$ 781
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	70	125	267	352
Amortization of debt issuance costs			6	5
Impairments	361	2	2,495	8
Deferred income taxes	0	11	408	(400)
(Gain) loss on derivatives, unsettled			272	(108)
Stock-based compensation	0	2	2	6
Gain on early extinguishment of debt	0	(7)	(35)	(7)
Loss on sale of assets	0	0	0	3
Other			3	11
Change in assets and liabilities:
Accounts receivable			106	257
Accounts payable			(129)	(124)
Taxes payable			(12)	(3)
Interest payable			3	2
Inventories			3	(2)
Other assets and liabilities			38	(42)
Net cash provided by operating activities			407	739
Cash Flows From Investing Activities:
Capital investments			(700)	(877)
Proceeds from sale of property and equipment			2	42
Net cash used in investing activities			(698)	(835)
Cash Flows From Financing Activities:
Payments on long-term debt			(72)	(43)
Payments on revolving credit facility			(1,449)	0
Borrowings under revolving credit facility			1,415	0
Change in bank drafts outstanding			(9)	(11)
Proceeds from issuance of long-term debt			350	0
Debt issuance costs			(5)	0
Purchase of treasury stock			0	(21)
Proceeds from issuance of common stock, net			152	0
Cash paid for tax withholding			(1)	(1)
Net cash provided by (used in) financing activities			381	(76)
Increase (decrease) in cash and cash equivalents			90	(172)
Cash and cash equivalents at beginning of year			5	201
Cash and cash equivalents at end of period	$ 95	$ 29	$ 95	$ 29

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury
Balance (in shares) at Dec. 31, 2018		585,407,107				39,092,537
Balance beginning at Dec. 31, 2018	$ 2,362	$ 6	$ 4,715	$ (2,142)	$ (36)	$ (181)
Comprehensive (loss) income:
Net (loss) income	594			594
Comprehensive income (loss)	594
Stock-based compensation	$ 3		3
Issuance of restricted stock (in shares)		8,798
Cancellation of restricted stock (in shares)		(128,324)
Treasury stock (in shares)	5,260,687					5,260,687
Treasury stock	$ (21)					$ (21)
Performance units vested (in shares)		535,802
Tax withholding - stock compensation (in shares)		(274,657)
Tax withholding – stock compensation	(1)		(1)
Balance (in shares) at Mar. 31, 2019		585,548,726				44,353,224
Balance ending at Mar. 31, 2019	2,937	$ 6	4,717	(1,548)	(36)	$ (202)
Balance (in shares) at Dec. 31, 2018		585,407,107				39,092,537
Balance beginning at Dec. 31, 2018	2,362	$ 6	4,715	(2,142)	(36)	$ (181)
Comprehensive (loss) income:
Net (loss) income	781
Comprehensive income (loss)	786
Balance (in shares) at Sep. 30, 2019		585,637,420				44,353,224
Balance ending at Sep. 30, 2019	3,135	$ 6	4,723	(1,361)	(31)	$ (202)
Balance (in shares) at Dec. 31, 2018		585,407,107				39,092,537
Balance beginning at Dec. 31, 2018	2,362	$ 6	4,715	(2,142)	(36)	$ (181)
Balance (in shares) at Dec. 31, 2019		585,555,923				44,353,224
Balance ending at Dec. 31, 2019	3,246	$ 6	4,726	(1,251)	(33)	$ (202)
Balance (in shares) at Mar. 31, 2019		585,548,726				44,353,224
Balance beginning at Mar. 31, 2019	2,937	$ 6	4,717	(1,548)	(36)	$ (202)
Comprehensive (loss) income:
Net (loss) income	138			138
Other comprehensive income	4				4
Comprehensive income (loss)	142
Stock-based compensation	3		3
Issuance of restricted stock (in shares)		6,424
Cancellation of restricted stock (in shares)		(72,555)
Tax withholding - stock compensation (in shares)		(4,250)
Balance (in shares) at Jun. 30, 2019		585,478,345				44,353,224
Balance ending at Jun. 30, 2019	3,082	$ 6	4,720	(1,410)	(32)	$ (202)
Comprehensive (loss) income:
Net (loss) income	49			49
Other comprehensive income	1				1
Comprehensive income (loss)	50
Stock-based compensation	3		3
Issuance of restricted stock (in shares)		205,883
Cancellation of restricted stock (in shares)		(33,851)
Tax withholding - stock compensation (in shares)		(12,957)
Balance (in shares) at Sep. 30, 2019		585,637,420				44,353,224
Balance ending at Sep. 30, 2019	3,135	$ 6	4,723	(1,361)	(31)	$ (202)
Balance (in shares) at Dec. 31, 2019		585,555,923				44,353,224
Balance beginning at Dec. 31, 2019	3,246	$ 6	4,726	(1,251)	(33)	$ (202)
Comprehensive (loss) income:
Net (loss) income	(1,547)			(1,547)
Comprehensive income (loss)	(1,547)
Stock-based compensation	1		1
Issuance of restricted stock (in shares)		12,397
Cancellation of restricted stock (in shares)		(167,130)
Restricted units granted (in shares)		1,005,976
Restricted units granted	1		1
Tax withholding - stock compensation (in shares)		(383,731)
Balance (in shares) at Mar. 31, 2020		586,023,435				44,353,224
Balance ending at Mar. 31, 2020	1,701	$ 6	4,728	(2,798)	(33)	$ (202)
Balance (in shares) at Dec. 31, 2019		585,555,923				44,353,224
Balance beginning at Dec. 31, 2019	3,246	$ 6	4,726	(1,251)	(33)	$ (202)
Comprehensive (loss) income:
Net (loss) income	(3,020)
Other comprehensive income					1
Comprehensive income (loss)	(3,019)
Balance (in shares) at Sep. 30, 2020		649,899,653				44,353,224
Balance ending at Sep. 30, 2020	384	$ 7	4,882	(4,271)	(32)	$ (202)
Balance (in shares) at Mar. 31, 2020		586,023,435				44,353,224
Balance beginning at Mar. 31, 2020	1,701	$ 6	4,728	(2,798)	(33)	$ (202)
Comprehensive (loss) income:
Net (loss) income	(880)			(880)
Comprehensive income (loss)	(880)
Stock-based compensation	1		1
Issuance of restricted stock (in shares)		222,489
Cancellation of restricted stock (in shares)		(1,079,515)
Restricted units granted (in shares)		1,649,294
Restricted units granted	2		2
Tax withholding - stock compensation (in shares)		(222,163)
Tax withholding – stock compensation	(1)		(1)
Balance (in shares) at Jun. 30, 2020		586,593,540				44,353,224
Balance ending at Jun. 30, 2020	823	$ 6	4,730	(3,678)	(33)	$ (202)
Comprehensive (loss) income:
Net (loss) income	(593)			(593)
Other comprehensive income	1				1
Comprehensive income (loss)	(592)
Stock-based compensation	1		1
Issuance of common stock (in shares)		63,250,000
Issuance of common stock	152	$ 1	151
Issuance of restricted stock (in shares)		63,344
Cancellation of restricted stock (in shares)		(5,196)
Tax withholding - stock compensation (in shares)		(2,035)
Balance (in shares) at Sep. 30, 2020		649,899,653				44,353,224
Balance ending at Sep. 30, 2020	$ 384	$ 7	$ 4,882	$ (4,271)	$ (32)	$ (202)

XML

BASIS OF PRESENTATION

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

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

E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania 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 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.

XML

ACQUISITION

9 Months Ended

Sep. 30, 2020

Business Combinations [Abstract]

ACQUISITION

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

$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.

XML

RESTRUCTURING CHARGES

9 Months Ended

Sep. 30, 2020

Restructuring and Related Activities [Abstract]

RESTRUCTURING CHARGES

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 nine months ended September 30, 2020, and were substantially complete by the end of the first quarter of 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. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. 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. As of September 30, 2019, the Company 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 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 third quarter of 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 September 30, 2020 and 2019:

	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Severance (including payroll taxes)	$	—	$	1	$	12	$	4
Office consolidation	—		3		—		5
Total restructuring charges (1)	$	—	$	4	$	12	$	9

(1)Total restructuring charges were $12 million for the Company’s E&P segment for the nine months ended 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 September 30, 2020, which is reflected in accounts payable on the consolidated balance sheet:

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

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REVENUE RECOGNITION

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

REVENUE RECOGNITION

REVENUE RECOGNITION

Revenues from Contracts with Customers

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

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

Marketing.  The Company, through its marketing affiliate, markets natural gas, oil and NGLs for its affiliated E&P company as well as other joint interest owners that choose to market with the Company.  In addition, the Company markets some products purchased from third parties.  Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point.  The pricing provisions of the Company’s contracts are primarily tied to market indices with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions.  Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled.  Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer.  Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date.  As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.

Disaggregation of Revenues

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

(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended September 30, 2020
Gas sales	$	190	$	—	$	9	$	199
Oil sales	39		—		1		40
NGL sales	68		—		—		68
Marketing	—		495		(276)		219
Other	1		—		—		1
Total	$	298	$	495	$	(266)	$	527
Three months ended September 30, 2019
Gas sales	$	230	$	—	$	8	$	238
Oil sales	66		—		1		67
NGL sales	52		—		—		52
Marketing	—		592		(313)		279
Total	$	348	$	592	$	(304)	$	636

(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2020
Gas sales	$	584	$	—	$	27	$	611
Oil sales	107		—		4		111
NGL sales	158		—		—		158
Marketing	—		1,432		(787)		645
Other (1)	4		—		—		4
Total	$	853	$	1,432	$	(756)	$	1,529
Nine months ended September 30, 2019
Gas sales	$	918	$	—	$	25	$	943
Oil sales	151		—		2		153
NGL sales	191		—		—		191
Marketing	—		2,158		(1,154)		1,004
Other (2)	1		1		—		2
Total	$	1,261	$	2,159	$	(1,127)	$	2,293

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

(2)For the nine months ended 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 September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Northeast Appalachia	$	131	$	175	$	443	$	740
Southwest Appalachia	166		173		409		519
Other	1		—		1		2
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)	September 30, 2020		December 31, 2019
Receivables from contracts with customers	$	218	$	284
Other accounts receivable	21		61
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 September 30, 2020 and 2019.  The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.

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CASH AND CASH EQUIVALENTS

9 Months Ended

Sep. 30, 2020

Cash and Cash Equivalents [Abstract]

CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS

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

(in millions)	September 30, 2020		December 31, 2019
Cash	$	93	$	5
Marketable securities (1)	2		—
Total	$	95	$	5

(1)Consists of government stable value money market funds.

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NATURAL GAS AND OIL PROPERTIES

9 Months Ended

Sep. 30, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

NATURAL GAS AND OIL PROPERTIES

NATURAL GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties.  Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method.  These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure).  Any costs in excess of the ceiling are written off as a non-cash expense.  The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling.  Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. The Company had no hedge positions that were designated for hedge accounting as of September 30, 2020. Prices used to calculate the ceiling value of reserves were as follows:

	September 30, 2020		September 30, 2019
Natural gas (per MMBtu)	$	1.97	$	2.87
Oil (per Bbl)	$	43.40	$	57.77
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 $361 million at 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 the first three quarters of 2020, an additional non-cash impairment of the Company’s assets may occur in the 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 oil properties.

The Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount at September 30, 2019, and the Company had no derivative positions that were designated for hedge accounting as of 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.

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EARNINGS PER SHARE

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

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

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

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.

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

	For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2020		2019		2020		2019
Net income (loss)	$	(593)	$	49	$	(3,020)	$	781
Number of common shares:
Weighted average outstanding	571,872,413		539,221,101		551,162,559		539,315,170
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	—		187,706		—		400,120
Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	—		629,380		—		727,359
Weighted average and potential dilutive outstanding	571,872,413		540,038,187		551,162,559		540,442,649
Earnings per common share
Basic	$	(1.04)	$	0.09	$	(5.48)	$	1.45
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 September 30, 2020 and 2019, as they would have had an antidilutive effect:

	For the three months ended September 30,		For the nine months ended September 30,
	2020	2019	2020	2019
Unexercised stock options	4,425,886	5,102,882	4,519,385	5,115,334
Unvested share-based payment	939,941	2,136,453	946,547	1,797,963
Restricted stock units	1,935,781	—	2,001,621	—
Performance units	2,282,211	240,450	2,027,985	247,443
Total	9,583,819	7,479,785	9,495,538	7,160,740

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DERIVATIVES AND RISK MANAGEMENT

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES AND RISK MANAGEMENT

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 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. The Company’s interest rate 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.

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 were used to fix or float interest rates on existing or anticipated indebtedness.  The purpose of these instruments was 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 10 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.

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 September 30, 2020:

Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2020 (in millions)
Natural Gas
2020
Fixed price swaps	91	$	2.46	$	—	$	—	$	—	$	—	$	16	(1)
Two-way costless collars	57	—		—		2.45		2.75		—		(7)
Three-way costless collars	25	—		2.19		2.58		2.96		—		(11)		(2)
Total	173											$	(2)
2021
Fixed price swaps	93	$	2.67	$	—	$	—	$	—	$	—	$	(13)
Two-way costless collars	166	—		—		2.51		2.89		—		(27)
Three-way costless collars	291	—		2.16		2.49		2.84		—		(113)		(3)
Total	550											$	(153)
2022
Fixed price swaps	37	$	2.75	$	—	$	—	$	—	$	—	$	(2)
Two-way costless collars	32	—		—		2.17		2.88		—		(5)
Three-way costless collars	116	—		2.07		2.44		2.87		—		(24)
Total	185											$	(31)
2023
Three-way costless collars	25	$	—	$	2.07	$	2.48	$	3.18	$	—	$	(2)
Basis Swaps
2020	66	$	—	$	—	$	—	$	—	$	(0.37)	$	21
2021	155	—		—		—		—		(0.12)		21
2022	127	—		—		—		—		(0.38)		4
Total	348											$	46

(1)Includes $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 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.

	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at September 30, 2020 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2020
Fixed price swaps (1)	584	$	75.44	$	—	$	—	$	—	$	20
Two-way costless collars	261	—		—		56.76		59.75		4
Three-way costless collars	404	—		43.71		52.85		57.78		3
Total	1,249									$	27
2021
Fixed price swaps	2,574	$	52.84	$	—	$	—	$	—	$	27
Three-way costless collars	1,445	—		43.52		53.25		58.14		8
Total	4,019									$	35
2022
Fixed price swaps	762	$	48.85	$	—	$	—	$	—	$	4
Three-way costless collars	666	—		42.50		53.20		58.00		2
Total	1,428									$	6
2023
Three-way costless collars	111	$	—	$	30.00	$	40.00	$	57.85	$	—
Ethane
2020
Fixed price swaps	2,629	$	8.62	$	—	$	—	$	—	$	—
2021
Fixed price swaps	5,889	$	7.12	$	—	$	—	$	—	$	(12)
Two-way costless collar	584	—		—		7.14		10.40		—
Total	6,473									$	(12)
2022
Fixed price swaps	190	$	7.41	$	—	$	—	$	—	$	—
Two-way costless collar	135	—		—		7.56		9.66		—
Total	325									$	—
Propane
2020
Fixed price swaps	1,435	$	23.11	$	—	$	—	$	—	$	2
Two-way costless collars	92	—		—		25.20		29.40		—
Total	1,527									$	2
2021
Fixed price swaps	4,298	$	19.99	$	—	$	—	$	—	$	(3)
2022
Fixed price swaps	156	$	19.25	$	—	$	—	$	—	$	—
Normal Butane
2020
Fixed price swaps	195	$	22.44	$	—	$	—	$	—	$	—
Natural Gasoline
2020
Fixed price swaps	184	$	34.59	$	—	$	—	$	—	$	—

(1)Includes 448 MBbls of purchased fixed price oil swaps at $33.94 per barrel with a fair value of $3 million and 1,032 MBbls of sold fixed price oil swaps at $57.44 per barrel with a fair value of $17 million.

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)

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

	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	$	—	$	—
Purchased basis swaps	—	—		(0.63)		—
Fixed price swaps	—	2.09		—		—
Basis swaps	—	—		(0.70)		—
Total	1					$	—
2021
Purchased fixed price swaps	1	$	2.04	$	—	$	—
Fixed price swaps	2	2.49		—		(1)
Basis swaps	1	—		(0.38)		—
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)	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2020 (in millions)
2020	2	$	2.44	$	—
2021	6	2.44		3
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 September 30, 2020, the net fair value of the Company’s financial instruments related to commodities was a $125 million liability and included a net reduction of the liability of $1 million related to non-performance risk. See Note 10 for additional details regarding the Company’s fair value measurements of its derivative positions.

As of 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. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The Company was 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 had a notional amount of $170 million and expired in June 2020.  Changes in the fair value of the interest rate swaps were included in gain (loss) on derivatives on the consolidated statements of operations.

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 September 30, 2020 and December 31, 2019:

Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2020			December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative assets	$	3		$	—
Fixed price swaps – natural gas	Derivative assets	21		(1)	77		(1)
Fixed price swaps – oil	Derivative assets	42			4
Fixed price swaps – ethane	Derivative assets	2			11
Fixed price swaps – propane	Derivative assets	5			21
Two-way costless collars – natural gas	Derivative assets	27			10
Two-way costless collars – oil	Derivative assets	6			5
Two-way costless collars – propane	Derivative assets	—			2
Three-way costless collars – natural gas	Derivative assets	64		(2)	126
Three-way costless collars – oil	Derivative assets	19			3
Basis swaps – natural gas	Derivative assets	40			17
Call options – natural gas	Derivative assets	9			1
Fixed price swaps – natural gas storage	Derivative assets	—			1
Fixed price swaps – natural gas	Other long-term assets	1			7
Fixed price swaps – oil	Other long-term assets	10			1
Fixed price swaps – propane	Other long-term assets	1			3
Two-way costless collars – natural gas	Other long-term assets	13			4
Three-way costless collars – natural gas	Other long-term assets	56			74
Three-way costless collars – oil	Other long-term assets	14			7
Basis swaps – natural gas	Other long-term assets	13			15
Call options – natural gas	Other long-term assets	4			2
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. 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.

Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2020		December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative liabilities	$	—	$	1
Fixed price swaps – natural gas	Derivative liabilities	15		1
Fixed price swaps – oil	Derivative liabilities	1		6
Fixed price swaps – ethane	Derivative liabilities	10		—
Fixed price swaps – propane	Derivative liabilities	5		—
Two-way costless collars – natural gas	Derivative liabilities	52		4
Two-way costless collars – oil	Derivative liabilities	2		5
Three-way costless collars – natural gas	Derivative liabilities	164		84
Three-way costless collars – oil	Derivative liabilities	10		4
Basis swaps – natural gas	Derivative liabilities	3		17
Call options – natural gas	Derivative liabilities	24		3
Fixed price swaps – natural gas storage	Derivative liabilities	1		—
Fixed price swaps – natural gas	Long-term derivative liabilities	6		—
Fixed price swaps – oil	Long-term derivative liabilities	—		2
Fixed price swaps – ethane	Long-term derivative liabilities	4		—
Fixed price swaps – propane	Long-term derivative liabilities	2		—
Two-way costless collars – natural gas	Long-term derivative liabilities	27		4
Three-way costless collars – natural gas	Long-term derivative liabilities	106		72
Three-way costless collars – oil	Long-term derivative liabilities	10		8
Basis swap – natural gas	Long-term derivative liabilities	4		9
Call options – natural gas	Long-term derivative liabilities	29		15
Call options – oil	Long-term derivative liabilities	—		1
Total derivative liabilities		$	475	$	236

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 September 30, 2020 and 2019:

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
	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		2020			2019			2020			2019
		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	4		$	—		$	4		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(138)			(19)			(74)			36
Fixed price swaps – oil	Gain (Loss) on Derivatives	(20)			8			54			5
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(13)			1			(23)			8
Fixed price swaps – propane	Gain (Loss) on Derivatives	(17)			10			(25)			19
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(34)			(11)			(45)			(2)
Two-way costless collars – oil	Gain (Loss) on Derivatives	(5)			—			4			(3)
Two-way costless collars – propane	Gain (Loss) on Derivatives	(1)			1			(2)			3
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(98)		(1)	3			(194)		(1)	27
Three-way costless collars – oil	Gain (Loss) on Derivatives	(4)			3			15			4
Basis swaps – natural gas	Gain (Loss) on Derivatives	54			12			40			6
Call options – natural gas	Gain (Loss) on Derivatives	(16)			1			(25)			5
Call options – oil	Gain (Loss) on Derivatives	—			—			1			—
Purchased 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	Gain (Loss) on Derivatives	—			1			—			(1)
Total gain (loss) on unsettled derivatives		$	(289)		$	12		$	(272)		$	108
Settled Gain (Loss) on Derivatives Recognized in Earnings (2)
	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		2020			2019			2020			2019
		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(2)		$	—		$	(4)		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	61		(3)	45			150		(3)	53
Fixed price swaps – oil	Gain (Loss) on Derivatives	17			3			44			5
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(2)			6			6			12
Fixed price swaps – propane	Gain (Loss) on Derivatives	2			11			19			20
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(5)			10			1			12
Two-way costless collars – oil	Gain (Loss) on Derivatives	4			2			13			4
Two-way costless collars – propane	Gain (Loss) on Derivatives	—			1			2			1
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	—			15			43			19
Three-way costless collars – oil	Gain (Loss) on Derivatives	1			—			5			—
Basis swaps – natural gas	Gain (Loss) on Derivatives	20			(3)			29			(11)
Call options – natural gas	Gain (Loss) on Derivatives	—			(1)		(4)	—			(2)		(4)
Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	1			(1)			2			(1)
Total gain on settled derivatives		$	97		$	88		$	310		$	112
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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RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

9 Months Ended

Sep. 30, 2020

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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 nine months ended September 30, 2020:

(in millions)	Pension and Other Postretirement		Foreign Currency		Total
Beginning balance December 31, 2019	$	(19)	$	(14)	$	(33)
Other comprehensive income before reclassifications	—		—		—
Amounts reclassified from other comprehensive income (1)	1		—		1
Net current-period other comprehensive income	1		—		1
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	$	1
	Provision (Benefit) for Income Taxes	—
	Net Income (Loss)	$	1
Total reclassifications for the period	Net Income (Loss)	$	1

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

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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 September 30, 2020 and December 31, 2019 were as follows:

	September 30, 2020						December 31, 2019
(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	95		$	95		$	5		$	5
2018 revolving credit facility due April 2024	—			—			34			34
Senior notes (1)	2,471			2,429			2,228			2,085
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 4.10% Senior Notes

due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy.  The fair values of the Company’s remaining senior notes are considered the be a Level 1 measurement. The carrying values of the borrowings under the Company’s revolving credit facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates.  The Company considers the fair value of its revolving credit facility to be a Level 1 measurement on the fair value hierarchy.

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

	September 30, 2020
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	3	$	—	$	3
Fixed price swaps (1)	—		82		—		82
Two-way costless collars	—		46		—		46
Three-way costless collars (2)	—		153		—		153
Basis swaps	—		53		—		53
Call options	—		13		—		13
Liabilities
Fixed price swaps	—		(43)		—		(43)
Two-way costless collars	—		(81)		—		(81)
Three-way costless collars	—		(290)		—		(290)
Basis swaps	—		(7)		—		(7)
Call options	—		(53)		—		(53)
Fixed price swaps – storage	—		(1)		—		(1)
Total (3)	$	—	$	(125)	$	—	$	(125)

(1)Includes $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 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 $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 of $1 million related to estimated nonperformance risk.

	December 31, 2019
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Fixed price swaps (1)	$	—	$	124	$	—	$	124
Two-way costless collars	—		21		—		21
Three-way costless collars	—		210		—		210
Basis swaps	—		32		—		32
Call options	—		3		—		3
Fixed price swaps - storage	—		1		—		1
Liabilities
Purchased fixed price swaps	—		(1)		—		(1)
Fixed price swaps	—		(9)		—		(9)
Two-way costless collars	—		(13)		—		(13)
Three-way costless collars	—		(168)		—		(168)
Basis swaps	—		(26)		—		(26)
Call options	—		(19)		—		(19)
Total	$	—	$	155	$	—	$	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 third quarters of 2020 and 2019.

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DEBT

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

DEBT

DEBT

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

	September 30, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (1.60% at September 30, 2020) 2018 revolving credit facility due April 2024	$	—	$	—	(1)	$	—	$	—
4.10% Senior Notes due March 2022	207		—			—		207
4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(6)			—		612
7.75% Senior Notes due October 2027	440		(5)			—		435
8.375% Senior Notes due September 2028 (3)	350		(5)			—		345
Total long-term debt	$	2,471	$	(20)		$	(1)	$	2,450
	December 31, 2019
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	$	34	$	—	(1)	$	—	$	34
4.10% Senior Notes due March 2022	213		(1)			—		212
4.95% Senior Notes due January 2025 (2)	892		(5)			(1)		886
7.50% Senior Notes due April 2026	639		(7)			—		632
7.75% Senior Notes due October 2027	484		(6)			—		478
Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242

(1)At 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.

(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate 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, in October 2020, the banks participating in the 2018 credit facility reaffirmed the elected borrowing base and aggregate commitments to be $1.8 billion. The borrowing base is subject to redetermination at least twice a year, in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets.

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

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, 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 September 30, 2020, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility.

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

As of September 30, 2020, the Company had $203 million in letters of credit and no borrowings outstanding under the 2018 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

The Company’s 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”).

Senior Notes

In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes”).  The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P.  Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment.  Effective in July 2018, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the 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 half of 2020, the Company repurchased $6 million of its 4.10% Senior Notes due 2022, $36 million of its 4.95% Senior Notes due 2025, $21 million of its 7.50% Senior Notes due 2026 and $44 million of its 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

In August 2020, the Company completed a public offering of $350 million aggregate principal amount of its 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.

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

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

	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Infrastructure currently in service	$	6,704	$	582	$	1,308	$	1,078	$	1,411	$	2,325
Pending regulatory approval and/or construction (1)	405		3		9		23		52		318
Total transportation charges	$	7,109	$	585	$	1,317	$	1,101	$	1,463	$	2,643

(1)Based on estimated in-service dates as of 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 September 30, 2020, approximately $27 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $13 million through December 2020 depending on the buyer’s actual use, and has recorded a $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 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 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.

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 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, 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. No material liabilities have been recognized in connection with these indemnifications.

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INCOME TAXES

9 Months Ended

Sep. 30, 2020

Income Tax Expense (Benefit), Continuing Operations [Abstract]

INCOME TAXES

INCOME TAXESThe Company’s effective tax rate was approximately 0% and (16)% for the three and nine months ended September 30, 2020, respectively. The change in the effective tax rate for the nine months ended 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.

Due to significant pricing declines and the material write-down of the carrying value of the Company’s natural gas and oil properties in addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in its valuation allowance 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 18% and (105)% for the three and nine months ended September 30, 2019, respectively. The effective tax rate for the nine months ended 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 $400 million was released on a discrete basis in the first nine months of 2019.

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PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

9 Months Ended

Sep. 30, 2020

Retirement Benefits [Abstract]

PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

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 September 30, 2020 and 2019:

	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)		2020		2019		2020		2019
Service cost	General and administrative expenses	$	2	$	1	$	6	$	5
Interest cost	Other Income (Loss), Net	1		2		3		4
Expected return on plan assets	Other Income (Loss), Net	(2)		(1)		(5)		(4)
Amortization of prior service cost	Other Income (Loss), Net	—		—		—		—
Amortization of net loss	Other Income (Loss), Net	1		—		1		1
Settlement loss	Other Income (Loss), Net	—		1		—		5
Net periodic benefit cost		$	2	$	3	$	5	$	11

The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million for the three months ended 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 September 30, 2020, the Company has contributed $12 million to the pension and other postretirement benefit plans and does not expect to contribute to its pension plan during the remainder of 2020.  The Company recognized liabilities of $22 million and $14 million related to its pension and other postretirement benefits, respectively, as of 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 September 30, 2020 and December 31, 2019, respectively.

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LONG-TERM INCENTIVE COMPENSATION

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

LONG-TERM INCENTIVE COMPENSATION

LONG-TERM INCENTIVE COMPENSATIONThe 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.

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 September 30, 2020 and 2019:

	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 September 30, 2020 and 2019:

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

As of September 30, 2020, there was $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 0.5 years.

Equity-Classified Stock Options

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

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

Equity-Classified Restricted Stock

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

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

Equity-Classified Performance Units

The following table summarizes equity-classified performance unit activity for the nine months ended September 30, 2020 and provides information for unvested units as of 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
	(in thousands)
Unvested units at December 31, 2019	178	$	10.47
Granted	—	$	—
Vested	(178)	$	10.47
Forfeited	—	$	—
Unvested units at September 30, 2020	—	$	—

(1)The actual payout of shares may range from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR.  The performance units have a 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 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 September 30, 2020:

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

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 September 30, 2020, there was $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 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
	(in thousands)
Unvested units at December 31, 2019	12,992	$	2.42
Granted	6,172	$	1.41
Vested	(3,946)	$	1.42
Forfeited	(3,060)	$	1.53
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 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 September 30, 2020, there was $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 2.2 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
	(in thousands)
Unvested units at December 31, 2019	5,142	$	2.42
Granted	6,172	$	1.41
Vested	—	$	—
Forfeited	(2,300)	$	3.06
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 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 September 30, 2020, there was $16 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.4 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.

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

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SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

SEGMENT INFORMATION

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 (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
	(in millions)
Three months ended September 30, 2020
Revenues from external customers	$	308		$	219	$	—		$	527
Intersegment revenues	(10)			276		—			266
Depreciation, depletion and amortization expense	68			2		—			70
Impairments	361			—		—			361
Operating loss	(379)		(1)	(2)		—			(381)
Interest expense (2)	22			—		—			22
Loss on derivatives	(192)			—		—			(192)
Other income, net	2			—		—			2
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	223			—		—			223
Three months ended September 30, 2019
Revenues from external customers	$	357		$	279	$	—		$	636
Intersegment revenues	(9)			313		—			304
Depreciation, depletion and amortization expense	123			2		—			125
Impairments	—			2		—			2
Operating loss	(21)		(1)	(8)		—			(29)
Interest expense (2)	17			—		—			17
Gain on derivatives	100			—		—			100
Gain on early extinguishment of debt	—			—		7			7
Other income (loss), net	(4)			—		2			(2)
Provision for income taxes (2)	10			—		—			10
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	239			—		1			240

	E&P			Marketing		Other			Total
Nine months ended September 30, 2020	(in millions)
Revenues from external customers	$	884		$	645	$	—		$	1,529
Intersegment revenues	(31)			787		—			756
Depreciation, depletion and amortization expense	260			7		—			267
Impairments	2,495			—		—			2,495
Operating loss	(2,613)		(1)	(14)		—			(2,627)
Interest expense (2)	63			—		—			63
Gain on derivatives	38			—		—			38
Gain on early extinguishment of debt	—			—		35			35
Other income, net	2			—		1			3
Provision for income taxes (2)	406			—		—			406
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	705			—		—			705
Nine months ended September 30, 2019
Revenues from external customers	$	1,288		$	1,005	$	—		$	2,293
Intersegment revenues	(27)			1,154		—			1,127
Depreciation, depletion and amortization expense	345			7		—			352
Impairments	6			2		—			8
Operating income (loss)	219		(1)	(13)		—			206
Interest expense (2)	46			—		—			46
Gain on derivatives	220			—		—			220
Gain on early extinguishment of debt	—			—		7			7
Other income (loss), net	(8)			—		1			(7)
Benefit from income taxes (2)	(401)			—		—			(401)
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	931			—		2			933

(1)Operating income (loss) for the E&P segment includes $4 million of restructuring charges for the three months ended 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. E&P assets also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At September 30, 2020 and 2019, other assets included approximately $95 million and $29 million, respectively, in cash and cash equivalents, $74 million and $84 million in right-of-use lease assets, respectively, $18 million and $31 million, respectively, in property, plant and equipment, $10 million and $9 million, respectively, in unamortized debt expense, $5 million and $7 million, respectively, in a non-qualified retirement plan and $3 million and $7 million in 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 decreases of $7 million and $53 million for the three months ended 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.

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NEW ACCOUNTING PRONOUNCEMENTS

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

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

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 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.

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New Accounting Pronouncements (Policies)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

New Accounting Standards Implemented/New Accounting Standards Not Yet Implemented

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

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 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.

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Restructuring Charges (Tables)

9 Months Ended

Sep. 30, 2020

Restructuring and Related Activities [Abstract]

Summary of Restructuring Charges

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

	For the three months ended September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Severance (including payroll taxes)	$	—	$	1	$	12	$	4
Office consolidation	—		3		—		5
Total restructuring charges (1)	$	—	$	4	$	12	$	9

(1)Total restructuring charges were $12 million for the Company’s E&P segment for the nine months ended 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 September 30, 2020, which is reflected in accounts payable on the consolidated balance sheet:

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

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Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue by Segment

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 September 30, 2020
Gas sales	$	190	$	—	$	9	$	199
Oil sales	39		—		1		40
NGL sales	68		—		—		68
Marketing	—		495		(276)		219
Other	1		—		—		1
Total	$	298	$	495	$	(266)	$	527
Three months ended September 30, 2019
Gas sales	$	230	$	—	$	8	$	238
Oil sales	66		—		1		67
NGL sales	52		—		—		52
Marketing	—		592		(313)		279
Total	$	348	$	592	$	(304)	$	636

(in millions)	E&P		Marketing		Intersegment Revenues		Total
Nine months ended September 30, 2020
Gas sales	$	584	$	—	$	27	$	611
Oil sales	107		—		4		111
NGL sales	158		—		—		158
Marketing	—		1,432		(787)		645
Other (1)	4		—		—		4
Total	$	853	$	1,432	$	(756)	$	1,529
Nine months ended September 30, 2019
Gas sales	$	918	$	—	$	25	$	943
Oil sales	151		—		2		153
NGL sales	191		—		—		191
Marketing	—		2,158		(1,154)		1,004
Other (2)	1		1		—		2
Total	$	1,261	$	2,159	$	(1,127)	$	2,293

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

(2)For the nine months ended 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.

Disaggregation of Revenue on Geographic Basis

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 September 30,				For the nine months ended September 30,
(in millions)	2020		2019		2020		2019
Northeast Appalachia	$	131	$	175	$	443	$	740
Southwest Appalachia	166		173		409		519
Other	1		—		1		2
Total	$	298	$	348	$	853	$	1,261

Reconciliation of Accounts Receivable

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)	September 30, 2020		December 31, 2019
Receivables from contracts with customers	$	218	$	284
Other accounts receivable	21		61
Total accounts receivable	$	239	$	345

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Cash and Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2020

Cash and Cash Equivalents [Abstract]

Summary of Cash and Cash Equivalents

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

(in millions)	September 30, 2020		December 31, 2019
Cash	$	93	$	5
Marketable securities (1)	2		—
Total	$	95	$	5

(1)Consists of government stable value money market funds.

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Natural Gas and Oil Properties (Tables)

9 Months Ended

Sep. 30, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures

Prices used to calculate the ceiling value of reserves were as follows:

	September 30, 2020		September 30, 2019
Natural gas (per MMBtu)	$	1.97	$	2.87
Oil (per Bbl)	$	43.40	$	57.77
NGLs (per Bbl)	$	9.26	$	12.59

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

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

	For the three months ended September 30,				For the nine months ended September 30,
(in millions, except share/per share amounts)	2020		2019		2020		2019
Net income (loss)	$	(593)	$	49	$	(3,020)	$	781
Number of common shares:
Weighted average outstanding	571,872,413		539,221,101		551,162,559		539,315,170
Issued upon assumed exercise of outstanding stock options	—		—		—		—
Effect of issuance of non-vested restricted common stock	—		187,706		—		400,120
Effect of issuance of non-vested restricted units	—		—		—		—
Effect of issuance of non-vested performance units	—		629,380		—		727,359
Weighted average and potential dilutive outstanding	571,872,413		540,038,187		551,162,559		540,442,649
Earnings per common share
Basic	$	(1.04)	$	0.09	$	(5.48)	$	1.45
Diluted	$	(1.04)	$	0.09	$	(5.48)	$	1.44

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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 September 30, 2020 and 2019, as they would have had an antidilutive effect:

	For the three months ended September 30,		For the nine months ended September 30,
	2020	2019	2020	2019
Unexercised stock options	4,425,886	5,102,882	4,519,385	5,115,334
Unvested share-based payment	939,941	2,136,453	946,547	1,797,963
Restricted stock units	1,935,781	—	2,001,621	—
Performance units	2,282,211	240,450	2,027,985	247,443
Total	9,583,819	7,479,785	9,495,538	7,160,740

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Derivatives and Risk Management (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value

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 September 30, 2020:

Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at September 30, 2020 (in millions)
Natural Gas
2020
Fixed price swaps	91	$	2.46	$	—	$	—	$	—	$	—	$	16	(1)
Two-way costless collars	57	—		—		2.45		2.75		—		(7)
Three-way costless collars	25	—		2.19		2.58		2.96		—		(11)		(2)
Total	173											$	(2)
2021
Fixed price swaps	93	$	2.67	$	—	$	—	$	—	$	—	$	(13)
Two-way costless collars	166	—		—		2.51		2.89		—		(27)
Three-way costless collars	291	—		2.16		2.49		2.84		—		(113)		(3)
Total	550											$	(153)
2022
Fixed price swaps	37	$	2.75	$	—	$	—	$	—	$	—	$	(2)
Two-way costless collars	32	—		—		2.17		2.88		—		(5)
Three-way costless collars	116	—		2.07		2.44		2.87		—		(24)
Total	185											$	(31)
2023
Three-way costless collars	25	$	—	$	2.07	$	2.48	$	3.18	$	—	$	(2)
Basis Swaps
2020	66	$	—	$	—	$	—	$	—	$	(0.37)	$	21
2021	155	—		—		—		—		(0.12)		21
2022	127	—		—		—		—		(0.38)		4
Total	348											$	46

(1)Includes $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 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.

	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at September 30, 2020 (in millions)
		Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2020
Fixed price swaps (1)	584	$	75.44	$	—	$	—	$	—	$	20
Two-way costless collars	261	—		—		56.76		59.75		4
Three-way costless collars	404	—		43.71		52.85		57.78		3
Total	1,249									$	27
2021
Fixed price swaps	2,574	$	52.84	$	—	$	—	$	—	$	27
Three-way costless collars	1,445	—		43.52		53.25		58.14		8
Total	4,019									$	35
2022
Fixed price swaps	762	$	48.85	$	—	$	—	$	—	$	4
Three-way costless collars	666	—		42.50		53.20		58.00		2
Total	1,428									$	6
2023
Three-way costless collars	111	$	—	$	30.00	$	40.00	$	57.85	$	—
Ethane
2020
Fixed price swaps	2,629	$	8.62	$	—	$	—	$	—	$	—
2021
Fixed price swaps	5,889	$	7.12	$	—	$	—	$	—	$	(12)
Two-way costless collar	584	—		—		7.14		10.40		—
Total	6,473									$	(12)
2022
Fixed price swaps	190	$	7.41	$	—	$	—	$	—	$	—
Two-way costless collar	135	—		—		7.56		9.66		—
Total	325									$	—
Propane
2020
Fixed price swaps	1,435	$	23.11	$	—	$	—	$	—	$	2
Two-way costless collars	92	—		—		25.20		29.40		—
Total	1,527									$	2
2021
Fixed price swaps	4,298	$	19.99	$	—	$	—	$	—	$	(3)
2022
Fixed price swaps	156	$	19.25	$	—	$	—	$	—	$	—
Normal Butane
2020
Fixed price swaps	195	$	22.44	$	—	$	—	$	—	$	—
Natural Gasoline
2020
Fixed price swaps	184	$	34.59	$	—	$	—	$	—	$	—

(1)Includes 448 MBbls of purchased fixed price oil swaps at $33.94 per barrel with a fair value of $3 million and 1,032 MBbls of sold fixed price oil swaps at $57.44 per barrel with a fair value of $17 million.

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)

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

	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	$	—	$	—
Purchased basis swaps	—	—		(0.63)		—
Fixed price swaps	—	2.09		—		—
Basis swaps	—	—		(0.70)		—
Total	1					$	—
2021
Purchased fixed price swaps	1	$	2.04	$	—	$	—
Fixed price swaps	2	2.49		—		(1)
Basis swaps	1	—		(0.38)		—
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)	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at September 30, 2020 (in millions)
2020	2	$	2.44	$	—
2021	6	2.44		3
Total	8			$	3

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

Balance Sheet Classification of Derivative Financial Instruments

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 September 30, 2020 and December 31, 2019:

Derivative Assets
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2020			December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative assets	$	3		$	—
Fixed price swaps – natural gas	Derivative assets	21		(1)	77		(1)
Fixed price swaps – oil	Derivative assets	42			4
Fixed price swaps – ethane	Derivative assets	2			11
Fixed price swaps – propane	Derivative assets	5			21
Two-way costless collars – natural gas	Derivative assets	27			10
Two-way costless collars – oil	Derivative assets	6			5
Two-way costless collars – propane	Derivative assets	—			2
Three-way costless collars – natural gas	Derivative assets	64		(2)	126
Three-way costless collars – oil	Derivative assets	19			3
Basis swaps – natural gas	Derivative assets	40			17
Call options – natural gas	Derivative assets	9			1
Fixed price swaps – natural gas storage	Derivative assets	—			1
Fixed price swaps – natural gas	Other long-term assets	1			7
Fixed price swaps – oil	Other long-term assets	10			1
Fixed price swaps – propane	Other long-term assets	1			3
Two-way costless collars – natural gas	Other long-term assets	13			4
Three-way costless collars – natural gas	Other long-term assets	56			74
Three-way costless collars – oil	Other long-term assets	14			7
Basis swaps – natural gas	Other long-term assets	13			15
Call options – natural gas	Other long-term assets	4			2
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. 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.

Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	September 30, 2020		December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative liabilities	$	—	$	1
Fixed price swaps – natural gas	Derivative liabilities	15		1
Fixed price swaps – oil	Derivative liabilities	1		6
Fixed price swaps – ethane	Derivative liabilities	10		—
Fixed price swaps – propane	Derivative liabilities	5		—
Two-way costless collars – natural gas	Derivative liabilities	52		4
Two-way costless collars – oil	Derivative liabilities	2		5
Three-way costless collars – natural gas	Derivative liabilities	164		84
Three-way costless collars – oil	Derivative liabilities	10		4
Basis swaps – natural gas	Derivative liabilities	3		17
Call options – natural gas	Derivative liabilities	24		3
Fixed price swaps – natural gas storage	Derivative liabilities	1		—
Fixed price swaps – natural gas	Long-term derivative liabilities	6		—
Fixed price swaps – oil	Long-term derivative liabilities	—		2
Fixed price swaps – ethane	Long-term derivative liabilities	4		—
Fixed price swaps – propane	Long-term derivative liabilities	2		—
Two-way costless collars – natural gas	Long-term derivative liabilities	27		4
Three-way costless collars – natural gas	Long-term derivative liabilities	106		72
Three-way costless collars – oil	Long-term derivative liabilities	10		8
Basis swap – natural gas	Long-term derivative liabilities	4		9
Call options – natural gas	Long-term derivative liabilities	29		15
Call options – oil	Long-term derivative liabilities	—		1
Total derivative liabilities		$	475	$	236

Summary of Before Tax Effect of Fair Value Hedges not Designated for Hedge Accounting

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 September 30, 2020 and 2019:

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
	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		2020			2019			2020			2019
		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	4		$	—		$	4		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	(138)			(19)			(74)			36
Fixed price swaps – oil	Gain (Loss) on Derivatives	(20)			8			54			5
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(13)			1			(23)			8
Fixed price swaps – propane	Gain (Loss) on Derivatives	(17)			10			(25)			19
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(34)			(11)			(45)			(2)
Two-way costless collars – oil	Gain (Loss) on Derivatives	(5)			—			4			(3)
Two-way costless collars – propane	Gain (Loss) on Derivatives	(1)			1			(2)			3
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(98)		(1)	3			(194)		(1)	27
Three-way costless collars – oil	Gain (Loss) on Derivatives	(4)			3			15			4
Basis swaps – natural gas	Gain (Loss) on Derivatives	54			12			40			6
Call options – natural gas	Gain (Loss) on Derivatives	(16)			1			(25)			5
Call options – oil	Gain (Loss) on Derivatives	—			—			1			—
Purchased 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	Gain (Loss) on Derivatives	—			1			—			(1)
Total gain (loss) on unsettled derivatives		$	(289)		$	12		$	(272)		$	108
Settled Gain (Loss) on Derivatives Recognized in Earnings (2)
	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		2020			2019			2020			2019
		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(2)		$	—		$	(4)		$	—
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	61		(3)	45			150		(3)	53
Fixed price swaps – oil	Gain (Loss) on Derivatives	17			3			44			5
Fixed price swaps – ethane	Gain (Loss) on Derivatives	(2)			6			6			12
Fixed price swaps – propane	Gain (Loss) on Derivatives	2			11			19			20
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(5)			10			1			12
Two-way costless collars – oil	Gain (Loss) on Derivatives	4			2			13			4
Two-way costless collars – propane	Gain (Loss) on Derivatives	—			1			2			1
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	—			15			43			19
Three-way costless collars – oil	Gain (Loss) on Derivatives	1			—			5			—
Basis swaps – natural gas	Gain (Loss) on Derivatives	20			(3)			29			(11)
Call options – natural gas	Gain (Loss) on Derivatives	—			(1)		(4)	—			(2)		(4)
Fixed price swaps – natural gas storage	Gain (Loss) on Derivatives	1			(1)			2			(1)
Total gain on settled derivatives		$	97		$	88		$	310		$	112
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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Reclassifications from Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2020

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Components of Accumulated Other Comprehensive Income (Loss)

The following tables detail the components of accumulated other comprehensive income and the related tax effects for the nine months ended September 30, 2020:

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

Reclassification out of Accumulated Other Comprehensive Income

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	$	1
	Provision (Benefit) for Income Taxes	—
	Net Income (Loss)	$	1
Total reclassifications for the period	Net Income (Loss)	$	1

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

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Carrying Amount and Estimated Fair Values of Financial Instruments

The carrying amounts and estimated fair values of the Company’s financial instruments as of September 30, 2020 and December 31, 2019 were as follows:

	September 30, 2020						December 31, 2019
(in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	95		$	95		$	5		$	5
2018 revolving credit facility due April 2024	—			—			34			34
Senior notes (1)	2,471			2,429			2,228			2,085
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.

Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis

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

	September 30, 2020
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	3	$	—	$	3
Fixed price swaps (1)	—		82		—		82
Two-way costless collars	—		46		—		46
Three-way costless collars (2)	—		153		—		153
Basis swaps	—		53		—		53
Call options	—		13		—		13
Liabilities
Fixed price swaps	—		(43)		—		(43)
Two-way costless collars	—		(81)		—		(81)
Three-way costless collars	—		(290)		—		(290)
Basis swaps	—		(7)		—		(7)
Call options	—		(53)		—		(53)
Fixed price swaps – storage	—		(1)		—		(1)
Total (3)	$	—	$	(125)	$	—	$	(125)

(1)Includes $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 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 $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 of $1 million related to estimated nonperformance risk.

	December 31, 2019
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Fixed price swaps (1)	$	—	$	124	$	—	$	124
Two-way costless collars	—		21		—		21
Three-way costless collars	—		210		—		210
Basis swaps	—		32		—		32
Call options	—		3		—		3
Fixed price swaps - storage	—		1		—		1
Liabilities
Purchased fixed price swaps	—		(1)		—		(1)
Fixed price swaps	—		(9)		—		(9)
Two-way costless collars	—		(13)		—		(13)
Three-way costless collars	—		(168)		—		(168)
Basis swaps	—		(26)		—		(26)
Call options	—		(19)		—		(19)
Total	$	—	$	155	$	—	$	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.

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Debt (Tables)

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Components of Debt

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

	September 30, 2020
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (1.60% at September 30, 2020) 2018 revolving credit facility due April 2024	$	—	$	—	(1)	$	—	$	—
4.10% Senior Notes due March 2022	207		—			—		207
4.95% Senior Notes due January 2025 (2)	856		(4)			(1)		851
7.50% Senior Notes due April 2026	618		(6)			—		612
7.75% Senior Notes due October 2027	440		(5)			—		435
8.375% Senior Notes due September 2028 (3)	350		(5)			—		345
Total long-term debt	$	2,471	$	(20)		$	(1)	$	2,450
	December 31, 2019
(in millions)	Debt Instrument		Unamortized Issuance Expense			Unamortized Debt Discount		Total
Long-term debt:
Variable rate (4.310% at December 31, 2019) 2018 term loan facility due April 2024	$	34	$	—	(1)	$	—	$	34
4.10% Senior Notes due March 2022	213		(1)			—		212
4.95% Senior Notes due January 2025 (2)	892		(5)			(1)		886
7.50% Senior Notes due April 2026	639		(7)			—		632
7.75% Senior Notes due October 2027	484		(6)			—		478
Total long-term debt	$	2,262	$	(19)		$	(1)	$	2,242

(1)At 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.

(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate 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.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Obligation under Transportation Agreements

As of September 30, 2020, future payments under non-cancelable firm transportation and gathering agreements were as follows:

	Payments Due by Period
(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Infrastructure currently in service	$	6,704	$	582	$	1,308	$	1,078	$	1,411	$	2,325
Pending regulatory approval and/or construction (1)	405		3		9		23		52		318
Total transportation charges	$	7,109	$	585	$	1,317	$	1,101	$	1,463	$	2,643

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

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Pension Plan and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2020

Retirement Benefits [Abstract]

Pension and Other Postretirement Benefit Costs

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 September 30, 2020 and 2019:

	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)		2020		2019		2020		2019
Service cost	General and administrative expenses	$	2	$	1	$	6	$	5
Interest cost	Other Income (Loss), Net	1		2		3		4
Expected return on plan assets	Other Income (Loss), Net	(2)		(1)		(5)		(4)
Amortization of prior service cost	Other Income (Loss), Net	—		—		—		—
Amortization of net loss	Other Income (Loss), Net	1		—		1		1
Settlement loss	Other Income (Loss), Net	—		1		—		5
Net periodic benefit cost		$	2	$	3	$	5	$	11

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Long-term Incentive Compensation (Tables)

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

Schedule of Stock-Based Compensation Costs

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

	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

Schedule of Equity-Classified Stock-Based Compensation Costs

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

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

Summary of Equity-Classified Stock Option Activity

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

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

Summary of Equity-Classified Restricted Stock Activity

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

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

Summary of Equity-Classified Performance Units Activity

The following table summarizes equity-classified performance unit activity for the nine months ended September 30, 2020 and provides information for unvested units as of 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
	(in thousands)
Unvested units at December 31, 2019	178	$	10.47
Granted	—	$	—
Vested	(178)	$	10.47
Forfeited	—	$	—
Unvested units at September 30, 2020	—	$	—

(1)The actual payout of shares may range from a minimum of zero shares to a maximum of two shares per unit contingent upon TSR.  The performance units have a 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 vesting period.

Schedule of Liability-Classified Stock-Based Compensation Costs

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

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

Summary of Liability-Classified Restricted Stock Unit Activity

As of September 30, 2020, there was $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 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
	(in thousands)
Unvested units at December 31, 2019	12,992	$	2.42
Granted	6,172	$	1.41
Vested	(3,946)	$	1.42
Forfeited	(3,060)	$	1.53
Unvested units at September 30, 2020	12,158	$	2.17

Summary of Liability-Classified Performance Unit Activity

	Number of Units	Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2019	5,142	$	2.42
Granted	6,172	$	1.41
Vested	—	$	—
Forfeited	(2,300)	$	3.06
Unvested units at September 30, 2020	9,014	$	2.10

Summary of Liability-Classified Performance Unit Activity

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

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Summary of Financial Information for Company's Reportable Segments

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 (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
	(in millions)
Three months ended September 30, 2020
Revenues from external customers	$	308		$	219	$	—		$	527
Intersegment revenues	(10)			276		—			266
Depreciation, depletion and amortization expense	68			2		—			70
Impairments	361			—		—			361
Operating loss	(379)		(1)	(2)		—			(381)
Interest expense (2)	22			—		—			22
Loss on derivatives	(192)			—		—			(192)
Other income, net	2			—		—			2
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	223			—		—			223
Three months ended September 30, 2019
Revenues from external customers	$	357		$	279	$	—		$	636
Intersegment revenues	(9)			313		—			304
Depreciation, depletion and amortization expense	123			2		—			125
Impairments	—			2		—			2
Operating loss	(21)		(1)	(8)		—			(29)
Interest expense (2)	17			—		—			17
Gain on derivatives	100			—		—			100
Gain on early extinguishment of debt	—			—		7			7
Other income (loss), net	(4)			—		2			(2)
Provision for income taxes (2)	10			—		—			10
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	239			—		1			240

	E&P			Marketing		Other			Total
Nine months ended September 30, 2020	(in millions)
Revenues from external customers	$	884		$	645	$	—		$	1,529
Intersegment revenues	(31)			787		—			756
Depreciation, depletion and amortization expense	260			7		—			267
Impairments	2,495			—		—			2,495
Operating loss	(2,613)		(1)	(14)		—			(2,627)
Interest expense (2)	63			—		—			63
Gain on derivatives	38			—		—			38
Gain on early extinguishment of debt	—			—		35			35
Other income, net	2			—		1			3
Provision for income taxes (2)	406			—		—			406
Assets	3,705		(3)	240		212		(4)	4,157
Capital investments (5)	705			—		—			705
Nine months ended September 30, 2019
Revenues from external customers	$	1,288		$	1,005	$	—		$	2,293
Intersegment revenues	(27)			1,154		—			1,127
Depreciation, depletion and amortization expense	345			7		—			352
Impairments	6			2		—			8
Operating income (loss)	219		(1)	(13)		—			206
Interest expense (2)	46			—		—			46
Gain on derivatives	220			—		—			220
Gain on early extinguishment of debt	—			—		7			7
Other income (loss), net	(8)			—		1			(7)
Benefit from income taxes (2)	(401)			—		—			(401)
Assets	6,099		(3)	272		227		(4)	6,598
Capital investments (5)	931			—		2			933

(1)Operating income (loss) for the E&P segment includes $4 million of restructuring charges for the three months ended 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. E&P assets also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At September 30, 2020 and 2019, other assets included approximately $95 million and $29 million, respectively, in cash and cash equivalents, $74 million and $84 million in right-of-use lease assets, respectively, $18 million and $31 million, respectively, in property, plant and equipment, $10 million and $9 million, respectively, in unamortized debt expense, $5 million and $7 million, respectively, in a non-qualified retirement plan and $3 million and $7 million in 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 decreases of $7 million and $53 million for the three months ended 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.

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Basis of Presentation (Narrative) (Details)	9 Months Ended
	Sep. 30, 2020 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of segments	2

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Acquisition (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
	Aug. 12, 2020	Aug. 31, 2020	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Business Acquisition [Line Items]
Transaction related expneses			$ 3	$ 0	$ 3	$ 0
8.375% Senior Notes due September 2028 (3) | Senior Notes
Business Acquisition [Line Items]
Senior notes		$ 350
Stated interest rate			8.375%		8.375%
Proceeds from issuance of long-term debt		$ 345
Montage Resources Corporation | Eight Point Eight Seven Five Percent Senior Notes Due 2023 | Senior Notes
Business Acquisition [Line Items]
Senior notes			$ 510		$ 510
Stated interest rate			8.875%		8.875%
Montage Resources Corporation
Business Acquisition [Line Items]
Number of Southwestern Energy common stock for each share of Montage Resources Corporation common stock converted (in shares)	1.8656
Percentage of voting interest			90.00%		90.00%
Offering price (in dollars per share)		$ 2.50
Transaction related expneses			$ 3		$ 3
Montage Resources Corporation | Public Stock Offering
Business Acquisition [Line Items]
Underwritten public offering of common stock (in shares)		63,250,000
Net proceeds from public offering		$ 152
Montage Resources Corporation | 8.375% Senior Notes due September 2028 (3) | Senior Notes
Business Acquisition [Line Items]
Senior notes		$ 350
Stated interest rate		8.375%
Proceeds from issuance of long-term debt		$ 345
Montage Resources Corporation | Montage Resources Corporation
Business Acquisition [Line Items]
Percentage of voting interest			10.00%		10.00%

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Restructuring Charges (Additional Information) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jul. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Restructuring Cost and Reserve [Line Items]
Term of contract	10 years
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Office consolidation	$ 3	$ 0	$ 3	$ 0	$ 5

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Restructuring Charges (Summary of Restructuring Charges) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jul. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Restructuring Cost and Reserve [Line Items]
Total restructuring charges		$ 0	$ 4	$ 12	$ 9
E&P
Restructuring Cost and Reserve [Line Items]
Total restructuring charges			4	12	9
Workforce Reduction
Restructuring Cost and Reserve [Line Items]
Severance (including payroll taxes)		0	1	12	4
Office consolidation	$ 3	0	3	0	5
Total restructuring charges		$ 0	4	12	9
Workforce Reduction | E&P
Restructuring Cost and Reserve [Line Items]
Total restructuring charges			$ 4	$ 12	$ 9

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Restructuring Charges (Restructuring Rollforward) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Restructuring Reserve [Roll Forward]
Additions	$ 0	$ 4	$ 12	$ 9
Workforce Reduction
Restructuring Reserve [Roll Forward]
Liability at December 31, 2019			2
Additions	0	$ 4	12	$ 9
Distributions			(14)
Liability at September 30, 2020	$ 0		$ 0

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Revenue Recognition (Narrative) (Details)	9 Months Ended
	Sep. 30, 2020 USD ($)
Disaggregation of Revenue [Line Items]
Contract asset associated with revenues from contracts with customers	$ 0
Contract liability associated with revenues from contracts with customers	$ 0
Minimum | NGL sales
Disaggregation of Revenue [Line Items]
Payment terms	30 days
Minimum | Marketing
Disaggregation of Revenue [Line Items]
Payment terms	30 days
Maximum | NGL sales
Disaggregation of Revenue [Line Items]
Payment terms	60 days
Maximum | Marketing
Disaggregation of Revenue [Line Items]
Payment terms	60 days

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Revenue Recognition (Disaggregation of Revenue by Segment) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 527	$ 636	$ 1,529	$ 2,293
E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	308	357	884	1,288
Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	219	279	645	1,005
Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	298	348	853	1,261
Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	495	592	1,432	2,159
Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	266	304	756	1,127
Intersegment Revenues | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	(10)	(9)	(31)	(27)
Intersegment Revenues | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	276	313	787	1,154
Gas sales
Disaggregation of Revenue [Line Items]
Total operating revenues	199	238	611	943
Gas sales | Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	190	230	584	918
Gas sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0	0
Gas sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	(9)	(8)	(27)	(25)
Oil sales
Disaggregation of Revenue [Line Items]
Total operating revenues	40	67	111	153
Oil sales | Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	39	66	107	151
Oil sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0	0
Oil sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	(1)	(1)	(4)	(2)
NGL sales
Disaggregation of Revenue [Line Items]
Total operating revenues	68	52	158	191
NGL sales | Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	68	52	158	191
NGL sales | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0	0
NGL sales | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0	0
Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	219	279	645	1,004
Marketing | Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0	0	0
Marketing | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	495	592	1,432	2,158
Marketing | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	276	313	787	1,154
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	1	$ 0	4	2
Other | Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	1		4	1
Other | Operating Segments | Marketing
Disaggregation of Revenue [Line Items]
Total operating revenues	0		0	1
Other | Intersegment Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 0		$ 0	$ 0

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Revenue Recognition (Disaggregation of Revenue on Geographic Basis) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 527	$ 636	$ 1,529	$ 2,293
E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	308	357	884	1,288
Operating Segments | E&P
Disaggregation of Revenue [Line Items]
Total operating revenues	298	348	853	1,261
Operating Segments | E&P | Northeast Appalachia
Disaggregation of Revenue [Line Items]
Total operating revenues	131	175	443	740
Operating Segments | E&P | Southwest Appalachia
Disaggregation of Revenue [Line Items]
Total operating revenues	166	173	409	519
Operating Segments | E&P | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 1	$ 0	$ 1	$ 2

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Revenue Recognition (Reconciliation of Accounts Receivable) (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 218	$ 284
Other accounts receivable	21	61
Total accounts receivable	$ 239	$ 345

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Cash and Cash Equivalents (Summary of Cash and Cash Equivalents) (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Cash and Cash Equivalents [Abstract]
Cash	$ 93	$ 5
Marketable securities	2	0
Total	$ 95	$ 5

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Natural Gas and Oil Properties (Narrative) (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) derivative_position $ / bbl $ / MMBTU	Sep. 30, 2019 USD ($) derivative_position $ / bbl $ / MMBTU	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Jun. 30, 2019 USD ($)
Natural Gas and Oil Properties [Line Items]
Natural gas, oil and NGL reserves discount			10.00%
Period of time needed to calculate ceiling value of reserves			12 months
Net book value adjusted for market differentials	$ 361		$ 361		$ 650	$ 1,480
Impairments	$ 361	$ 2	$ 2,495	$ 8
Number of hedge positions designated for hedge accounting | derivative_position			0	0
Other Non-Core Assets
Natural Gas and Oil Properties [Line Items]
Impairments			$ 5
Non-Core Leasehold
Natural Gas and Oil Properties [Line Items]
Consideration amount							$ 25
Natural Gas
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price per MMBtu (in dollars per MMBtu) | $ / MMBTU			1.97	2.87
Oil
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price per barrel (in dollars per bbl) | $ / bbl			43.40	57.77
NGL
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price per barrel (in dollars per bbl) | $ / bbl			9.26	12.59

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Earnings Per Share (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Aug. 31, 2020	Mar. 31, 2019
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Treasury stock acquired (in shares)		5,260,687
Treasury stock acquired		$ 21
Treasury stock acquired, average cost per share (in dollars per share)		$ 3.84
Montage Resources Corporation
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Offering price (in dollars per share)	$ 2.50
Montage Resources Corporation | Public Stock Offering
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Underwritten public offering of common stock (in shares)	63,250,000
Net proceeds from public offering	$ 152

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Earnings Per Share (Schedule of Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Earnings Per Share [Abstract]
Net income (loss)	$ (593)	$ (880)	$ (1,547)	$ 49	$ 138	$ 594	$ (3,020)	$ 781
Number of common shares:
Weighted average outstanding (in shares)	571,872,413			539,221,101			551,162,559	539,315,170
Issued upon assumed exercise of outstanding stock options (in shares)	0			0			0	0
Effect of issuance of non-vested restricted common stock (in shares)	0			187,706			0	400,120
Effect of issuance of non-vested performance units (in shares)	0			629,380			0	727,359
Weighted average and potential dilutive outstanding (in shares)	571,872,413			540,038,187			551,162,559	540,442,649
Earnings per common share
Basic (in dollars per share)	$ (1.04)			$ 0.09			$ (5.48)	$ 1.45
Diluted (in dollars per share)	$ (1.04)			$ 0.09			$ (5.48)	$ 1.44

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Earnings Per Share (Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share) (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	9,583,819	7,479,785	9,495,538	7,160,740
Unexercised stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	4,425,886	5,102,882	4,519,385	5,115,334
Unvested share-based payment
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	939,941	2,136,453	946,547	1,797,963
Restricted stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	1,935,781	0	2,001,621	0
Performance units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	2,282,211	240,450	2,027,985	247,443

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Derivatives and Risk Management (Schedule of Derivative Instruments Notional Amount, Weighted Average Contract Prices and Fair Value) (Details) bbl in Thousands, Mcf in Millions, $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2020 USD ($) $ / MMBTU $ / bbl bbl	Sep. 30, 2020 USD ($) $ / bbl $ / MMBTU Mcf bbl	Dec. 31, 2019 USD ($)
Fixed Price Swaps - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		91
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.46	2.46
Fair value	$ 16	$ 16
Fixed Price Swaps - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		584
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	75.44	75.44
Fair value	$ 20	$ 20
Fixed Price Swaps - 2020 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		2,629
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	8.62	8.62
Fair value	$ 0	$ 0
Fixed Price Swaps - 2020 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		1,435
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	23.11	23.11
Fair value	$ 2	$ 2
Fixed Price Swaps - 2020 | Not Designated as Hedging Instrument | Normal Butane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		195
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	22.44	22.44
Fair value	$ 0	$ 0
Fixed Price Swaps - 2020 | Not Designated as Hedging Instrument | Natural Gasoline
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		184
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	34.59	34.59
Fair value	$ 0	$ 0
Two-way Costless-collars - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		57
Fair value	(7)	$ (7)
Two-way Costless-collars - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		261
Fair value	4	$ 4
Two-way Costless-collars - 2020 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		92
Fair value	$ 0	$ 0
Two-way Costless-collars - 2020 Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.75	2.75
Two-way Costless-collars - 2020 Sold Calls | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	59.75	59.75
Two-way Costless-collars - 2020 Sold Calls | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	29.40	29.40
Three-Way Costless Collars - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		25
Fair value	$ (11)	$ (11)
Three-Way Costless Collars - 2020 | Not Designated as Hedging Instrument | Natural Gas | Derivative liabilities
Derivative [Line Items]
Deferred premiums		$ 2
Three-Way Costless Collars - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		404
Fair value	$ 3	$ 3
Three-way Costless-collars - 2020 Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.96	2.96
Three-way Costless-collars - 2020 Sold Calls | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	57.78	57.78
Financial protection on production - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		173
Fair value	$ (2)	$ (2)
Financial protection on production - 2020 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		1,249
Fair value	27	$ 27
Financial protection on production - 2020 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		1,527
Fair value	$ 2	$ 2
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		93
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.67	2.67
Fair value	$ (13)	$ (13)
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		2,574
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	52.84	52.84
Fair value	$ 27	$ 27
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		5,889
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	7.12	7.12
Fair value	$ (12)	$ (12)
Fixed Price Swaps - 2021 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		4,298
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	19.99	19.99
Fair value	$ (3)	$ (3)
Two-way Costless Collars-2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		166
Fair value	(27)	$ (27)
Two-way Costless Collars-2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		584
Fair value	$ 0	$ 0
Two-way Costless Collars - 2021 Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.89	2.89
Two-way Costless Collars - 2021 Sold Calls | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	10.40	10.40
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		291
Fair value	$ (113)	$ (113)
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Natural Gas | Derivative liabilities
Derivative [Line Items]
Deferred premiums		$ 1
Three-way Costless-collars - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		1,445
Fair value	$ 8	$ 8
Three-Way Costless Collars - 2021 Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.84	2.84
Three-Way Costless Collars - 2021 Sold Calls | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	58.14	58.14
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		550
Fair value	$ (153)	$ (153)
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		4,019
Fair value	35	$ 35
Financial protection on production - 2021 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		6,473
Fair value	$ (12)	$ (12)
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		37
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.75	2.75
Fair value	$ (2)	$ (2)
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		762
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	48.85	48.85
Fair value	$ 4	$ 4
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		190
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	7.41	7.41
Fair value	$ 0	$ 0
Fixed Price Swaps - 2022 | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		156
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	19.25	19.25
Fair value	$ 0	$ 0
Two Way Costless Collars - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		32
Fair value	(5)	$ (5)
Two Way Costless Collars - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		135
Fair value	$ 0	$ 0
Two Way Costless Collars - 2022 Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.88	2.88
Two Way Costless Collars - 2022 Sold Calls | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	9.66	9.66
Three-Way Costless Collars - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		116
Fair value	$ (24)	$ (24)
Three-Way Costless Collars - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		666
Fair value	$ 2	$ 2
Three-way Costless Collars 2022 - Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.87	2.87
Three-way Costless Collars 2022 - Sold Calls | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	58.00	58.00
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		185
Fair value	$ (31)	$ (31)
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		1,428
Fair value	6	$ 6
Financial protection on production - 2022 | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		325
Fair value	0	$ 0
Three Way Costless Collars - 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		25
Fair value	(2)	$ (2)
Three Way Costless Collars - 2023 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		111
Fair value	$ 0	$ 0
Three Way Costless Collars - 2023 Sold Calls | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	3.18	3.18
Three Way Costless Collars - 2023 Sold Calls | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	57.85	57.85
Basis Swaps - 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		66
Basis differential per MMBtu | $ / MMBTU		(0.37)
Fair value	$ 21	$ 21
Basis Swaps - 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		155
Basis differential per MMBtu | $ / MMBTU		(0.12)
Fair value	21	$ 21
Basis Swaps - 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		127
Basis differential per MMBtu | $ / MMBTU		(0.38)
Fair value	4	$ 4
Basis Swaps | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		348
Fair value	$ 46	$ 46
Fixed price swaps | Natural Gas
Derivative [Line Items]
Premium paid		1	$ 9
Fixed price swaps | Not Designated as Hedging Instrument | Natural Gas | Derivative assets
Derivative [Line Items]
Premium paid		$ 1	$ 9
Call Options 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		6
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	3.15	3.15
Fair value	$ (2)	$ (2)
Call Options 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		57
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	3.15	3.15
Fair value	$ (17)	$ (17)
Call Options 2021 | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		226
Cap price (in dollars per MMBtu, Bbl) | $ / bbl	60.00	60.00
Fair value	$ 0	$ 0
Call Options 2022 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		58
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	3.00	3.00
Fair value	$ (15)	$ (15)
Call Options 2023 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		17
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.84	2.84
Fair value	$ (4)	$ (4)
Call Options 2024 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		9
Cap price (in dollars per MMBtu, Bbl) | $ / MMBTU	3.00	3.00
Fair value	$ (2)	$ (2)
Call options | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		147
Fair value	$ (40)	$ (40)
Purchased Fixed Price Swaps, Storage, 2020 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		1
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	1.94	1.94
Basis differential per MMBtu | $ / MMBTU		0
Fair value	$ 0	$ 0
Purchased Basis Swaps, Storage, 2020 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		0
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	0	0
Basis differential per MMBtu | $ / MMBTU		(0.63)
Fair value	$ 0	$ 0
Fixed Price Swaps, Storage, 2020 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		0
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.09	2.09
Basis differential per MMBtu | $ / MMBTU		0
Fair value	$ 0	$ 0
Basis Swaps, Storage, 2020 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		0
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	0	0
Basis differential per MMBtu | $ / MMBTU		(0.70)
Fair value	$ 0	$ 0
Storage 2020 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		1
Fair value	$ 0	$ 0
Purchased Fixed Price Swaps, Storage, 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		1
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.04	2.04
Basis differential per MMBtu | $ / MMBTU		0
Fair value	$ 0	$ 0
Fixed Price Swap, Storage, 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		2
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.49	2.49
Basis differential per MMBtu | $ / MMBTU		0
Fair value	$ (1)	$ (1)
Basis Swaps Storage, 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		1
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	0	0
Basis differential per MMBtu | $ / MMBTU		(0.38)
Fair value	$ 0	$ 0
Storage 2021 | Not Designated as Hedging Instrument
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		4
Fair value	$ (1)	$ (1)
Purchased Fixed Price Swaps, Marketing, 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		2
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.44	2.44
Fair value	$ 0	$ 0
Purchased Fixed Price Swaps, Marketing, 2021 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		6
Weighted average price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.44	2.44
Fair value	$ 3	$ 3
Marketing 2020 | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Volume (Bcf, MBbls) | Mcf		8
Fair value	$ 3	$ 3
Purchased fixed price swaps | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl		448
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	33.94	33.94
Fair value	$ 3	$ 3
Three-way costless collars | Natural Gas
Derivative [Line Items]
Deferred premiums		3
Three-way costless collars | Not Designated as Hedging Instrument | Natural Gas | Derivative liabilities
Derivative [Line Items]
Deferred premiums		$ 3
Sold fixed price swaps | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Volume (Bcf, MBbls) | bbl	1,032
Weighted average price (in dollars per MMBtu, Bbl) | $ / bbl	57.44	57.44
Fair value	$ 17	$ 17
Short Puts | Three-way Costless-collars - 2020 Sold Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.19	2.19
Short Puts | Three-way Costless-collars - 2020 Sold Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	43.71	43.71
Short Puts | Three-Way Costless Collars - 2021 Sold Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.16	2.16
Short Puts | Three-Way Costless Collars - 2021 Sold Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	43.52	43.52
Short Puts | Three-Way Costless Collars - 2022 Sold Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.07	2.07
Short Puts | Three-Way Costless Collars - 2022 Sold Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	42.50	42.50
Short Puts | Three Way Costless Collars - 2023 Sold Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.07	2.07
Short Puts | Three Way Costless Collars - 2023 Sold Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	30.00	30.00
Purchased Puts | Two-way Costless-collars - 2020 Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.45	2.45
Purchased Puts | Two-way Costless-collars - 2020 Purchased Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	56.76	56.76
Purchased Puts | Two-way Costless-collars - 2020 Purchased Puts | Not Designated as Hedging Instrument | Propane
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	25.20	25.20
Purchased Puts | Three-way Costless-collars - 2020 Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.58	2.58
Purchased Puts | Three-way Costless-collars - 2020 Purchased Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	52.85	52.85
Purchased Puts | Two-way Costless Collars - 2021 Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.51	2.51
Purchased Puts | Two-way Costless Collars - 2021 Purchased Puts | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	7.14	7.14
Purchased Puts | Three-Way Costless Collars - 2021 Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.49	2.49
Purchased Puts | Three-Way Costless Collars - 2021 Purchased Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	53.25	53.25
Purchased Puts | Two Way Costless Collars - 2022 Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.17	2.17
Purchased Puts | Two Way Costless Collars - 2022 Purchased Puts | Not Designated as Hedging Instrument | Ethane
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	7.56	7.56
Purchased Puts | Three Way Costless Collars 2022 - Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.44	2.44
Purchased Puts | Three Way Costless Collars 2022 - Purchased Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	53.20	53.20
Purchased Puts | Three Way Costless Collars - 2023 Purchased Puts | Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / MMBTU	2.48	2.48
Purchased Puts | Three Way Costless Collars - 2023 Purchased Puts | Not Designated as Hedging Instrument | Oil
Derivative [Line Items]
Floor price (in dollars per MMBtu, Bbl) | $ / bbl	40.00	40.00

XML

Derivatives and Risk Management (Narrative) (Details) - Not Designated as Hedging Instrument $ in Millions	Sep. 30, 2020 USD ($)
Derivative [Line Items]
Fair value of net derivative liability position	$ 1
Commodities
Derivative [Line Items]
Derivative liability	(125)
Interest rate swaps
Derivative [Line Items]
Derivative notional amount	$ 170

XML

Derivatives and Risk Management (Balance Sheet Classification of Derivative Financial Instruments) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative assets	$ 350	$ 391
Derivative liabilities	475	236
Natural Gas | Fixed price swaps
Derivatives, Fair Value [Line Items]
Premium paid	1	9
Natural Gas | Three-way costless collars
Derivatives, Fair Value [Line Items]
Deferred premiums	3
Natural Gas | Not Designated as Hedging Instrument | Purchased fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	3	0
Natural Gas | Not Designated as Hedging Instrument | Purchased fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	21	77
Premium paid	1	9
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	1	7
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	15	1
Natural Gas | Not Designated as Hedging Instrument | Fixed price swaps | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	6	0
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	27	10
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	13	4
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	52	4
Natural Gas | Not Designated as Hedging Instrument | Two-way costless collars | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	27	4
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	64	126
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	56	74
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	164	84
Deferred premiums	3
Natural Gas | Not Designated as Hedging Instrument | Three-way costless collars | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	106	72
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	40	17
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	13	15
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	3	17
Natural Gas | Not Designated as Hedging Instrument | Basis swaps | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	9
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	9	1
Natural Gas | Not Designated as Hedging Instrument | Call options | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	4	2
Natural Gas | Not Designated as Hedging Instrument | Call options | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	24	3
Natural Gas | Not Designated as Hedging Instrument | Call options | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	29	15
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	42	4
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	10	1
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	1	6
Oil | Not Designated as Hedging Instrument | Fixed price swaps | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	2
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	6	5
Oil | Not Designated as Hedging Instrument | Two-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	2	5
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	19	3
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	14	7
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	10	4
Oil | Not Designated as Hedging Instrument | Three-way costless collars | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	10	8
Oil | Not Designated as Hedging Instrument | Call options | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	0	1
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	2	11
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	10	0
Ethane | Not Designated as Hedging Instrument | Fixed price swaps | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	4	0
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	5	21
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Other long-term assets
Derivatives, Fair Value [Line Items]
Derivative assets	1	3
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	5	0
Propane | Not Designated as Hedging Instrument | Fixed price swaps | Long-term derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	2	0
Propane | Not Designated as Hedging Instrument | Two-way costless collars | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	2
Natural Gas Storage | Not Designated as Hedging Instrument | Fixed price swaps | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	1
Natural Gas Storage | Not Designated as Hedging Instrument | Fixed price swaps | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 1	$ 0

XML

Derivatives and Risk Management (Summary of Before Tax Effect of Fair Value Hedges not Designated for Hedge Accounting) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	$ (289)	$ 12	$ (272)	$ 108
Settled Gain (Loss) on Derivatives Recognized in Earnings	97	88	310	112
Total gain (loss) on derivatives	(192)	100	38	220
Purchased fixed price swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	4	0	4	0
Settled Gain (Loss) on Derivatives Recognized in Earnings	(2)	0	(4)	0
Purchased fixed price swaps | Natural Gas Storage
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	1	0	0	0
Fixed price swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(138)	(19)	(74)	36
Settled Gain (Loss) on Derivatives Recognized in Earnings	61	45	150	53
Amortization of premium paid	4		8
Fixed price swaps | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(20)	8	54	5
Settled Gain (Loss) on Derivatives Recognized in Earnings	17	3	44	5
Fixed price swaps | Ethane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(13)	1	(23)	8
Settled Gain (Loss) on Derivatives Recognized in Earnings	(2)	6	6	12
Fixed price swaps | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(17)	10	(25)	19
Settled Gain (Loss) on Derivatives Recognized in Earnings	2	11	19	20
Two-way costless collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(34)	(11)	(45)	(2)
Settled Gain (Loss) on Derivatives Recognized in Earnings	(5)	10	1	12
Two-way costless collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(5)	0	4	(3)
Settled Gain (Loss) on Derivatives Recognized in Earnings	4	2	13	4
Two-way costless collars | Propane
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(1)	1	(2)	3
Settled Gain (Loss) on Derivatives Recognized in Earnings	0	1	2	1
Three-way costless collars | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(98)	3	(194)	27
Settled Gain (Loss) on Derivatives Recognized in Earnings	0	15	43	19
Three-way costless collars | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(4)	3	15	4
Settled Gain (Loss) on Derivatives Recognized in Earnings	1	0	5	0
Basis swaps | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	54	12	40	6
Settled Gain (Loss) on Derivatives Recognized in Earnings	20	(3)	29	(11)
Call options | Natural Gas
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(16)	1	(25)	5
Settled Gain (Loss) on Derivatives Recognized in Earnings	0	(1)	0	(2)
Amortization of premium paid				1
Call options | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	0	0	1	0
Fixed price swaps – storage | Natural Gas Storage
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	(2)	2	(2)	1
Settled Gain (Loss) on Derivatives Recognized in Earnings	1	(1)	2	(1)
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Unsettled Gain (Loss) on Derivatives Recognized in Earnings	$ 0	$ 1	$ 0	$ (1)

XML

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Jun. 30, 2019	Sep. 30, 2020
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance beginning	$ 823	$ 3,082	$ 2,937	$ 3,246
Net current-period other comprehensive income	1	1	4
Balance ending	384	3,135	3,082	384
Pension and Other Postretirement
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance beginning				(19)
Other comprehensive income before reclassifications				0
Amounts reclassified from other comprehensive income				1
Net current-period other comprehensive income				1
Balance ending	(18)			(18)
Foreign Currency
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance beginning				(14)
Other comprehensive income before reclassifications				0
Amounts reclassified from other comprehensive income				0
Net current-period other comprehensive income				0
Balance ending	(14)			(14)
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance beginning	(33)	(32)	(36)	(33)
Other comprehensive income before reclassifications				0
Amounts reclassified from other comprehensive income				1
Net current-period other comprehensive income	1	1	4	1
Balance ending	$ (32)	$ (31)	$ (32)	$ (32)

XML

Reclassifications from Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net	$ 2			$ (2)			$ 3	$ (7)
Provision (Benefit) for Income Taxes	0			10			406	(401)
Net income (loss)	$ (593)	$ (880)	$ (1,547)	$ 49	$ 138	$ 594	(3,020)	$ 781
Amount Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income (loss)							1
Amortization of prior service cost and net loss | Amount Reclassified from Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Loss), Net							1
Provision (Benefit) for Income Taxes							0
Net income (loss)							$ 1

XML

Fair Value Measurements (Carrying Amount and Estimated Fair Values of Financial Instruments) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ (125)	$ 155
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	95	5
Derivative instruments, net	(125)	155
Carrying Amount | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	2,471	2,228
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	95	5
Derivative instruments, net	(125)	155
Fair Value | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	2,429	2,085
2018 revolving credit facility due April 2024 | Carrying Amount | Long-term debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
2018 revolving credit facility due April 2024	0	34
2018 revolving credit facility due April 2024 | Fair Value | Long-term debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
2018 revolving credit facility due April 2024	0	34
Fixed price swaps | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	1	$ 9
Three-way costless collars | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred premiums	$ 3

XML

Fair Value Measurements (Narrative) (Details) $ in Millions	Sep. 30, 2020 USD ($)
Not Designated as Hedging Instrument
Debt Instrument [Line Items]
Fair value of net derivative liability position	$ 1
Senior Notes | 4.20% Senior Notes Due March 2022
Debt Instrument [Line Items]
Stated interest rate	4.10%

XML

Fair Value Measurements (Summary of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ (125)	$ 155
Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	0	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	(125)	155
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	0	0
Purchased fixed price swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	3
Derivative liabilities		(1)
Purchased fixed price swaps | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0
Derivative liabilities		0
Purchased fixed price swaps | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	3
Derivative liabilities		(1)
Purchased fixed price swaps | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0
Derivative liabilities		0
Fixed price swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	82	124
Derivative liabilities	(43)	(9)
Fixed price swaps | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Premium paid	1	9
Fixed price swaps | Nonperforming Financial Instruments | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of net derivative liability position	1
Fixed price swaps | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Fixed price swaps | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	82	124
Derivative liabilities	(43)	(9)
Fixed price swaps | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Two-way costless collars
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	46	21
Derivative liabilities	(81)	(13)
Two-way costless collars | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Two-way costless collars | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	46	21
Derivative liabilities	(81)	(13)
Two-way costless collars | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Three-way costless collars
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	153	210
Derivative liabilities	(290)	(168)
Three-way costless collars | Natural Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred premiums	3
Three-way costless collars | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Three-way costless collars | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	153	210
Derivative liabilities	(290)	(168)
Three-way costless collars | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Basis swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	53	32
Derivative liabilities	(7)	(26)
Basis swaps | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Basis swaps | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	53	32
Derivative liabilities	(7)	(26)
Basis swaps | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Call options
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	13	3
Derivative liabilities	(53)	(19)
Call options | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Call options | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	13	3
Derivative liabilities	(53)	(19)
Call options | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	0	0
Derivative liabilities	0	0
Fixed price swaps – storage
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset		1
Derivative liabilities	(1)
Fixed price swaps – storage | Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset		0
Derivative liabilities	0
Fixed price swaps – storage | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset		1
Derivative liabilities	(1)
Fixed price swaps – storage | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset		$ 0
Derivative liabilities	$ 0

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Debt (Components of Debt) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019	Apr. 07, 2020	Jul. 31, 2018	Jan. 31, 2015
Debt Instrument [Line Items]
Debt Instrument	$ 2,471	$ 2,262
Unamortized Issuance Expense	20	19
Unamortized Debt Discount	(1)	(1)
Total debt	2,450	2,242
Line of Credit | Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility, due April 2024
Debt Instrument [Line Items]
Debt Instrument	0
Unamortized Issuance Expense	0
Unamortized Debt Discount	0
Total debt	$ 0
Variable interest rate	1.60%
Line of Credit | Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility, due April 2024 | Revolving Credit Facility
Debt Instrument [Line Items]
Debt Instrument		34
Unamortized Issuance Expense		0
Unamortized Debt Discount		0
Total debt		$ 34
Line of Credit | Variable rate (4.310% at December 31, 2019) 2018 term loan facility, due April 2024
Debt Instrument [Line Items]
Variable interest rate		4.31%
Senior Notes | 4.10% Senior Notes due March 2022
Debt Instrument [Line Items]
Debt Instrument	$ 207	$ 213
Unamortized Issuance Expense	0	1
Unamortized Debt Discount	0	0
Total debt	$ 207	$ 212
Stated interest rate	4.10%	4.10%
Senior Notes | 4.95% Senior Notes due January 2025
Debt Instrument [Line Items]
Debt Instrument	$ 856	$ 892
Unamortized Issuance Expense	4	5
Unamortized Debt Discount	(1)	(1)
Total debt	851	$ 886
Stated interest rate		4.95%	6.45%	6.20%	4.95%
Senior Notes | 7.50% Senior Notes due April 2026
Debt Instrument [Line Items]
Debt Instrument	618	$ 639
Unamortized Issuance Expense	6	7
Unamortized Debt Discount	0	0
Total debt	$ 612	632
Stated interest rate	7.50%
Senior Notes | 7.75% Senior Notes due October 2027
Debt Instrument [Line Items]
Debt Instrument	$ 440	484
Unamortized Issuance Expense	5	6
Unamortized Debt Discount	0	0
Total debt	$ 435	478
Stated interest rate	7.75%
Senior Notes | 8.375% Senior Notes due September 2028 (3)
Debt Instrument [Line Items]
Debt Instrument	$ 350
Unamortized Issuance Expense	5
Unamortized Debt Discount	0
Total debt	$ 345
Stated interest rate	8.375%
Other long-term assets | Line of Credit | Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility, due April 2024
Debt Instrument [Line Items]
Unamortized Issuance Expense	$ 10	$ 11

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Debt (2018 Revolving Credit Facility - Narrative) (Details) - USD ($)	1 Months Ended		9 Months Ended
	Oct. 31, 2020	Apr. 30, 2018	Sep. 30, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Subsidiary ownership			100.00%
Letters of credit			$ 203,000,000
Debt instrument			2,471,000,000	$ 2,262,000,000
October 2020 Amendment [Member] | Subsequent Event
Debt Instrument [Line Items]
Basis points	0.25%
Limit of unrestricted cash and cash equivalents	$ 200,000,000
Long-term debt | 2018 revolving credit facility due April 2024
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 3,500,000,000
Current borrowing base			1,800,000,000
Aggregate commitment			1,800,000,000
Limit on securing indebtedness		$ 2,000,000,000.0
Percentage of consolidated net tangible assets		25.00%
Minimum interest coverage ratio		1.00
Long-term debt | 2018 revolving credit facility due April 2024 | Subsequent Event
Debt Instrument [Line Items]
Current borrowing base	2,000,000,000.0
Aggregate commitment	$ 2,000,000,000.0
Long-term debt | 2018 revolving credit facility due April 2024 | Maximum
Debt Instrument [Line Items]
Leverage ratio, percentage of credit limit		10.00%
Leverage ratio, amount of credit limit		$ 150,000,000
Long-term debt | 2018 revolving credit facility due April 2024 | Eurodollar | Minimum
Debt Instrument [Line Items]
Basis points		1.75%
Long-term debt | 2018 revolving credit facility due April 2024 | Eurodollar | Maximum
Debt Instrument [Line Items]
Basis points		2.75%
Long-term debt | 2018 revolving credit facility due April 2024 | Base Rate | Minimum
Debt Instrument [Line Items]
Basis points		0.75%
Long-term debt | 2018 revolving credit facility due April 2024 | Base Rate | Maximum
Debt Instrument [Line Items]
Basis points		1.75%
Line of Credit | 2018 Revolving Credit Facility
Debt Instrument [Line Items]
Debt instrument			$ 0
After June 30, 2020 | Long-term debt | 2018 revolving credit facility due April 2024 | Maximum
Debt Instrument [Line Items]
Leverage ratio		4.00

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Debt (Senior Notes - Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended		9 Months Ended
	Aug. 31, 2020	Jan. 31, 2015	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Apr. 07, 2020	Dec. 31, 2019	Jul. 31, 2018	Jul. 31, 2016
Debt Instrument [Line Items]
Gain on extinguishment of debt			$ 0	$ 7	$ 35	$ 7
Senior Notes
Debt Instrument [Line Items]
Gain on extinguishment of debt					35
Senior Notes | LIBOR
Debt Instrument [Line Items]
Incremental increase in basis points resulting from downgrades		0.25%
Incremental decrease in basis points resulting from upgrades		0.25%
4.95% Senior Notes due January 2025 | Senior Notes
Debt Instrument [Line Items]
Senior notes		$ 1,000
Stated interest rate		4.95%					6.45%	4.95%	6.20%
Stated interest rate cap										6.95%
Repurchased amount			$ 36		$ 36
4.10% Senior Notes due March 2022 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate			4.10%		4.10%			4.10%
Repurchased amount			$ 6		$ 6
7.50% Senior Notes Due April 2026 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate			7.50%		7.50%
Repurchased amount			$ 21		$ 21
7.75% Senior Notes due October 2027 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate			7.75%		7.75%
Repurchased amount			$ 44		$ 44
4.50% Senior Notes due January 2020 | Senior Notes
Debt Instrument [Line Items]
Repurchased amount			$ 72		$ 72
8.375% Senior Notes due September 2028 (3) | Senior Notes
Debt Instrument [Line Items]
Senior notes	$ 350
Stated interest rate			8.375%		8.375%
Proceeds from issuance of long-term debt	$ 345
Percentage price of face value of the notes sold to the public	100.00%
Eight Point Eight Seven Five Percent Senior Notes Due 2023 | Senior Notes | Montage Resources Corporation
Debt Instrument [Line Items]
Senior notes			$ 510		$ 510
Stated interest rate			8.875%		8.875%

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Commitments and Contingencies (Narrative) (Details) - USD ($)	1 Months Ended
	Feb. 29, 2020	Sep. 30, 2020	Dec. 31, 2019	Mar. 31, 2019
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		$ 7,109,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services		1,000,000,000.0
Contractual commitments assumed by buyer		27,000,000
Potential amount to be reimbursed to buyer		13,000,000
Liability for estimated future payments		10,000,000	$ 46,000,000
Contractual commitments	$ 512,000,000
Commitment period	17 years
Material liabilities recognized		0
Pending regulatory approval and/or construction
Commitments And Contingencies [Line Items]
Obligation under transportation agreements		$ 405,000,000
Appalachian Basin
Commitments And Contingencies [Line Items]
Obligation under transportation agreements				$ 357,000,000
Reimbursed by seller				$ 133,000,000

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Commitments and Contingencies (Schedule of Future Obligation under Transportation Agreements) (Details) $ in Millions	Sep. 30, 2020 USD ($)
Other Commitments [Line Items]
Total	$ 7,109
Less than 1 Year	585
1 to 3 Years	1,317
3 to 5 Years	1,101
5 to 8 Years	1,463
More than 8 Years	2,643
Infrastructure currently in service
Other Commitments [Line Items]
Total	6,704
Less than 1 Year	582
1 to 3 Years	1,308
3 to 5 Years	1,078
5 to 8 Years	1,411
More than 8 Years	2,325
Pending regulatory approval and/or construction
Other Commitments [Line Items]
Total	405
Less than 1 Year	3
1 to 3 Years	9
3 to 5 Years	23
5 to 8 Years	52
More than 8 Years	$ 318

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Effective tax rate	0.00%		18.00%	(16.00%)	(105.00%)
Discrete tax benefit		$ 408			$ 400
Valuation allowance related to operating loss		$ 87
Valuation allowance decreased during the period					$ 522

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Pension Plan and Other Postretirement Benefits (Pension and Other Postretirement Benefit Costs) (Details) - Pension - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 1	$ 6	$ 5
Interest cost	1	2	3	4
Expected return on plan assets	(2)	(1)	(5)	(4)
Amortization of prior service cost	0	0	0	0
Amortization of net loss	1	0	1	1
Settlement loss	0	1	0	5
Net periodic benefit cost	$ 2	$ 3	$ 5	$ 11

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Pension Plan and Other Postretirement Benefits (Narrative) (Details) - USD ($)	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				$ 12,000,000
Treasury stock acquired (in shares)			5,260,687
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost (gain)	$ 1,000,000	$ 1,000,000		2,000,000	$ 1,000,000
Benefit obligation	14,000,000			14,000,000		$ 13,000,000
Pension
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost (gain)	2,000,000	3,000,000		5,000,000	11,000,000
Expected future employer contributions, remainder of fiscal year	0			0
Benefit obligation	22,000,000			22,000,000		$ 30,000,000
Settlement loss	$ 0	$ 1,000,000		$ 0	5,000,000
Payments for pension plan					$ 19,000,000
Non-Qualified Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Treasury stock acquired (in shares)				3,632		5,115

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Long-term Incentive Compensation (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Stock Based Compensation 2013 Plan
Long-term Incentive Compensation [Line Items]
Service period				3 years
Stock options
Long-term Incentive Compensation [Line Items]
Vesting period				3 years
Expiration period				7 years
Restricted stock
Long-term Incentive Compensation [Line Items]
Vesting period				4 years
Performance units
Long-term Incentive Compensation [Line Items]
Vesting period				3 years	3 years	3 years
Weighted average period over which unrecognized cost is recognized, years				2 years 2 months 12 days
Liability classified awards, unrecognized compensation costs				$ 14
Restricted stock units
Long-term Incentive Compensation [Line Items]
Vesting period	4 years	4 years	4 years
Weighted average period over which unrecognized cost is recognized, years				2 years 6 months
Liability classified awards, unrecognized compensation costs				$ 21
Performance cash awards
Long-term Incentive Compensation [Line Items]
Vesting period				4 years
Weighted average period over which unrecognized cost is recognized, years				3 years 4 months 24 days
Liability classified awards, unrecognized compensation costs				$ 16
Share-based payment arrangement
Long-term Incentive Compensation [Line Items]
Equity-classified awards, unrecognized compensation cost				$ 2
Weighted average period over which unrecognized cost is recognized, years				6 months

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Long-term Incentive Compensation (Schedule of Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Share-based Payment Arrangement, Noncash Expense [Abstract]
Stock-based compensation cost – expensed	$ 2	$ 1	$ 8	$ 12
Stock-based compensation cost – capitalized	$ 2	$ 1	$ 3	$ 7

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Long-term Incentive Compensation (Schedule of Equity-Classified Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Share-based Payment Arrangement, Noncash Expense [Abstract]
Equity-classified awards – expensed	$ 0	$ 2	$ 2	$ 6
Equity-classified awards – capitalized	$ 1	$ 1	$ 1	$ 3

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Long-term Incentive Compensation (Summary of Equity-Classified Stock Option Activity) (Details) - Stock options shares in Thousands	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Number of Options
Beginning balance (in shares) | shares	4,635
Granted (in shares) | shares	0
Exercised (in shares) | shares	0
Forfeited or expired (in shares) | shares	(357)
Ending balance (in shares) | shares	4,278
Exercisable (in shares) | shares	4,278
Weighted Average Exercise Price
Beginning balance (in dollars per share) | $ / shares	$ 15.26
Granted (in dollars per share) | $ / shares	0
Exercised (in dollars per share) | $ / shares	0
Forfeited or expired (in dollars per share) | $ / shares	7.06
Ending balance (in dollars per share) | $ / shares	15.95
Exercisable (in dollars per share) | $ / shares	$ 15.95

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Long-term Incentive Compensation (Summary of Equity-Classified Restricted Stock Activity) (Details) - Restricted stock shares in Thousands	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Number of Units
Beginning balance (in shares) | shares	1,480
Granted (in shares) | shares	570
Vested (in shares) | shares	(1,083)
Forfeited (in shares) | shares	(246)
Ending balance (in shares) | shares	721
Weighted Average Fair Value
Beginning balance (in dollars per share) | $ / shares	$ 7.00
Granted (in dollars per share) | $ / shares	2.88
Vested (in dollars per share) | $ / shares	5.30
Forfeited (in dollars per share) | $ / shares	7.71
Ending balance (in dollars per share) | $ / shares	$ 6.05

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Long-term Incentive Compensation (Summary of Equity-Classified Performance Units Activity) (Details) - Performance units - $ / shares	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Number of Units
Beginning balance (in shares)	178,000
Granted (in shares)	0
Vested (in shares)	(178,000)
Forfeited (in shares)	0
Ending balance (in shares)	0
Weighted Average Fair Value
Beginning balance (in dollars per share)	$ 10.47
Granted (in dollars per share)	0
Vested (in dollars per share)	10.47
Forfeited (in dollars per share)	0
Ending balance (in dollars per share)	$ 0
Vesting period	3 years	3 years	3 years
Minimum
Number of Units
Granted (in shares)	0
Maximum
Number of Units
Granted (in shares)	2

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Long-term Incentive Compensation (Schedule of Liability-Classified Stock-Based Compensation Costs) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Share-based Payment Arrangement, Noncash Expense [Abstract]
Liability-classified stock-based compensation cost – expensed	$ 2	$ (1)	$ 6	$ 6
Liability-classified stock-based compensation cost – capitalized	$ 1	$ 0	$ 2	$ 4

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Long-term Incentive Compensation (Summary of Liability-Classified Restricted Stock Unit Activity) (Details) - Restricted stock units shares in Thousands	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Number of Units
Beginning balance (in shares) | shares	12,992
Granted (in shares) | shares	6,172
Vested (in shares) | shares	(3,946)
Forfeited (in shares) | shares	(3,060)
Ending balance (in shares) | shares	12,158
Weighted Average Fair Value
Beginning balance (in dollars per share) | $ / shares	$ 2.42
Granted (in dollars per share) | $ / shares	1.41
Vested (in dollars per share) | $ / shares	1.42
Forfeited (in dollars per share) | $ / shares	1.53
Ending balance (in dollars per share) | $ / shares	$ 2.17

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Long-term Incentive Compensation (Summary of Liability-Classified Performance Cash Awards ) (Details) - Performance units - $ / shares shares in Thousands	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Number of Units
Beginning balance (in shares)	5,142
Granted (in shares)	6,172
Vested (in shares)	0
Forfeited (in shares)	(2,300)
Ending balance (in shares)	9,014
Weighted Average Fair Value
Beginning balance (in dollars per share)	$ 2.42
Granted (in dollars per share)	1.41
Vested (in dollars per share)	0
Forfeited (in dollars per share)	3.06
Ending balance (in dollars per share)	$ 2.10
Vesting period	3 years	3 years	3 years

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Long-term Incentive Compensation (Summary of Liability-Classified Restricted Cash Unit Activity) (Details) - Performance cash awards shares in Thousands	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Number of Units
Beginning balance (in shares) | shares	0
Granted (in shares) | shares	20,044
Vested (in shares) | shares	(100)
Forfeited (in shares) | shares	(729)
Ending balance (in shares) | shares	19,215
Weighted Average Fair Value
Beginning balance (in dollars per share) | $ / shares	$ 0
Granted (in dollars per share) | $ / shares	1.00
Vested (in dollars per share) | $ / shares	1.00
Forfeited (in dollars per share) | $ / shares	1.00
Ending balance (in dollars per share) | $ / shares	$ 1.00

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Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Segment Reporting Information [Line Items]
Total operating revenues	$ 527	$ 636	$ 1,529	$ 2,293
Depreciation, depletion and amortization expense	70	125	267	352
Impairments	361	2	2,495	8
Operating (loss) income	(381)	(29)	(2,627)	206
Interest expense	22	17	63	46
(Loss) gain on derivatives	(192)	100	38	220
Gain on early extinguishment of debt	0	7	35	7
Other income, net	2	(2)	3	(7)
Provision (benefit) from income taxes	0	10	406	(401)
Assets	4,157	6,598	4,157	6,598	$ 6,717
Capital investments	223	240	705	933
Restructuring charges	0	4	12	9
Montage acquisition-related expenses	3	0	3	0
Cash and cash equivalents	95		95		5
Right-of-use asset	145		145		159
Property, plant and equipment	3,222		3,222		5,267
Unamortized debt expense	20		20		19
Accounts receivable	239		239		$ 345
Change in accrued expenditures	(7)	(53)	1	52
Intersegment Revenues
Segment Reporting Information [Line Items]
Total operating revenues	266	304	756	1,127
E&P
Segment Reporting Information [Line Items]
Total operating revenues	308	357	884	1,288
Depreciation, depletion and amortization expense	68	123	260	345
Impairments	361	0	2,495	6
Operating (loss) income	(379)	(21)	(2,613)	219
Interest expense	22	17	63	46
(Loss) gain on derivatives	(192)	100	38	220
Gain on early extinguishment of debt		0	0	0
Other income, net	2	(4)	2	(8)
Provision (benefit) from income taxes		10	406	(401)
Assets	3,705	6,099	3,705	6,099
Capital investments	223	239	705	931
Restructuring charges		4	12	9
Montage acquisition-related expenses	3		3
E&P | Intersegment Revenues
Segment Reporting Information [Line Items]
Total operating revenues	(10)	(9)	(31)	(27)
Marketing
Segment Reporting Information [Line Items]
Total operating revenues	219	279	645	1,005
Depreciation, depletion and amortization expense	2	2	7	7
Impairments	0	2	0	2
Operating (loss) income	(2)	(8)	(14)	(13)
Interest expense	0	0	0	0
(Loss) gain on derivatives	0	0	0	0
Gain on early extinguishment of debt		0	0	0
Other income, net	0	0	0	0
Provision (benefit) from income taxes		0	0	0
Assets	240	272	240	272
Capital investments	0	0	0	0
Marketing | Intersegment Revenues
Segment Reporting Information [Line Items]
Total operating revenues	276	313	787	1,154
Other
Segment Reporting Information [Line Items]
Total operating revenues	0	0	0	0
Depreciation, depletion and amortization expense	0	0	0	0
Impairments	0	0	0	0
Operating (loss) income	0	0	0	0
Interest expense	0	0	0	0
(Loss) gain on derivatives	0	0	0	0
Gain on early extinguishment of debt		7	35	7
Other income, net	0	2	1	1
Provision (benefit) from income taxes		0	0	0
Assets	212	227	212	227
Capital investments	0	1	0	2
Cash and cash equivalents	95	29	95	29
Right-of-use asset	74	84	74	84
Property, plant and equipment	18	31	18	31
Unamortized debt expense	10	9	10	9
Prepayments	3	7	3	7
Income tax receivable		61		61
Accounts receivable	7		7
Other | Non-Qualified Supplemental Employee Retirement Plan
Segment Reporting Information [Line Items]
Non-qualified retirement plan	5	7	5	7
Other | Intersegment Revenues
Segment Reporting Information [Line Items]
Total operating revenues	$ 0	$ 0	$ 0	$ 0