Financial Protection on Production
Weighted Average Price per MMBtu

Volume (Bcf)
Swaps Sold Puts Purchased Puts Sold Calls Basis Differential
Fair Value at June 30, 2019
(in millions)
Natural Gas
2019

Fixed price swaps 131
$ 2.92
$ —
$ —
$ —
$ —
$ 75
Two-way costless collars 25
—
—
2.78
2.92
—
13
Three-way costless collars 67
—
2.47
2.88
3.22
—
22
Total 223
$ 110
2020
Fixed price swaps 24
$ 2.88
$ —
$ —
$ —
$ —
$ 8
Three-way costless collars 148
—
2.36
2.67
2.97
—
10
Total 172
$ 18
2021
Three-way costless collars 37
$ —
$ 2.35
$ 2.60
$ 2.93
$ —
$ (1 )

Basis Swaps
2019 80
$ —
$ —
$ —
$ —
$ (0.45 ) $ (6 )
2020 132
—
—
—
—
(0.34 ) (10 )
2021 28
—
—
—
—
(0.51 ) (1 )
Total 240
$ (17 )


	Volume (MBbls)	Weighted Average Strike Price per Bbl														Fair Value at March 31, 2020 (in millions)
				Swaps			Sold Puts			Purchased Puts			Sold Calls
Oil
2020
Fixed price swaps⁽¹⁾	2,442	$	57.75		$	—		$	—		$	—		$	66
Two-way costless collars	731	—			—			56.88			59.81			19
Three-way costless collars	1,210	—			43.94			53.17			58.05			9
Total	4,383													$	94
2021
Fixed price swaps	2,328	$	53.72		$	—		$	—		$	—		$	39
Three-way costless collars	1,445	—			43.52			53.25			58.14			10
Total	3,773													$	49
2022
Fixed price swaps	438	$	51.74		$	—		$	—		$	—		$	5
Three-way costless collars	666	—			42.50			53.20			58.00			4
Total	1,104													$	9

Ethane
2020
Fixed price swaps	6,952	$	8.59		$	—		$	—		$	—		$	21
2021
Fixed price swaps	3,017	$	7.40		$	—		$	—		$	—		$	2

Propane
2020
Fixed price swaps	4,049	$	23.06		$	—		$	—		$	—		$	43
Two-way costless collars	275	—			—			25.20			29.40			4
Total	4,324													$	47
2021
Fixed price swaps	2,460	$	21.77		$	—		$	—		$	—		$	17

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


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2020 (in millions)





Sold Call Options – Natural Gas (Net)
2020	51	$	2.83	$	(2)
2021	57	3.15		(7)
2022	58	3.00		(6)
2023	17	2.84		(3)
2024	9	3.00		(2)
Total	192			$	(20)

໿


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

Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at June 30, 2019
(in millions)
Swaps Sold Puts Purchased Puts Sold Calls
Oil
2019
Fixed price swaps⁽¹⁾
1,003
$ 60.89
$ —
$ —
$ —
$ 4
Two-way costless collars 764
—
—
61.45
67.16
4
Three-way costless collars 276
—
45.00
55.00
63.67
—
Total 2,043
$ 8
2020
Fixed price swaps 1,556
$ 60.18
$ —
$ —
$ —
$ 7
Two-way costless collars 366
—
—
60.00
69.80
3
Three-way costless collars 641
—
45.00
55.00
63.36
1
Total 2,563
$ 11

Propane
2019
Fixed price swaps 1,955
$ 30.18
$ —
$ —
$ —
$ 14
Two-way costless collars 276
—
—
25.62
28.77
1
Total 2,231
$ 15
2020
Fixed price swaps 2,196
$ 26.97
$ —
$ —
$ —
$ 6
Two-way costless collars 366
—
—
25.20
$ 29.40
1
Total 2,562
$ 7

Ethane
2019
Fixed price swaps 1,858
$ 13.90
$ —
$ —
$ —
$ 10
2020
Fixed price swaps 732
$ 13.49
$ —
$ —
$ —
$ 2


~~(1)~~	Includes 138 MBbls of purchased fixed price oil swaps hedged at $69.10 per barrel with a fair value of ($1) million and 1,141 MBbls of sold fixed price oil swaps hedged at $61.88 with a fair value of $5 million.

Other Derivative Contracts

Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
June 30, 2019
(in millions)
Purchased Call Options – Natural Gas
2019 17
$ 3.50
$ —
2020 68
3.63
2
2021 57
3.52
2
Total 142
$ 4

Sold Call Options – Natural Gas
2019 26
$ 3.50
$ —
2020 137
3.39
(8 )
2021 114
3.33
(8 )
Total 277
$ (16 )

໿

Table of Contents


	Volume (Bcf)	Weighted Average Strike Price per MMBtu								Fair Value at March 31, 2020 (in millions)
				Swaps			Basis Differential
Storage ⁽¹⁾
2020
Purchased fixed price swaps	3	$	2.00		$	—		$	(1)
Purchased basis swaps	1	—			(0.49)			—
Sold fixed price swaps	2	1.99			—			—
Sold basis swaps	1	—			(0.51)			—
Total	7							$	(1)
2021
Purchased fixed price swaps	1	$	2.04		$	—		$	—
Sold fixed price swaps	2	2.49			—			—
Sold basis swaps	1	—			(0.38)			—
Total	4							$	—

(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 at a later date.

Volume
(Bcf)
Weighted Average Strike Price per MMBtu Basis Differential per MMBtu
Fair Value at
June 30, 2019
($ in millions)
Storage ⁽¹⁾

2019
Purchased fixed price swaps 1
$ 2.87
$ —
$ (1 )
Purchased basis swaps 1
—
(0.53 ) —
Total 2
$ (1 )

2020
Fixed price swap 1
$ 3.14
$ —
$ —


Purchased Fixed Price Swaps – Marketing (Natural Gas) ⁽¹⁾	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair Value at March 31, 2020 (in millions)
2020	6	$	2.44	$	(2)
2021	6	2.44		—
Total	12			$	(2)


~~(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 at a later date.~~

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

At ~~June 30, 2019,~~March 31, 2020, the net fair value of the Company’s financial instruments related to commodities was a ~~$150~~$402 million ~~asset. The~~asset and included a net reduction of less than $1 million related to non-performance risk. See Note 9 for additional details regarding the Company’s fair value measurements of ~~the Company’s interest rate swaps was a $1 million liability as of June 30, 2019.~~its derivative positions.

As of ~~June 30, 2019,~~March 31, 2020, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gain and losses on both settled and unsettled derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have a notional amount of $170 million and expire in June 2020. ~~The Company did not designate the interest rate swaps for hedge accounting treatment.~~ Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations. At March 31, 2020, the net fair value of the Company’s interest rate swaps was a $1 million liability.

Table of Contents

The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) is summarized below as of ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:

Derivative Assets
Fair Value
(in millions) Balance Sheet Classification June 30, 2019 December 31, 2018
Derivatives not designated as hedging instruments:
Fixed price swaps – natural gas Derivative assets $ 79
$ 32
Fixed price swaps – oil Derivative assets 7
13
Fixed price swaps – propane Derivative assets 18
11
Fixed price swaps – ethane Derivative assets 11
7
Two-way costless collars – natural gas Derivative assets 13
11
Two-way costless collars – oil Derivative assets 6
6
Two-way costless collars – propane Derivative assets 2
—
Three-way costless collars – natural gas Derivative assets 65
41
Three-way costless collars – oil Derivative assets 2
—
Basis swaps – natural gas Derivative assets 5
8
Purchased call options – natural gas Derivative assets 1
⁽¹⁾
—
Interest rate swaps Derivative assets —
1
Fixed price swaps – natural gas Other long-term assets 4
6
Fixed price swaps – oil Other long-term assets 4
6
Fixed price swaps – propane Other long-term assets 2
—
Fixed price swaps – ethane Other long-term assets 1
1
Two-way costless collars – oil Other long-term assets 2
5
Three-way costless collars – natural gas Other long-term assets 31
34
Three-way costless collars – oil Other long-term assets 2
—
Basis swaps – natural gas Other long-term assets 2
3
Purchased call options – natural gas Other long-term assets 4
6
Total derivative assets $ 261
$ 191


Derivative Liabilities
Derivative Assets						Derivative Assets
		Fair Value						Fair Value
(in millions)	Balance Sheet Classification	June 30, 2019		December 31, 2018		(in millions)	Balance Sheet Classification	March 31, 2020			December 31, 2019
Derivatives not designated as hedging instruments:						Derivatives not designated as hedging instruments:
Purchased fixed price swap – oil	Derivative liabilities	$	1	$	6

Purchased fixed price swaps – natural gas						Purchased fixed price swaps – natural gas	Derivative assets	$	1		$	—
Fixed price swaps – natural gas	Derivative liabilities	—		9		Fixed price swaps – natural gas	Derivative assets	181		⁽¹⁾	77		⁽¹⁾
Fixed price swaps – oil						Fixed price swaps – oil	Derivative assets	80			4
Fixed price swaps – ethane	Derivative liabilities	—		3		Fixed price swaps – ethane	Derivative assets	22			11
Fixed price swaps – propane						Fixed price swaps – propane	Derivative assets	48			21
Two-way costless collars – natural gas	Derivative liabilities	—		7		Two-way costless collars – natural gas	Derivative assets	13			10
Two-way costless collars – oil	Derivative liabilities	1		—		Two-way costless collars – oil	Derivative assets	28			5
Two-way costless collars – propane						Two-way costless collars – propane	Derivative assets	4			2
Three-way costless collars – natural gas	Derivative liabilities	37		33		Three-way costless collars – natural gas	Derivative assets	189			126
Three-way costless collars – oil	Derivative liabilities	2		—		Three-way costless collars – oil	Derivative assets	36			3
Basis swaps – natural gas	Derivative liabilities	19		18		Basis swaps – natural gas	Derivative assets	22			17
Sold call options – natural gas	Derivative liabilities	5		3
Storage – fixed price swap	Derivative liabilities	1		—
Interest rate swaps	Derivative liabilities	1		—
Purchased call options – natural gas						Purchased call options – natural gas	Derivative assets	3			1
Fixed price swaps – natural gas storage						Fixed price swaps – natural gas storage	Derivative assets	—			1

Fixed price swaps – natural gas	Other long-term liabilities	—		1		Fixed price swaps – natural gas	Other long-term assets	5			7
Two-way costless collars – oil	Other long-term liabilities	—		1
Fixed price swaps – oil						Fixed price swaps – oil	Other long-term assets	35			1
Fixed price swaps – ethane						Fixed price swaps – ethane	Other long-term assets	1			—
Fixed price swaps – propane						Fixed price swaps – propane	Other long-term assets	12			3
Two-way costless collars – natural gas						Two-way costless collars – natural gas	Other long-term assets	5			4

Three-way costless collars – natural gas	Other long-term liabilities	28		35		Three-way costless collars – natural gas	Other long-term assets	71			74
Three-way costless collars – oil	Other long-term liabilities	1		—		Three-way costless collars – oil	Other long-term assets	29			7
Basis swap – natural gas	Other long-term liabilities	5		4
Sold call options – natural gas	Other long-term liabilities	11		19
Total derivative liabilities		$	112	$	139
Basis swaps – natural gas						Basis swaps – natural gas	Other long-term assets	5			15
Purchased call options – natural gas						Purchased call options – natural gas	Other long-term assets	1			2
Total derivative assets						Total derivative assets		$	791		$	391

(1) Includes $1$9 million in premiums paid related to certain natural gas ~~purchased call options~~fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at ~~June 30,~~both March 31, 2020 and December 31, 2019. As certain natural gas ~~purchased call options~~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.

Table of Contents


Derivative Liabilities
		Fair Value
(in millions)	Balance Sheet Classification	March 31, 2020		December 31, 2019
Derivatives not designated as hedging instruments:
Purchased fixed price swaps – natural gas	Derivative liabilities	$	3	$	1
Purchased fixed price swaps – oil	Derivative liabilities	5		—
Fixed price swaps – natural gas	Derivative liabilities	—		1
Fixed price swaps – oil	Derivative liabilities	—		6

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

Fixed price swaps – oil	Other long-term liabilities	—		2
Two-way costless collars – natural gas	Other long-term liabilities	6		4

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

Table of Contents

The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018:~~2019:


Unsettled Gain (Loss) on Derivatives Recognized in Earnings

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

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(1)	$	—
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	(5)		4
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	103		(2)
Fixed price swaps – oil	Gain (Loss) on Derivatives	118		(13)
Fixed price swaps – ethane	Gain (Loss) on Derivatives	12		7
Fixed price swaps – propane	Gain (Loss) on Derivatives	36		(4)
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	(4)		(1)
Two-way costless collars – oil	Gain (Loss) on Derivatives	19		(7)
Two-way costless collars – propane	Gain (Loss) on Derivatives	2		—
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	(51)		2
Three-way costless collars – oil	Gain (Loss) on Derivatives	25		—
Basis swaps – natural gas	Gain (Loss) on Derivatives	(1)		(10)
Purchased call options – natural gas	Gain (Loss) on Derivatives	1		—
Sold call options – natural gas	Gain (Loss) on Derivatives	(6)		2
Sold call options – oil	Gain (Loss) on Derivatives	1		—
Purchased fixed price swap – natural gas storage	Gain (Loss) on Derivatives	(1)		—
Fixed price swap – natural gas storage	Gain (Loss) on Derivatives	(1)		—
Interest rate swaps	Gain (Loss) on Derivatives	(1)		—
Total gain (loss) on unsettled derivatives				$	246		$	(22)

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

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

		(in millions)
Purchased fixed price swaps – natural gas	Gain (Loss) on Derivatives	$	(1)	$	—
Purchased fixed price swaps – oil	Gain (Loss) on Derivatives	—		(1)
Fixed price swaps – natural gas	Gain (Loss) on Derivatives	5		(6)
Fixed price swaps – oil	Gain (Loss) on Derivatives	9		2
Fixed price swaps – ethane	Gain (Loss) on Derivatives	6		1
Fixed price swaps – propane	Gain (Loss) on Derivatives	10		2
Two-way costless collars – natural gas	Gain (Loss) on Derivatives	6		(1)
Two-way costless collars – oil	Gain (Loss) on Derivatives	3		1
Two-way costless collars – propane	Gain (Loss) on Derivatives	1		—
Three-way costless collars – natural gas	Gain (Loss) on Derivatives	36		(4)
Three-way costless collars – oil	Gain (Loss) on Derivatives	1		—
Basis swaps – natural gas	Gain (Loss) on Derivatives	16		(4)



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

Total gain (loss) on derivatives				$	339		$	(32)

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

Unsettled Gain (Loss) on Derivatives Recognized in Earnings

Derivative Instrument
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Unsettled
For the three months ended June 30, For the six months ended June 30,
2019 2018 2019 2018

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

Fixed price swaps – natural gas Gain (Loss) on Derivatives 57
(26 ) 55
(29 )
Fixed price swaps – oil Gain (Loss) on Derivatives 5
—
(8 ) —

Fixed price swaps – propane Gain (Loss) on Derivatives 13
(12 ) 9
(9 )
Fixed price swaps – ethane Gain (Loss) on Derivatives —
(2 ) 7
(2 )
Two-way costless collars – natural gas Gain (Loss) on Derivatives 10
(1 ) 9
2

Two-way costless collars – oil Gain (Loss) on Derivatives 4
—
(3 ) —

Two-way costless collars – propane Gain (Loss) on Derivatives 2
—
2
—

Three-way costless collars – natural gas Gain (Loss) on Derivatives 22
(24 ) 24
(29 )
Three-way costless collars – oil Gain (Loss) on Derivatives 1
—
1
—

Basis swaps – natural gas Gain (Loss) on Derivatives 4
(4 ) (6 ) 16

Purchased call options – natural gas Gain (Loss) on Derivatives (2 ) (12 ) (2 ) 4

Sold call options – natural gas Gain (Loss) on Derivatives 4
31
6
(3 )
Sold call options – oil Gain (Loss) on Derivatives —
(6 ) —
(6 )
Storage – fixed price swap Gain (Loss) on Derivatives (1 ) —
(1 ) —

Interest rate swaps Gain (Loss) on Derivatives (2 ) —
(2 ) 2

Total gain (loss) on unsettled derivatives $ 118
$ (56 ) $ 96
$ (54 )

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

Derivative Instrument
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Settled
For the three months ended June 30, For the six months ended June 30,
2019 2018 2019 2018

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

Sold fixed price swaps – natural gas Gain (Loss) on Derivatives 14
13
8
13

Sold fixed price swaps – oil Gain (Loss) on Derivatives 2
—
4
—

Sold fixed price swaps – propane Gain (Loss) on Derivatives 7
(1 ) 9
(1 )
Sold fixed price swaps – ethane Gain (Loss) on Derivatives 5
—
6
—

Two-way costless collars – natural gas Gain (Loss) on Derivatives 3
—
2
4

Two-way costless collars – oil Gain (Loss) on Derivatives 1
—
2
—

Three-way costless collars – natural gas Gain (Loss) on Derivatives 8
12
4
19

Sold basis swaps – natural gas Gain (Loss) on Derivatives (4 ) (3 ) (8 ) (24 )
Purchased call options – natural gas Gain (Loss) on Derivatives —
—
—
2
⁽²⁾
Sold call options – natural gas Gain (Loss) on Derivatives (1 ) —
(1 ) (1 )
Sold call options – oil Gain (Loss) on Derivatives —
(1 ) —
(1 )
Total gain on settled derivatives $ 34
$ 20
$ 24
$ 11

Total gain (loss) on derivatives $ 152
$ (36 ) $ 120
$ (43 )


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


~~(2)~~	Includes $1 million amortization of premiums paid related to certain natural gas call options for the six months ended June 30, 2018, which is included in gain (loss) on derivatives on the consolidated statements of operations.

Table of Contents

~~(10)~~(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

In the first ~~half~~quarter of ~~2019,~~2020, changes in accumulated other comprehensive income ~~primarily~~ related to ~~settlements in~~ the Company’s pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income and the related tax effects for the ~~six~~three months ended ~~June 30, 2019:~~March 31, 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⁾	—		—		—
Net current-period other comprehensive income	—		—		—
Ending balance March 31, 2020	$	(19)	$	(14)	$	(33)

(in millions) Pension and Other Postretirement Foreign Currency Total
Beginning balance December 31, 2018 $ (22 ) $ (14 ) $ (36 )
Other comprehensive income before reclassifications —
—
—
Amounts reclassified from other comprehensive income ⁽¹⁾
4
—
4
Net current-period other comprehensive income 4
—
4
Ending balance June 30, 2019 $ (18 ) $ (14 ) $ (32 )


~~(1)~~	~~See separate table below for details about these reclassifications.~~

Details about Accumulated Other
Comprehensive Income Affected Line Item in the
Consolidated Statement of Operations Amount Reclassified from Accumulated Other Comprehensive Income
For the six months ended
June 30, 2019
(in millions)
Pension and other postretirement:
Amortization of prior service cost and net loss⁽¹⁾
Other Income, Net $ 5
Provision for income taxes 1
Net income $ 4

Total reclassifications for the period Net income $ 4

໿


~~(1)~~	(1)Amounts reclassified from other comprehensive income to earnings were immaterial for the three months ended March 31, 2020. See Note 13~~Note 15~~ for additional details regarding the Company’s pension and other postretirement benefit plans.

~~(11)~~

(9) FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis

The carrying amounts and estimated fair values of the Company’s financial instruments as of ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 were as follows:


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

June 30, 2019 December 31, 2018
(in millions)
Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value
Cash and cash equivalents $ 155
$ 155
$ 201
$ 201
2018 revolving credit facility due April 2023 —
—
—
—
Senior notes⁽¹⁾
2,342
2,220
2,342
2,190
Derivative instruments, net 149
⁽²⁾
149
⁽²⁾
52
52
(1)Excludes unamortized debt issuance costs and debt discounts.

(2)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.


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


~~(2)~~	~~Includes $1 million in premiums paid related to certain natural gas purchased call options recognized as a component of derivative assets within current assets 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 ~~were~~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. ~~These instruments were previously classified as a Level~~

~~Table of Contents~~

~~2 measurement but substantially all senior notes were updated to a Level 1 measurement in the second quarter of 2018 as the market activity~~The fair value of the ~~Company’s debt has resulted in timely quoted prices. The 4.05%~~Company's 4.10% Senior Notes due ~~January 2020 remain~~March 2022 is considered to be a Level 2 measurement ~~due to relative market inactivity.~~

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 ~~all~~its derivative instruments isbased upon a pricing model that utilizes market-based inputs, including, but not limited to, the ~~amount at which~~contractual price of the ~~instrument could be exchanged currently between willing parties. The amounts~~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 ~~quoted market prices, best estimates obtained from counterparties~~published credit default swap rates and ~~an option pricing model, when necessary, for price option contracts.~~the duration of each

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

The Company has classified its ~~derivatives~~derivative instruments into ~~these~~ 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 ~~NYMEX~~New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of ~~June 30, 2019~~March 31, 2020 are based on (i) the contracted notional amounts, (ii) active market-quoted ~~London Interbank Offered Rate (“LIBOR”)~~LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s call options, two-way costless collars and three-way costless collars (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves. These instruments were previously classified as a Level 3 measurement in the fair value hierarchy but were updated to a Level 2 measurement in the second quarter of 2018 as a result of the Company’s ability to derive volatility inputs and forward commodity price curves from directly observable sources.

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.

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

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


	March 31, 2020
	Fair Value Measurements Using:
(in millions)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets (Liabilities) at Fair Value
Assets
Purchased fixed price swaps	$	—	$	1	$	—	$	1
Fixed price swaps ⁽¹⁾	—		384		—		384
Two-way costless collars	—		50		—		50
Three-way costless collars	—		325		—		325
Basis swaps	—		27		—		27
Purchased call options	—		4		—		4


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

Two-way costless collars	—		(25)		—		(25)
Three-way costless collars	—		(309)		—		(309)
Basis swaps	—		(22)		—		(22)
Sold call options	—		(24)		—		(24)
Purchased fixed price swaps – storage	—		(1)		—		(1)
Interest rate swaps	—		(1)		—		(1)
Total⁽²⁾	$	—	$	401	$	—	$	401

June 30, 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 swap – natural gas $ —
$ 83
$ —
$ 83
Fixed price swap – oil —
11
—
11
Fixed price swap – propane —
20
—
20
Fixed price swap – ethane —
12
—
12
Two-way costless collar – natural gas —
13
—
13
Two-way costless collar – oil —
8
—
8
Two-way costless collar – propane —
2
—
2
Three-way costless collar – natural gas —
96
—
96
Three-way costless collar – oil —
4
—
4
Basis swap – natural gas —
7
—
7
Purchased call option – natural gas ⁽¹⁾
—
5
—
5
Liabilities
Purchased fixed price swap – oil —
(1 ) —
(1 )
Two-way costless collar – oil —
(1 ) —
(1 )
Three-way costless collar – natural gas —
(65 ) —
(65 )
Three-way costless collar – oil —
(3 ) —
(3 )
Basis swap – natural gas —
(24 ) —
(24 )
Sold call option – natural gas —
(16 ) —
(16 )
Storage – fixed price swap —
(1 ) —
(1 )
Interest rate swap —
(1 ) —
(1 )
Total $ —
$ 149
$ —
$ 149

(1)Includes $1$9 million in premiums paid related to certain natural gas ~~purchased call options~~fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at ~~June 30, 2019.~~March 31, 2020. As certain natural gas ~~purchased call options~~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 a net fair value reduction of less than $1 million related to estimated nonperformance risk.

December 31, 2018
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 swap – natural gas $ —
$ 38
$ —
$ 38
Fixed price swap – oil —
19
—
19
Fixed price swap – propane —
11
—
11
Fixed price swap – ethane —
8
—
8
Two-way costless collar – natural gas —
11
—
11
Two-way costless collar – oil —
11
—
11
Three-way costless collar – natural gas —
75
—
75
Basis swap – natural gas —
11
—
11
Purchased call option – natural gas —
6
—
6
Interest rate swap —
1
—
1
Liabilities
Purchased fixed price swap – oil —
(6 ) —
(6 )
Fixed price swap – natural gas —
(10 ) —
(10 )
Fixed price swap – ethane —
(3 ) —
(3 )
Two-way costless collar – natural gas —
(7 ) —
(7 )
Two-way costless collar – oil —
(1 ) —
(1 )
Three-way costless collar – natural gas —
(68 ) —
(68 )
Basis swap – natural gas —
(22 ) —
(22 )
Sold call option – natural gas —
(22 ) —
(22 )
Total $ —
$ 52
$ —
$ 52

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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
Purchased 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)
Sold call options	—		(19)		—		(19)


Total	$	—	$	155	$	—	$	155

~~The table below presents reconciliations for the change~~(1)Includes $9 million in ~~net fair value~~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 ~~liabilities measured at fair value~~recognized as a component of gain (loss) on ~~a recurring basis using significant unobservable inputs (Level 3) for~~derivatives on the ~~three and six months ended June 30, 2019 and 2018.~~ consolidated statements of operations.

The fair values of Level 3 derivative instruments ~~were~~are estimated using proprietary valuation models that ~~utilized~~utilize both market observable and unobservable parameters. Level 3 instruments ~~presented in the table consisted~~consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, ~~reflected~~reflect reasonable assumptions a marketplace participant would ~~have used as of June 30, 2018. Commodity derivatives previously presented as~~use. There were no Level 3 ~~were transferred to Level 2~~derivatives in the ~~second quarter~~first quarters of ~~2018 as the Company moved from using proprietary volatility inputs~~2020 and ~~forward curves to more widely available published information, increasing market observability.~~2019.

໿

For the three months ended June 30, For the six months ended June 30,
(in millions) 2019 2018 2019

2018
Balance at beginning of period $ —
$ 22
$ —

$ 22

Total gains (losses):

Included in earnings —
(8 ) —

(17 )
Settlements —
(8 ) —
1
⁽¹⁾
Transfers into/out of Level 3 —
(6 )
⁽²⁾
—

(6 )
⁽²⁾
Balance at end of period $ —
$ —
$ —

$ —

Change in gains (losses) included in earnings relating to derivatives still held as of June 30 $ —
$ —
$ —

$ —


~~(1)~~	~~Includes $1 million amortization of premiums paid related to certain natural gas call options for the six months ended June 30, 2018.~~


~~(2)~~	Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.

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~~(12)~~(10) DEBT

The components of debt as of ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 consisted of the following:


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




Long-term debt:
Variable rate (2.120% at March 31, 2020) 2018 revolving credit facility due April 2024	$	149	$	—	⁽¹⁾	$	—	$	149
4.10% Senior Notes due March 2022	210		(1)			—		209
4.95% Senior Notes due January 2025⁽²⁾	864		(5)			(1)		858
7.50% Senior Notes due April 2026	621		(6)			—		615
7.75% Senior Notes due October 2027	453		(5)			—		448
Total long-term debt	$	2,297	$	(17)		$	(1)	$	2,279



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

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June 30, 2019
(in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total
Current portion of long-term debt:
4.05% Senior Notes due January 2020⁽¹⁾
$ 52
$ —
$ —
$ 52
Total current portion of long-term debt $ 52
$ —
$ —
$ 52

Long-term debt:
Variable rate (3.880% at June 30, 2019) 2018 revolving credit facility, due April 2023 $ —
$ —
⁽²⁾
$ —
$ —
4.10% Senior Notes due March 2022 213
(1 ) —
212
4.95% Senior Notes due January 2025⁽¹⁾
927
(7 ) (1 ) 919
7.50 % Senior Notes due April 2026 650
(8 ) —
642
7.75 % Senior Notes due October 2027 500
(6 ) —
494
Total long-term debt $ 2,290
$ (22 ) $ (1 ) $ 2,267

Total debt $ 2,342
$ (22 ) $ (1 ) $ 2,319

December 31, 2018
(in millions) Debt Instrument Unamortized Issuance Expense Unamortized Debt Discount Total
Long-term debt:
Variable rate (3.920% at December 31, 2018) 2018 term loan facility, due April 2023 $ —
$ —
⁽²⁾
$ —
$ —
4.05% Senior Notes due January 2020⁽¹⁾
52
—
—
52
4.10% Senior Notes due March 2022 213
(1 ) —
212
4.95% Senior Notes due January 2025⁽¹⁾
927
(7 ) (1 ) 919
7.50% Senior Notes due April 2026 650
(8 ) —
642
7.75% Senior Notes due October 2027 500
(7 ) —
493
Total long-term debt $ 2,342
$ (23 ) $ (1 ) $ 2,318
(2)At March 31, 2020 and December 31, 2019, respectively, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. This rate has been in effect since January 2019. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which has 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 paid in January 2021.

~~(1)~~

In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In April and May 2018, S&P and Moody’s upgraded certain senior notes. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rate was paid in January 2019.


~~(2)~~	At June 30, 2019 and December 31, 2018, unamortized issuance expense of $10 million and $11 million, respectively, associated with the 2018 revolving credit facility is classified as other long-term assets on the consolidated balance sheets.

Credit Facilities

2018 Revolving Credit Facility

In April 2018, the Company replaced its ~~2016~~ credit facility ~~(which consisted of a $1,191 million secured term loan and an unsecured $743 million revolving credit facility)~~that was entered into in 2016 with a new revolving credit facility (the “2018 credit facility”)~~. Concurrent~~ with ~~the closing~~a group of ~~the 2018 credit facility agreement on~~banks that, as amended, has a maturity date of April 26, 2018, the Company repaid the $1,191 million secured term loan balance and recognized a loss on early debt extinguishment of $8 million on the consolidated income statement related to the unamortized issuance expense. In addition, approximately $4 million of unamortized issuance expense associated with the closed $743 million revolving credit facility was carried forward into the unamortized issuance expenses of the 2018 credit facility.

2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, at ~~June 30, 2019,~~March 31, 2020, had a ~~current~~ borrowing base of $2.1 billion with ~~a current~~ aggregate ~~commitment~~bank commitments of $2.0 billion. The Company may utilize the credit facility in the form of loans and letters of credit. The borrowing base is subject to redetermination at least twice a year, in April and October. On April ~~4, 2019,~~13, 2020, the banks participating in the 2018 credit facility ~~reaffirmed~~redetermined the borrowing base to be $1.8 billion, which also changed the aggregate commitments to that amount. The 2018 credit facility is secured by substantially all of ~~$2.1 billion.~~the assets owned by the Company and its subsidiaries. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion ~~and~~or 25% of adjusted consolidated net tangible assets. ~~The 2018 credit facility matures in April 2023 and is secured by substantially all of the assets owned by the Company and its subsidiaries.~~

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

~~Table of Contents~~

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 ranges from 1.50% to 2.50% based on the Company’s utilization of ~~the borrowing base under~~ 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 ranges from 0.50% to 1.50% based on the Company’s utilization of the ~~borrowing base 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).

Maximum total net leverage ratio of no greater than (i) with respect to each fiscal quarter ending during the period from June 30, 2018 through March 31, 2019, 4.50 to 1.00, (ii) with respect to each fiscal quarter ending during the period from June 30, 2019 through March 31, 2020, 4.25 to 1.00, and (iii) with respect to each fiscal quarter ending on or after June 30, 2020, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. EBITDAX, as defined in the Company’s 2018 credit agreement, 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.

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

2.Maximum total net leverage ratio of no greater than (i) with respect to each fiscal quarter ending during the period from June 30, 2018 through March 31, 2019, 4.50 to 1.00, (ii) with respect to each fiscal quarter ending during the period from June 30, 2019 through March 31, 2020, 4.25 to 1.00, and (iii) with respect to each fiscal quarter ending on or after June 30, 2020, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. EBITDAX, as defined in the credit agreement governing the Company’s 2018 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.

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

As of ~~June 30, 2019,~~March 31, 2020, the Company was in compliance with all of the covenants contained in the credit agreement governing the 2018 credit facility. Beginning late in the first quarter of 2020, decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions reduced the demand for

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

Each United States domestic subsidiary of the Company for which the Company owns 100% guarantees the 2018 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes. ~~See~~ ~~Note 19~~ ~~for the Company’s Condensed Consolidated Financial Information, presented in accordance with Rule 3-10 of Regulation S-X.~~

As of ~~June 30, 2019,~~March 31, 2020, the Company had $172 million in letters of credit and no$149 million borrowings outstanding under the 2018 ~~revolving~~ credit facility. As of April 28, 2020, the Company had been requested to post an additional $150 million in letters of credit related to firm transportation. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.

Senior Notes

In January 2015, the Company completed a public offering of ~~$850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and~~ $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” ~~together with the 2020 Notes, the “Notes”~~). The interest ~~rates~~rate on the 2025 Notes ~~are~~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. ~~In February and June 2016, Moody’s and~~At March 31, 2020, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since the initial offering. This rate has been in effect since January 2019. On April 7, 2020, S&P downgraded the ~~Notes,~~Company’s bond rating to BB- which had the effect of increasing the interest ~~rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for~~rate on the 2025 ~~Notes.~~Notes to 6.45%. 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 ~~are~~have been capped at ~~6.05%~~6.95%.

In the first quarter of 2020, the Company repurchased $3 million of its 4.10% Senior Notes due 2022, $28 million of its 4.95% Senior Notes due 2025, $18 million of its 7.50% Senior Notes due 2026 and ~~6.95%, respectively. The first coupon payment to~~$31 million of its 7.75% Senior Notes due 2027 for $52 million, and recognized a $28 million gain on the ~~bondholders at the higher interest rates was paid in January 2017. S&P and Moody’s upgraded the Notes in April and May 2018, respectively. As a result~~extinguishment of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rates was paid in January 2019.debt.

~~Table of Contents~~

~~(13)~~(11) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of ~~June 30, 2019,~~March 31, 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 ~~$8.5~~$7.6 billion, ~~$966~~$411 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 ~~$362 million~~$1.1 billion of that amount. As of ~~June 30, 2019,~~March 31, 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	$	7,199	$	753	$	1,339	$	1,098	$	1,524	$	2,485
Pending regulatory approval and/or construction ⁽¹⁾	411		1		17		23		74		296
Total transportation charges	$	7,610	$	754	$	1,356	$	1,121	$	1,598	$	2,781

Payments Due by Period
(in millions) Total
Less than 1
Year
1 to 3 Years 3 to 5 Years 5 to 8 Years
More than 8
Years
Infrastructure currently in service $ 7,501
$ 702
$ 1,304
$ 1,097
$ 1,511
$ 2,887
Pending regulatory approval and/or construction ⁽¹⁾
966
9
78
121
196
562
Total transportation charges $ 8,467
$ 711
$ 1,382
$ 1,218
$ 1,707
$ 3,449
(1)Based on estimated in-service dates as of March 31, 2020.


~~(1)~~	~~Based on estimated in-service dates as of June 30, 2019.~~

In December 2018, the Company closed on the Fayetteville Shale ~~sale. The Company~~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 ~~June 30, 2019,~~March 31,

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2020, approximately ~~$162~~$81 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately ~~$82~~$45 million through December 2020 depending on the buyer’s actual use, and has recorded a ~~$68~~$36 million liability for the estimated future payments, down from ~~$88~~$46 million recorded at December 31, ~~2018.~~2019.

In the first quarter of 2019, the Company 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, which is presented in the table above; the seller has agreed to reimburse $133 million of these commitments.

In ~~July 2019~~February 2020, the Company ~~terminated~~was notified that the proposed Constitution pipeline project was cancelled and that the Company was released from a firm transportation agreement with its ~~existing lease agreement and entered into a new lease agreement for a smaller portion of~~sponsor. Prior to its cancellation, the ~~headquarters office building, resulting in a~~Company had contractual ~~commitment~~commitments totaling ~~$88~~$512 million over the next ~~ten years.~~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, ~~that~~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 ~~such items~~litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. ItAs of March 31, 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.

~~Arkansas Royalty Litigation~~

The Company has been a defendant in three certified class actions alleging that the Company underpaid lessors of lands in Arkansas by deducting from royalty payments costs for gathering, transportation and compression of natural gas in excess of what is permitted by the relevant leases. Two of the these class actions were filed in Arkansas state courts and the third in the United StatesSt. Lucie County Fire District Court for the Eastern District of Arkansas. The Company denied liability in all these cases. Under the agreement for the sale of the equity in the Company’s subsidiaries that operated in the Fayetteville Shale, the Company retained responsibility for these class actions.Firefighters’ Pension Trust

~~In June 2017,~~

On October 17, 2016, the ~~jury returned~~St. Lucie County Fire District Firefighters’ Pension Trust filed a ~~verdict in favor of the Company on all counts in~~ ~~Smith v. SEECO, Inc. et al., the~~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, ~~whose plaintiff class comprises~~but after a decision by the ~~vast majority~~United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the ~~lessors in these cases.~~federal court remanded the case to the Texas state court. The ~~plaintiff had asserted claims for, among other things, breach of contract, fraud, civil conspiracy, unjust enrichment and violation of certain Arkansas~~

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~~statutes. Following the verdict, the court entered judgment in favor of the Company on all claims. The~~Texas trial court denied the ~~plaintiff’s~~Company’s motion ~~for a new trial,~~to dismiss, and in February 2020, the ~~plaintiff appealed~~court of appeals declined to ~~the United States Court of Appeals for the Eighth Circuit. Independent of the plaintiff’s appeal, several different parties sought~~exercise discretion to ~~intervene in the~~ ~~Smith~~ ~~case prior to or shortly after trial, and have appealed~~reverse the trial court’s ~~order denying their request~~decision. The Company filed a petition to ~~intervene. Oral argument occurred in January 2019. On April 23, 2019, the Court of Appeals affirmed~~review the trial court’s ~~order denying all requests to intervene in~~decision with the ~~case, and, in a separate order, affirmed~~Texas Supreme Court, which remains pending. The Company carries insurance for the ~~trial court’s judgment in favor of the Company on all claims. The Court of Appeals subsequently denied all requests for rehearing.~~

~~In the second quarter of 2018, the Company entered into an agreement to settle another of the class actions, which has been pending in the Circuit Court of Conway County, Arkansas under the caption~~ ~~Snow et al. v. SEECO, Inc~~.~~, et al. The settlement received final approval by the court during the third quarter of 2018,~~claims asserted against it and the deadline to appeal the order approving the settlement passed without any appeals filed. The amount of the settlement is reflected in the Company’s consolidated statement of operations for the second quarter of 2018officer and ~~was paid early in the fourth quarter of 2018. The third class action was dismissed in the second quarter of 2018.~~

~~The~~ ~~Smith~~director defendants, and the ~~Snow~~ ~~cases cover~~carrier has accepted coverage. The Company denies all ~~affected lessors, except a small percentage who opted out. Most of those have filed separate actions.~~allegations and intends to continue to defend this case vigorously. The Company does not expect ~~those cases~~this case to have a material adverse effect on the results of operations, financial position or cash flows of the ~~Company.~~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 ~~provides~~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 ~~assets. These~~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. NoIn the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. NaN material liabilities have been recognized in connection with these indemnifications.

~~(14)~~

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(12) INCOME TAXES

The Company’s effective tax rate was approximately ~~10% and 0%~~(36)% for the three months ended ~~June 30, 2019 and 2018, respectively, and (128)% and 0%~~March 31, 2020. The change in the effective tax rate for the ~~six~~three months ended ~~June 30, 2019 and 2018, respectively, primarily as~~March 31, 2020 related to the effects of recording a ~~result of~~valuation allowance against the ~~release of valuation allowances previously recorded against~~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 ~~the~~ current and forecasted business economics of the oil and gas industry.

~~For~~Due to significant pricing declines and the ~~year~~material write-down of the carrying value of the Company’s natural gas and oil properties in the three months ended ~~December~~March 31, ~~2018,~~2020, the Company ~~maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative),~~concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense in the period of $408 million for the increase in its valuation allowance. 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 ~~assets would not~~asset considered realizable, however, could be ~~realized. A significant item~~adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence ~~considered~~is no longer present.

The Company’s effective tax rate was approximately (254)% for the ~~cumulative pre-tax loss incurred over~~three months ended March 31, 2019. The effective tax rate for the ~~three-year period~~three months ended ~~December~~March 31, ~~2018,~~2019 was primarily ~~due to impairments~~the effect of ~~proved natural gas and oil properties recognized in 2015 and 2016.~~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 ~~including forecasted income,~~available at the time, the Company concluded that it was more likely than not that the deferred tax assets would be realized and ~~released substantially all~~determined $522 million of the valuation ~~allowance. For~~allowance would be released during 2019, of which $426 million was released on a discrete basis in the first ~~half~~quarter of 2019, the Company has recorded a discrete tax benefit of $411 million. The Company expects to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates.2019.

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~~(15)~~(13) 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 six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018:~~2019:

Pension Benefits

Consolidated Statements of
Operations Classification of
Net Periodic Benefit Cost
For the three months ended June 30, For the six months ended June 30,
(in millions) 2019 2018 2019 2018
Service cost General and administrative expenses $ 2
$ 3
$ 4
$ 6
Interest cost Other Income (Loss), Net 1
1
2
3
Expected return on plan assets Other Income (Loss), Net (1 ) (2 ) (3 ) (4 )
Amortization of prior service cost Other Income (Loss), Net —
—
—
—
Amortization of net loss Other Income (Loss), Net —
—
1
—
Settlement loss Other Income (Loss), Net 4
—
4
—
Net periodic benefit cost $ 6
$ 2
$ 8
$ 5

The Company recognized a $4 million non-cash settlement loss related to $16 million of lump sum payments from the pension plan in the first half of 2019 for employees who were terminated as a result of the Fayetteville Shale sale.



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

Net periodic benefit cost		$	2		$	2

The Company’s other postretirement benefit plan had a net periodic benefit cost of ~~less than~~ $1 million and less than $1 million for the three months ended ~~June 30,~~March 31, 2020 and 2019, ~~and 2018, respectively, and a net periodic benefit cost of $1 million and $2 million for the six months ended June 30, 2019 and 2018,~~ respectively.

As of ~~June 30, 2019,~~March 31, 2020, the Company has contributed $9$5 million to the pension and other postretirement benefit plans and expects to contribute an additional $3$7 million to its pension plan during the remainder of ~~2019.~~2020. The Company recognized liabilities of ~~$28~~$27 million and $13 million related to its pension and other postretirement benefits, respectively, as of ~~June 30, 2019,~~March 31, 2020, compared to liabilities of ~~$34~~$30 million and $13 million as of December 31, ~~2018,~~2019, respectively.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the Non-Qualified Plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are included in treasury stock and totaled 3,632 shares and 5,115 shares ~~and 10,653 shares~~ at ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, respectively.

~~(16) STOCK-BASED~~

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(14) 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 ~~recognized the following amounts in total employee stock-based compensation costs~~issued its first long-term fixed cash-based awards. The resulting impact to general and administrative expenses as well as capitalized expenses was immaterial for the ~~three and six months ended June 30, 2019 and 2018:~~first quarter of 2020.

For the three months ended June 30, For the six months ended June 30,
(in millions) 2019 2018 2019 2018
Stock-based compensation cost – expensed $ 4
$ 8
$ 11
$ 13
Stock-based compensation cost – capitalized 2
4
6
7

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 ~~and capitalized 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. ~~A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in property and equipment.~~ 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, or 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 ~~December 2018,~~February 2020, the Company ~~closed the sale~~notified employees of a workforce reduction plan as a result of a strategic realignment 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 employeesCompany’s organizational structure. This reduction was substantially complete by the end of the ~~buyer although the employment~~first quarter of ~~some was or will be terminated. All affected~~2020. Affected employees were offered a severance package which, if applicable, included ~~a one-time cash payment depending on length of service and, if~~

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~~applicable,~~ the current value of ~~a portion of equity~~unvested long-term incentive awards that were forfeited. ~~Stock-based~~

The Company recognized the following amounts in total employee stock-based compensation costs ~~recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges~~ for ~~the year ended December 31, 2018 and~~ the three months ended March 31, ~~2019 on~~2020 and 2019:


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

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

Equity-Classified Awards

The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018:~~2019:

For the three months ended June 30, For the six months ended June 30,
(in millions) 2019 2018 2019 2018
Equity-classified awards – expensed $ 2
$ 5
$ 4
$ 9
Equity-classified awards – capitalized 1
1
2
4


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

As of ~~June 30, 2019,~~March 31, 2020, there was ~~$11~~$4 million of total unrecognized compensation cost related to the Company’s unvested equity-classified stock option grants, equity-classified restricted stock grants and equity-classified performance units. This cost is expected to be recognized over a weighted-average period of ~~1.3~~0.9 years.

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Equity-Classified Stock Options

The following table summarizes equity-classified stock option activity for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and provides information for options outstanding and options exercisable as of ~~June 30, 2019:~~March 31, 2020:

Number
of Options

Weighted Average
Exercise Price
(in thousands)
Outstanding at December 31, 2018 5,178
$ 17.06
Granted —
$ —
Exercised —
$ —
Forfeited or expired (72 ) $ 18.58
Outstanding at June 30, 2019 5,106
$ 17.04
Exercisable at June 30, 2019 4,590
$ 18.12


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

Equity-Classified Restricted Stock

The following table summarizes equity-classified restricted stock activity for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and provides information for unvested shares as of ~~June 30, 2019:~~March 31, 2020:

Number
of Shares

Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2018 2,717
$ 7.91
Granted 15
$ 4.12
Vested (990 ) $ 7.37
Forfeited (175 ) $ 8.37
Unvested shares at June 30, 2019 1,567
$ 8.17

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	Number of Shares	Weighted Average Fair Value
	(in thousands)
Unvested shares at December 31, 2019	1,480	$	7.00
Granted	12	$	2.42
Vested	(522)	$	7.75
Forfeited	(167)	$	8.59
Unvested shares at March 31, 2020	803	$	6.11

Equity-Classified Performance Units

The following table summarizes equity-classified performance unit activity for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and provides information for unvested units as of ~~June 30, 2019.~~March 31, 2020. The performance unit awards granted in ~~2017~~2018 include a market condition based exclusively on the ~~fair value of the~~ Total Shareholder Return (“TSR”), aswith 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 March 31, 2020	—	$	—

Number
of Shares ⁽¹⁾

Weighted Average
Fair Value
(in thousands)
Unvested units at December 31, 2018 598
$ 10.01
Granted —
$ —
Vested (371 ) $ 9.73
Forfeited (30 ) $ 10.47
Unvested units at June 30, 2019 197
$ 10.47
(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.


~~(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 six~~ months ended ~~June 30, 2019:~~March 31, 2020:


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

For the three months ended June 30, For the six months ended June 30,
(in millions) 2019 2018 2019 2018
Liability-classified stock-based compensation cost – expensed $ 2
$ 3
$ 7
$ 4
Liability-classified stock-based compensation cost – capitalized 1
3
4
3

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Liability-Classified Restricted Stock Units

In the ~~second quarters~~first quarter of ~~2019 and~~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 ~~June 30, 2019,~~March 31, 2020, there was ~~$38~~$26 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of ~~3.2~~3.0 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.


						Number of Units	Weighted Average Fair Value
	Number of Units		Weighted Average Fair Value			(in thousands)
	(in thousands)
Unvested shares at December 31, 2018	8,202		$	3.41
Unvested units at December 31, 2019					Unvested units at December 31, 2019	12,992	$	2.42
Granted	8,659		$	4.34	Granted	6,172	$	1.41
Vested	(2,617	)	$	4.09	Vested	(3,852)	$	1.38
Forfeited	(739	)	$	3.13	Forfeited	(1,464)	$	1.67
Unvested units at June 30, 2019	13,505		$	3.16
Unvested units at March 31, 2020					Unvested units at March 31, 2020	13,848	$	1.69

Liability-Classified Performance Units

In ~~the second quarters of 2019 and~~each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a ~~three-year~~three-year period and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include a performance ~~condition~~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 ~~two~~ market conditions are calculated by Monte Carlo models on a quarterly basis. As of ~~June 30, 2019,~~March 31, 2020, there was ~~$16~~$15 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 ~~2.4~~2.6 years. The

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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	—	$	—
Unvested units at March 31, 2020	11,314	$	1.69

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 March 31, 2020, there was $19 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.9 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.

Number
of Shares

Weighted Average
Fair Value
(in thousands)
Unvested shares at December 31, 2018 2,803
$ 3.41
Granted 2,757
$ 4.34
Vested —
$ —
Forfeited (119 ) $ 4.65
Unvested units at June 30, 2019 5,441
$ 3.16

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

~~(17)~~(15) 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 ~~Midstream~~Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.

Prior to December 2018, the Midstream segment included the Company’s natural gas gathering business associated with its Fayetteville Shale assets. With the closing of the Fayetteville Shale sale in December 2018, the Company’s marketing business comprises substantially all of the Company’s Midstream segment.

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 ~~2018~~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).~~income. The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items.

E&P Midstream Other Total

Three months ended June 30, 2019 (in millions)
Revenues from external customers $ 380
$ 287
$ —
$ 667
Intersegment revenues (9 ) 339
—
330
Depreciation, depletion and amortization expense 118
3
—
121
Operating income (loss) 30
⁽¹⁾
(8 ) —
22
Interest expense ⁽²⁾
15
—
—
15
Gain on derivatives 152
—
—
152
Other loss, net (5 ) —
(1 ) (6 )
Provision for income taxes ⁽²⁾
15
—
—
15
Assets 5,945
⁽³⁾
277

323
⁽⁴⁾
6,545
Capital investments⁽⁵⁾
367
—
1
368

Three months ended June 30, 2018
Revenues from external customers $ 527
$ 289
$ —
$ 816
Intersegment revenues (7 ) 508
—
501
Depreciation, depletion and amortization expense 126
16
—
142
Operating income⁽⁶⁾
97
⁽¹⁾
27
⁽⁷⁾
—
124
Interest expense ⁽²⁾
32
—
—
32
Loss on derivatives (36 ) —
—
(36 )
Loss on early extinguishment of debt —
—
(8 ) (8 )
Other income, net 3
—
—
3
Assets 5,583
⁽³⁾
1,228
231
⁽⁴⁾
7,042
Capital investments ⁽⁵⁾
396
5
2
403

~~Table of Contents~~

E&P Midstream Other Total

Six months ended June 30, 2019 (in millions)
Revenues from external customers $ 931
$ 726
$ —
$ 1,657
Intersegment revenues (18 ) 841
—
823
Depreciation, depletion and amortization expense 228
5
—
233
Operating income (loss) 240
⁽¹⁾
(5 ) —
235
Interest expense⁽²⁾
29
—
—
29
Gain on derivatives 120
—
—
120
Other loss, net (4 ) —
(1 ) (5 )
Benefit from income taxes ⁽²⁾
(411 ) —
—
(411 )
Assets 5,945
⁽³⁾
277
323
⁽⁴⁾
6,545
Capital investments⁽⁵⁾
692
—
1
693

Six months ended June 30, 2018
Revenues from external customers $ 1,170
$ 566
$ —
$ 1,736
Intersegment revenues (13 ) 1,127
—
1,114
Depreciation, depletion and amortization expense 243
42
⁽⁸⁾
—
285
Operating income ⁽⁶⁾
335
⁽¹⁾
44
⁽⁷⁾
—
379
Interest expense⁽²⁾
71
—
—
71
Loss on derivatives (43 ) —
—
(43 )
Loss on early extinguishment of debt —
—
(8 ) (8 )
Other income (loss), net 3
(1 ) —
2
Assets 5,583
⁽³⁾
1,228
231
⁽⁴⁾
7,042
Capital investments⁽⁵⁾
730
9
2
741


~~(1)~~	Operating income for the E&P segment includes $2 million and $16 million of restructuring charges for the three months ended June 30, 2019 and 2018, respectively, and $5 million and $16 million of restructuring charges for the six months ended June 30, 2019 and 2018, respectively.


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


~~(3)~~	E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. This 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 June 30, 2019 and 2018, other assets included approximately $155 million and $37 million, respectively, in cash and cash equivalents, $68 million and $89 million, respectively, in income taxes receivable, $50 million and $83 million, respectively, in property, plant and equipment, $10 million and $12 million, respectively, in unamortized debt expense, $6 million and $8 million, respectively, in a non-qualified retirement plan and $3 million, respectively, in other assets for both periods presented. Additionally, the June 30, 2019 asset balance includes $29 million in right-of-use lease assets.


~~(5)~~	Capital investments include increases of $39 million and $19 million for the three months ended June 30, 2019 and 2018, respectively, and increases of $105 million and $52 million for the six months ended June 30, 2019 and 2018, respectively, relating to the change in accrued expenditures between years.


~~(6)~~	~~Includes the impact of Fayetteville Shale-related E&P and Midstream operations which were divested on December 3, 2018.~~


~~(7)~~	~~Operating income for the Midstream segment includes~~ ~~$2 million~~ ~~related to restructuring charges for the~~ ~~three and six~~ ~~months ended~~ ~~June 30, 2018~~.


~~(8)~~	~~Includes a $10 million impairment related to certain non-core gathering assets.~~

Included in intersegment revenues of the Midstream segment are $339 million and $463 million for the three months ended June 30, 2019 and 2018, respectively, and $841 million and $1,039 million for the six months ended June 30, 2019 and 2018, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other assets. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.


	E&P			Marketing		Other			Total

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

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

Operating income	210		⁽¹⁾	3		—			213
Interest expense⁽²⁾	14			—		—			14
Loss on derivatives	(32)			—		—			(32)

Other income, net	1			—		—			1
Benefit from income taxes⁽²⁾	(426)			—		—			(426)
Assets	5,562		⁽³⁾	342		542		⁽⁴⁾	6,446
Capital investments⁽⁵⁾	325			—		—			325

~~(18)~~

(1)Operating income for the E&P segment includes $10 million and $3 million of restructuring charges for the three months ended March 31, 2020 and 2019, respectively.

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

(3)E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. For the three months ended March 31, 2019, this also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.

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(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At March 31, 2020 and 2019, other assets included approximately $5 million and $366 million, respectively, in cash and cash equivalents, $32 million and $68 million, respectively, in income taxes receivable, $23 million and $56 million, respectively, in property, plant and equipment, $10 million and $10 million, respectively, in unamortized debt expense, $9 million and $10 million, respectively, in prepayments, $5 million and $7 million, respectively, in a non-qualified retirement plan and $77 million and $25 million in right-of-use lease assets, respectively.

(5)Capital investments include increases of $8 million and $66 million for the three months ended March 31, 2020 and 2019, respectively, relating to the change in accrued expenditures between years.

(17) NEW ACCOUNTING PRONOUNCEMENTS

~~New Accounting Standards Implemented~~Recently Adopted

In ~~February 2016,~~August 2018, the FASB issued Accounting Standards Update No. ~~2016-02, Leases (Topic 842)~~2018-13, Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“~~Update 2016-02”~~ASU 2018-13”), which ~~seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities~~modifies the disclosure requirements on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. The codification was amended through additional ASUs. For public entities, Update 2016-02fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted ASC 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial application. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period2019. As a result of adoption, ~~on January 1, 2019, the incremental borrowing rate as of the application date was used~~

~~Table of Contents~~

to calculate the present value of remaining lease payments. Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of thethis standard did not ~~materially change~~have a material impact on the Company’s consolidated ~~statement of operations or its consolidated statement of cash flows. Please refer to~~ ~~Note 4 – “Leases”~~ ~~for full disclosure.~~

~~New Accounting Standards Not Yet Implemented~~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 ~~replaces~~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. ~~The Company is still performing its~~For public business entities, the new standard became effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period.

From an evaluation of the Company’s existing credit portfolio, which includes trade receivables from commodity sales, joint interest billings due from partners and other receivables and cash equivalents, historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business partners. 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 ~~does~~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 ~~believe it will~~expected to have a material impact on ~~its~~the Company’s consolidated financial ~~statements at this time.~~statements.

~~(19)CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~

In April, 2018, the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing the Company’s senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s 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 the Company’s operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes (“Non-Guarantor Subsidiaries”). See ~~Note 12 – Debt~~ for additional information on the Company’s 2018 revolving credit facility and senior notes. At the closing of the Fayetteville Shale sale in December 2018, its subsidiaries being sold were released from these guarantees. See ~~Note 2~~ ~~for additional information on the divestiture of the Company’s Fayetteville Shale-related subsidiaries.~~

The following financial information reflects consolidating financial information of Southwestern Energy Company (the parent and issuer company), its Guarantor Subsidiaries on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.

~~Table of Contents~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Three months ended June 30, 2019
Operating Revenues:
Gas sales $ —
$ 275
$ —
$ —
$ 275
Oil sales —
47
—
—
47
NGL sales —
58
—
—
58
Marketing —
287
—
—
287
—
667
—
—
667
Operating Costs and Expenses:
Marketing purchases —
293
—
—
293
Operating expenses —
169
—
—
169
General and administrative expenses —
40
—
—
40
Loss on sale of operating assets —
3
—
—
3
Restructuring charges —
2
—
—
2
Depreciation, depletion and amortization —
121
—
—
121
Taxes, other than income taxes —
17
—
—
17
—
645
—
—
645
Operating Income —
22
—
—
22
Interest Expense, Net 15
—
—
—
15
Gain on Derivatives —
152
—
—
152
Other Loss, Net —
(6 ) —
—
(6 )
Equity in Earnings of Subsidiaries 153
—
—
(153 ) —

Income (Loss) Before Income Taxes 138
168
—
(153 ) 153
Provision for Income Taxes —
15
—
—
15
Net Income (Loss) $ 138
$ 153
$ —
$ (153 ) $ 138

Net Income (Loss) $ 138
$ 153
$ —
$ (153 ) $ 138
Other Comprehensive Income 4
—
—
—
4
Comprehensive Income (Loss) $ 142
$ 153
$ —
$ (153 ) $ 142

~~Table of Contents~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Three months ended June 30, 2018
Operating Revenues:
Gas sales $ —
$ 407
$ —
$ —
$ 407
Oil sales —
44
—
—
44
NGL sales —
75
—
—
75
Marketing —
265
—
—
265
Gas gathering —
24
—
—
24
Other —
1
—
—
1
—
816
—
—
816
Operating Costs and Expenses:
Marketing purchases —
265
—
—
265
Operating expenses —
193
—
—
193
General and administrative expenses —
59
—
—
59
Restructuring charges —
18
—
—
18
Depreciation, depletion and amortization —
142
—
—
142
Taxes, other than income taxes —
15
—
—
15
—
692
—
—
692
Operating Income —
124
—
—
124
Interest Expense, Net 32
—
—
—
32
Loss on Derivatives —
(36 ) —
—
(36 )
Loss on Early Extinguishment of Debt (8 ) —
—
—
(8 )
Other Income, Net —
3
—
—
3
Equity in Earnings of Subsidiaries 91
—
—
(91 ) —

Income (Loss) Before Income Taxes 51
91
—
(91 ) 51
Provision for Income Taxes —
—
—
—
—
Net Income (Loss) $ 51
$ 91
$ —
$ (91 ) $ 51

Net Income (Loss) $ 51
$ 91
$ —
$ (91 ) $ 51
Other Comprehensive Income —
—
—
—
—
Comprehensive Income (Loss) $ 51
$ 91
$ —
$ (91 ) $ 51

~~Table of Contents~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Six months ended June 30, 2019
Operating Revenues:
Gas sales $ —
$ 705
$ —
$ —
$ 705
Oil sales —
86
—
—
86
NGL sales —
139
—
—
139
Marketing —
725
—
—
725
Other —
2
—
—
2
—
1,657
—
—
1,657
Operating Costs and Expenses:
Marketing purchases —
734
—
—
734
Operating expenses —
334
—
—
334
General and administrative expenses —
77
—
—
77
Loss on sale of operating assets —
3
—
—
3
Restructuring charges —
5
—
—
5
Depreciation, depletion and amortization —
233
—
—
233
Taxes, other than income taxes —
36
—
—
36
—
1,422
—
—
1,422
Operating Income —
235
—
—
235
Interest Expense, Net 29
—
—
—
29
Gain on Derivatives —
120
—
—
120
Other Loss, Net —
(5 ) —
—
(5 )
Equity in Earnings of Subsidiaries 761
—
—
(761 ) —

Income (Loss) Before Income Taxes 732
350
—
(761 ) 321
Benefit from Income Taxes —
(411 ) —
—
(411 )
Net Income (Loss) $ 732
$ 761
$ —
$ (761 ) $ 732

Net Income (Loss) $ 732
$ 761
$ —
$ (761 ) $ 732
Other Comprehensive Income 4
—
—
—
4
Comprehensive Income (Loss) $ 736
$ 761
$ —
$ (761 ) $ 736

~~Table of Contents~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Six months ended June 30, 2018
Operating Revenues:
Gas sales $ —
$ 947
$ —
$ —
$ 947
Oil sales —
79
—
—
79
NGL sales —
140
—
—
140
Marketing —
518
—
—
518
Gas gathering —
48
—
—
48
Other —
4
—
—
4
—
1,736
—
—
1,736
Operating Costs and Expenses:
Marketing purchases —
520
—
—
520
Operating expenses —
382
—
—
382
General and administrative expenses —
114
—
—
114
Restructuring charges —
18
—
—
18
Depreciation, depletion and amortization —
285
—
—
285
Taxes, other than income taxes —
38
—
—
38
—
1,357
—
—
1,357
Operating Income —
379
—
—
379
Interest Expense, Net 71
—
—
—
71
Loss on Derivatives —
(43 ) —
—
(43 )
Loss on Early Extinguishment of Debt (8 ) —
—
—
(8 )
Other Income, Net —
2
—
—
2
Equity in Earnings of Subsidiaries 338
—
—
(338 ) —

Income (Loss) Before Income Taxes 259
338
—
(338 ) 259
Provision for Income Taxes —
—
—
—
—
Net Income (Loss) $ 259
$ 338
$ —
$ (338 ) $ 259
Participating securities - mandatory convertible preferred stock 2
—
—
—
2
Net Income (Loss) Attributable to Common Stock $ 257
$ 338
$ —
$ (338 ) $ 257

Net Income (Loss) $ 259
$ 338
$ —
$ (338 ) $ 259
Other Comprehensive Income —
—
—
—
—
Comprehensive Income (Loss) $ 259
$ 338
$ —
$ (338 ) $ 259

~~Table of Contents~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
June 30, 2019
ASSETS
Cash and cash equivalents $ 155
$ —
$ —
$ —
$ 155
Accounts receivable, net —
358
—
—
358
Other current assets 5
246
—
—
251
Total current assets 160
604
—
—
764

Intercompany receivables 7,894
—
—
(7,894 ) —

Natural gas and oil properties, using the full cost method —
24,769
54
—
24,823
Other 196
330
29
—
555
Less: Accumulated depreciation, depletion and amortization (162 ) (20,059 ) (58 ) —
(20,279 )
Total property and equipment, net 34
5,040
25
—
5,099

Investments in subsidiaries (equity method) —
23
—
(23 ) —
Other long-term assets 45
637
—
—
682
TOTAL ASSETS $ 8,133
$ 6,304
$ 25
$ (7,917 ) $ 6,545

LIABILITIES AND EQUITY

Accounts payable $ 72
$ 513
$ —
$ —
$ 585
Other current liabilities 193
134
—
—
327
Total current liabilities 265
647
—
—
912

Intercompany payables —
7,892
2
(7,894 ) —

Long-term debt 2,267
—
—
—
2,267
Pension and other postretirement liabilities 39
—
—
—
39
Other long-term liabilities 39
206
—
—
245
Negative carrying amount of subsidiaries, net 2,441
—
—
(2,441 ) —
Total long-term liabilities 4,786
206
—
(2,441 ) 2,551
Commitments and contingencies

Total equity (accumulated deficit) 3,082
(2,441 ) 23
2,418
3,082
TOTAL LIABILITIES AND EQUITY $ 8,133
$ 6,304
$ 25
$ (7,917 ) $ 6,545

~~Table of Contents~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
December 31, 2018
ASSETS
Cash and cash equivalents $ 201
$ —
$ —
$ —
$ 201
Accounts receivable, net 4
577
—
—
581
Other current assets 8
166
—
—
174
Total current assets 213
743
—
—
956

Intercompany receivables 7,932
—
—
(7,932 ) —

Natural gas and oil properties, using the full cost method —
24,128
52
—
24,180
Other 197
301
27
—
525
Less: Accumulated depreciation, depletion and amortization (154 ) (19,840 ) (55 ) —
(20,049 )
Total property and equipment, net 43
4,589
24
—
4,656

Investments in subsidiaries (equity method) —
24
—
(24 ) —
Other long-term assets 19
166
—
—
185
TOTAL ASSETS $ 8,207
$ 5,522
$ 24
$ (7,956 ) $ 5,797

LIABILITIES AND EQUITY
Accounts payable $ 113
$ 496
$ —
$ —
$ 609
Other current liabilities 115
122
—
—
237
Total current liabilities 228
618
—
—
846

Intercompany payables —
7,932
—
(7,932 ) —

Long-term debt 2,318
—
—
—
2,318
Pension and other postretirement liabilities 46
—
—
—
46
Other long-term liabilities 54
171
—
—
225
Negative carrying amount of subsidiaries, net 3,199
—
—
(3,199 ) —
Total long-term liabilities 5,617
171
—
(3,199 ) 2,589
Commitments and contingencies

Total equity (accumulated deficit) 2,362
(3,199 ) 24
3,175
2,362
TOTAL LIABILITIES AND EQUITY $ 8,207
$ 5,522
$ 24
$ (7,956 ) $ 5,797

~~Table of Contents~~

~~CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS~~

~~(Unaudited)~~

(in millions) Parent Guarantors Non-Guarantors Eliminations Consolidated
Six months ended June 30, 2019
Net cash provided by (used in) operating activities $ 1,124
$ 179
$ —
$ (760 ) $ 543
Investing activities:
Capital investments (1 ) (584 ) (1 ) —
(586 )
Proceeds from sale —
26
—
—
26
Net cash used in investing activities (1 ) (558 ) (1 ) —
(560 )
Financing activities:
Intercompany activities (1,140 ) 379
1
760
—
Change in bank drafts outstanding (7 ) —
—
—
(7 )
Purchase of treasury stock (21 ) —
—
—
(21 )
Cash paid for tax withholding (1 ) —
—
—
(1 )
Net cash provided by (used in) financing activities (1,169 ) 379
1
760
(29 )
Decrease in cash and cash equivalents (46 ) —
—
—
(46 )
Cash and cash equivalents at beginning of year 201
—
—
—
201
Cash and cash equivalents at end of period $ 155
$ —
$ —
$ —
$ 155

Six months ended June 30, 2018
Net cash provided by (used in) operating activities $ 276
$ 725
$ —
$ (337 ) $ 664
Investing activities:
Capital investments (6 ) (678 ) —
—
(684 )
Other —
9
—
—
9
Net cash used in investing activities (6 ) (669 ) —
—
(675 )
Financing activities:
Intercompany activities (287 ) (50 ) —
337
—
Payments on long-term debt (1,191 ) —
—
—
(1,191 )
Payments on revolving credit facility (645 ) —
—
—
(645 )
Borrowings under revolving credit facility 1,005
—
—
—
1,005
Preferred stock dividend (27 ) —
—
—
(27 )
Other (10 ) —
—
—
(10 )
Net cash provided by (used in) financing activities (1,155 ) (50 ) —
337
(868 )
Increase (decrease) in cash and cash equivalents (885 ) 6
—
—
(879 )
Cash and cash equivalents at beginning of year 914
2
—
—
916
Cash and cash equivalents at end of period $ 29
$ 8
$ —
$ —
$ 37

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 ~~2018~~2019 Annual Report and analyzes the changes in the results of operations between the three ~~and six~~ month periods ended ~~June 30, 2019~~March 31, 2020 and ~~2018.~~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 ~~2018~~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 ~~2018~~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.

Table of Contents

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 ~~refer~~call “Marketing” but previously referred to as ~~“Midstream.”~~“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. ~~Our historical financial and operating results include the Fayetteville Shale E&P and related midstream gathering businesses, which were sold in early December 2018.~~

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 ~~the “Appalachian Basin.~~“Appalachia.” We also operate drilling rigs located in Pennsylvania and West Virginia, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration.

~~Midstream.~~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. ~~In December 2018, we divested almost all of our gathering assets as part of the Fayetteville Shale sale.~~

Recent Financial and Operating Results

Significant ~~second~~first quarter ~~2019~~2020 operating and financial results include:

Total Company

•Net ~~income attributable to common stock~~loss of ~~$138~~$1,547 million, or ~~$0.26~~($2.86) per diluted share, ~~increased 171%~~decreased compared to net income ~~attributable to common stock~~ of ~~$51~~$594 million, or ~~$0.09~~$1.10 per diluted share, for the same period in ~~2018.~~2019. The ~~increase~~decrease was primarily due to a ~~$188~~$1,479 million non-cash full cost ceiling test impairment and a $408 million tax valuation allowance, which were only partially offset by a $371 million positive impact of derivatives, including a ~~$174~~$103 million improvement in ~~unsettled~~settled derivatives as compared to the same period in ~~2018, which was partially offset by decreased operating income and the divestiture~~2019.

•Operating loss of ~~the Fayetteville Shale E&P and related midstream gathering assets on December 3, 2018.~~

~~Operating income of $22~~$1,490 million decreased ~~82%~~ compared to operating income of ~~$124~~$213 million for the same period in ~~2018~~2019 on a consolidated ~~basis. The decrease was~~basis primarily due to a $1,479 million non-cash full cost ceiling test impairment in the first quarter of 2020. Excluding the non-cash impairment, operating loss of $11 million decreased 105% compared to the same period in 2019 primarily due to lower margins associated with reduced commodity ~~prices and the divestiture of the Fayetteville Shale E&P and related midstream gathering assets in December 2018.~~prices.

•Net cash provided by operating activities of ~~$543~~$160 million decreased ~~18%~~64% from ~~$664~~$442 million for the same period in ~~2018~~2019 primarily due to the decrease in operating income net of depreciation, depletion and amortization and impairments, and a reduction in net cash flow associated with working capital, partially offset by the improvement in settled derivatives discussed above.

•Total capital investing of ~~$368~~$237 million decreased 9%27% from ~~$403~~$325 million for the same period in ~~2018.~~2019.

•We repurchased $80 million in aggregate principal amount of our outstanding senior notes at a discount and recognized a gain on the extinguishment of debt of $28 million.

E&P

•E&P segment operating loss of $1,486 million decreased from operating income of ~~$30 million decreased 69% from $97~~$210 million for the same period in ~~2018.~~2019, primarily related to the non-cash impairment of $1,479 million in the first quarter of 2020.

•Total net production of ~~186~~201 Bcfe, which was comprised of ~~79%~~78% natural gas and ~~21%~~22% oil and NGLs, and oil. E&P segment production volumes of 234 Bcfe for the second quarter of 2018 include 67 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding the impact of the production related to the sold Fayetteville Shale assets, our production increased ~~11%~~10% from ~~167~~182 Bcfe in the same period in ~~2018,~~2019, and our liquids production increased ~~15%~~17% over the same ~~periods.~~period primarily associated with our oil production.

•Excluding the effect of derivatives, our realized natural gas price of ~~$1.80~~$1.53 per Mcf decreased ~~10% from the same period in 2018,~~48%, our realized oil price of ~~$49.55~~$36.72 per barrel decreased ~~18% from the same period in 2018~~19% and our realized NGL price of ~~$10.51~~$8.16 per barrel decreased ~~32% from~~44% as compared to the same period in ~~2018.~~2019. Our total weighted average realized price excluding the effect of derivatives of ~~$1.99~~$1.69 per Mcfe decreased ~~10%~~43% from the same period in ~~2018.~~2019.

•E&P segment invested ~~$367~~$237 million in capital; drilling 4138 wells, completing 4022 wells and placing 3612 wells to sales.

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Outlook

We expect to continue to exercise capital discipline ~~through a fully-funded 2019~~in our 2020 capital investment ~~program. We~~program, and we remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities, looking for ~~opportunities~~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. ~~We believe our industry will continue to face challenges due to the uncertainty of~~

Lower natural gas, oil and NGL prices ~~in the United States,~~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 ~~the Company’s 2018~~our 2019 Annual Report. During the first quarter of 2020, the economic impact of the COVID-19 pandemic and related governmental and societal measures (discussed below), along with the disagreements between OPEC and Russia on production levels, have caused oil prices to decrease 66% since the beginning of 2020. In the first quarter of 2020, gains on settled derivatives offset a large portion of the impact of the recent decline in prices, and as of April 28, 2020, we currently have derivative positions in place for 81% 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 expected production at favorable prices. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 3 and Note 7 - Derivatives and Risk Management, in the consolidated financial statements included in this Quarterly Report for further details.

The Impact of COVID-19 on Our Business

During the first quarter 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. Almost all employees working at our sites today are engaged in the physical drilling, completion and operation of wells, and we have instituted additional measures designed to prevent the possible spread of the virus, including social distancing and appropriate personal protective equipment (PPE). 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.

Although prices for oil dropped substantially during March 2020, by early in the first quarter we had protected the price of 99% of our expected 2020 oil production through derivatives. During the first quarter, natural gas prices were not impacted as severely as oil prices, and as of March 31, 2020, we have protected the price of approximately 87% of expected remaining 2020 gas production through derivatives. However, as decreased transportation, manufacturing and general economic activity levels prompted by COVID-19 and related governmental and societal actions have reduced the demand for oil-based products such as gasoline, jet fuel and other refined products, as well as NGLs, space to store oil and condensate production is reaching or may reach capacity in some areas, which is prompting purchasers of oil and condensate to reduce future purchase levels and, in some cases, to claim force majeure for purchases already contracted. Further, although the reduced production of natural gas associated with oil wells has dampened the effect of lower natural gas demand, the demand for natural gas and liquefied natural gas to be exported has fallen. These situations may lead to production greater than storage capacity later in the year, depending on weather and other seasonal factors. In addition, commodity pricing challenges may cause our production costs to exceed the revenues associated with such production. To the extent that this decreased demand for our commodities continues and our margins are not at acceptable levels or storage for our production is not available, we may have to reduce production from or completely shut in portions of our currently producing wells. The inability to sell our production or the decision to potentially reduce or shut in our production could materially and adversely affect our operating results and our ability to comply with the financial covenants under our 2018 credit facility.

There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will likely 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, ~~loss~~gain on early extinguishment of debt and income ~~tax expense~~taxes are discussed on a consolidated basis.

E&P

~~The 2018 information in~~


	For the three months ended March 31,
(in millions)	2020		2019
Revenues	$	344	$	542
Operating costs and expenses⁽¹⁾	1,830		332
Operating income (loss)	$	(1,486)	$	210

Gain on derivatives, settled ⁽²⁾	$	93	$	(10)

(1)Includes $1,479 million related to non-cash full cost ceiling test impairment for the ~~table below includes the financial results from E&P assets in the Fayetteville Shale that were sold in December 2018.~~three months ended March 31, 2020.

For the three months ended June 30, For the six months ended June 30,
(in millions) 2019 2018 2019 2018
Revenues $ 371
$ 520
$ 913
$ 1,157
Operating costs and expenses 341
423
673
822
Operating income $ 30
$ 97
$ 240
$ 335

Gain on derivatives, settled ⁽¹⁾
$ 34
$ 20
$ 24
$ 11

~~(1)~~ (2)Represents the gain on settled commodity ~~derivatives.~~derivatives and is not included in operating income (loss).

Operating Income (Loss)

•Operating income (loss) for the E&P segment operating income for the second quarter of 2018 included $20 million related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding amounts relating to the Fayetteville Shale, E&P segment operating income decreased ~~$47~~$1,696 million for the three months ended ~~June 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, primarily due to a $1,479 million non-cash full cost ceiling test impairment. Excluding the impact of the impairment, operating income (loss) decreased $217 million compared to the same period in 2019 primarily due to lower margins associated with decreased commodity pricing.

Operating income for the E&P segment included $51 million related to our operations in the Fayetteville Shale for the six months ended June 30, 2018. Excluding the amounts related to the Fayetteville Shale, operating income for the E&P segment decreased $44 million for the six months ended June 30, 2019, compared to the same period in 2018, due to lower margins associated with decreased commodity pricing.

Revenues

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


	Three months ended March 31,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues ⁽¹⁾	$	421		$	39		$	81		$	541
Changes associated with prices	(221)			(12)			(39)			(272)
Changes associated with production volumes	39			25			8			72
2020 sales revenues ⁽²⁾	$	239		$	52		$	50		$	341
Increase (decrease) from 2019	(43)		%	33		%	(38)		%	(37)		%

(1)Excludes $1 million in other operating revenues for the three months ended March 31, 2019 primarily related to third-party water sales.

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

Three months ended June 30,
(in millions except percentages) Natural
Gas Oil NGLs Total
2018 sales revenues⁽¹⁾
$ 400
$ 44
$ 75
$ 519
Changes associated with the Fayetteville Shale sale⁽²⁾
(139 ) —
—
(139 )
2018 sales revenues, net of Fayetteville Shale revenues 261
44
75
380
Changes associated with prices (22 ) (10 ) (27 ) (59 )
Changes associated with production volumes 28
12
10
50
2019 sales revenues $ 267
$ 46
$ 58
$ 371
Increase (decrease) from 2018, net of Fayetteville Shale revenues 2 % 5 % (23 )% (2 %)


~~(1)~~	~~Excludes $1 million in other operating revenues for the three months ended June 30, 2018 related to third-party water sales.~~


~~(2)~~	~~This amount represents the revenues associated with the Fayetteville Shale assets, which were sold on December 3, 2018. There were no Fayetteville Shale revenues in the first half of 2019.~~

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Six months ended June 30,
(in millions except percentages) Natural
Gas Oil NGLs Total
2018 sales revenues ⁽¹⁾
$ 935
$ 78
$ 140
$ 1,153
Changes associated with the Fayetteville Shale sale⁽²⁾
(291 ) —
—
(291 )
2018 sales revenues, net of Fayetteville Shale revenues 644
78
140
862
Changes associated with prices (22 ) (19 ) (32 ) (73 )
Changes associated with production volumes 66
26
31
123
2019 sales revenues ⁽³⁾
$ 688
$ 85
$ 139
$ 912
Increase (decrease) from 2018, net of Fayetteville Shale revenues 7 % 9 % (1 )% 6 %


~~(1)~~	~~Excludes $4 million in other operating revenues for the six months ended June 30, 2018 related to third-party water sales.~~


~~(2)~~	~~This amount represents the revenues associated with the Fayetteville Shale assets, which were sold on December 3, 2018. There were no Fayetteville Shale revenues in the first half of 2019.~~


~~(3)~~	~~Excludes $1 million in other operating revenues for the six months ended June 30, 2019 related to third-party water sales.~~

Production Volumes


	For the three months ended March 31,					Increase/(Decrease)
Production volumes:	2020		2019
Natural Gas (Bcf)
Northeast Appalachia	114		112		2%
Southwest Appalachia	42		31		35%

Total	156		143		9%

Oil (MBbls)
Southwest Appalachia	1,395		849		64%
Other	4		5		(20)%
Total	1,399		854		64%

NGL (MBbls)
Southwest Appalachia	6,127		5,602		9%
Other	1		1		—%
Total	6,128		5,603		9%

Production volumes by area: (Bcfe)
Northeast Appalachia	114		112		2%
Southwest Appalachia⁽¹⁾	87		70		24%

Total	201		182		10%

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

For the three months ended June 30, Increase/(Decrease) For the six months ended June 30, Increase/(Decrease)
Production volumes: 2019 2018 2019 2018
Natural Gas (Bcf)

Northeast Appalachia 113
112
1% 225
220
2%
Southwest Appalachia 35
22
59% 66
44
50%
Fayetteville Shale ⁽¹⁾
—
67
(100%) —
134
(100%)
Total 148
201
(26%) 291
398
(27%)

Oil (MBbls)

Southwest Appalachia 931
707
32% 1,780
1,301
37%
Other 6
16
(63%) 11
35
(69%)
Total 937
723
30% 1,791
1,336
34%

NGL (MBbls)

Southwest Appalachia 5,493
4,850
13% 11,095
9,068
22%
Other 4
12
(67%) 5
24
(79%)
Total 5,497
4,862
13% 11,100
9,092
22%

Production volumes by area: (Bcfe)

Northeast Appalachia 113
112
1% 225
220
2%
Southwest Appalachia 73
55
33% 143
106
35%
Fayetteville Shale ⁽¹⁾
—
67
(100%) —
134
(100%)
Total 186
234
(21%) 368
460
(20%)

Production percentage: (Bcfe)

Natural gas 79 % 86 % 79 % 86 %
Oil 3 % 2 % 3 % 2 %
NGL 18 % 12 % 18 % 12 %
Total 100 % 100 % 100 % 100 %


~~(1)~~	~~The Fayetteville Shale assets were sold on December 3, 2018.~~

~~E&P segment production volumes~~(1)Approximately 87 Bcfe and 69 Bcfe for the ~~second quarter of 2018 included 67 Bcf of production related to our operations in~~three months ended March 31, 2020 and March 31, 2019, respectively, were produced from the ~~Fayetteville~~Marcellus Shale ~~which was sold in December 2018. Excluding this amount, production~~formation.

•Production volumes for our E&P segment increased by 19 Bcfe for the three months ended ~~June 30, 2019~~March 31, 2020 compared to the same period in ~~2018,~~2019, primarily due to a ~~33%~~24% increase in production volumes ~~from~~in Southwest Appalachia.

E&P segment production volumes for the six months ended June 30, 2018 included 134 Bcf of production related to our operations in the Fayetteville Shale, which was sold in December 2018. Excluding this amount, production volumes for our E&P segment increased by 42 Bcfe for the six months ended June 30, 2019 compared to the same period in 2018, primarily due to a 35% increase in production volumes from Southwest Appalachia.

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Oil and NGL production increased ~~30%~~64% and ~~13%~~9%, respectively, for the three months ended ~~June 30, 2019,~~March 31, 2020, compared to the same period in ~~2018, reflecting our shifting commodity production mix towards liquids.~~


•	~~Oil and NGL production increased 34% and 22%, respectively, for the~~ ~~six months endedJune 30, 2019, compared to the same period in~~ ~~2018~~.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 June 30,						Increase/(Decrease)		For the six months ended June 30,							Increase/(Decrease)				For the three months ended March 31,								Increase/(Decrease)
	2019			2018				2019				2018							2020				2019
Natural Gas Price:																		Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾	$	2.64		$	2.80		(6)%		$	2.89			$	2.90		—%	NYMEX Henry Hub Price ($/MMBtu) ⁽¹⁾			$	1.95			$	3.15		(38)%
Discount to NYMEX ⁽²⁾	(0.84		)	(0.81		)	4%		(0.52		)		(0.55		)	(5%)	Discount to NYMEX ⁽²⁾			(0.42)				(0.20)			(110)%
Average realized gas price per Mcf, excluding derivatives	$	1.80		$	1.99		(10)%		$	2.37			$	2.35		1%
Loss on settled financial basis derivatives ($/Mcf)	(0.03		)	(0.01		)			(0.03		)		(0.06		)
Gain on settled commodity derivatives ($/Mcf)	0.17			0.13					0.04				0.10
Average realized gas price per Mcf, including derivatives	$	1.94		$	2.11		(8)%		$	2.38			$	2.39		—%
Average realized gas price, excluding derivatives ($/Mcf)																	Average realized gas price, excluding derivatives ($/Mcf)			$	1.53			$	2.95		(48)%
Gain (loss) on settled financial basis derivatives ($/Mcf)																	Gain (loss) on settled financial basis derivatives ($/Mcf)			0.10				(0.03)
Gain (loss) on settled commodity derivatives ($/Mcf)																	Gain (loss) on settled commodity derivatives ($/Mcf)			0.31				(0.08)
Average realized gas price, including derivatives ($/Mcf)																	Average realized gas price, including derivatives ($/Mcf)			$	1.94			$	2.84		(32)%

Oil Price:																	Oil Price:
WTI oil price ($/Bbl)	$	59.81		$	67.88		(12%)		$	57.36			$	65.37		(12%)	WTI oil price ($/Bbl)			$	46.17			$	54.90		(16)%
Discount to WTI	(10.26		)	(7.73		)	33%		(9.75		)		(7.12		)	37%	Discount to WTI			(9.45)				(9.42)			—%
Average oil price per Bbl, excluding derivatives	$	49.55		$	60.15		(18%)		$	47.61			$	58.25		(18%)
Gain (loss) on settled derivatives ($/Bbl)	2.05			(0.93		)			2.19				(0.51		)
Average oil price per Bbl, including derivatives	$	51.60		$	59.22		(13%)		$	49.80			$	57.74		(14%)
Average oil price, excluding derivatives ($/Bbl)																	Average oil price, excluding derivatives ($/Bbl)			$	36.72			$	45.48		(19)%
Gain on settled derivatives ($/Bbl)																	Gain on settled derivatives ($/Bbl)			9.25				2.34
Average oil price, including derivatives ($/Bbl)																	Average oil price, including derivatives ($/Bbl)			$	45.97			$	47.82		(4)%

NGL Price:																	NGL Price:
Average net realized NGL price per Bbl, excluding derivatives	$	10.51		$	15.37		(32%)		$	12.50			$	15.39		(19%)
Gain (loss) on settled derivatives ($/Bbl)	2.11			(0.32		)			1.34				(0.17		)
Average net realized NGL price per Bbl, including derivatives	$	12.62		$	15.05		(16%)		$	13.84			$	15.22		(9%)
Average realized NGL price, excluding derivatives ($/Bbl)																	Average realized NGL price, excluding derivatives ($/Bbl)			$	8.16			$	14.45		(44)%
Gain on settled derivatives ($/Bbl)																	Gain on settled derivatives ($/Bbl)			2.62				0.60
Average realized NGL price, including derivatives ($/Bbl)																	Average realized NGL price, including derivatives ($/Bbl)			$	10.78			$	15.05		(28)%
Percentage of WTI, excluding derivatives	18		%	23		%			22		%		24		%		Percentage of WTI, excluding derivatives			18		%		26		%

Total Weighted Average Realized Price:																	Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	1.99		$	2.21		(10)%		$	2.48			$	2.51		(1)%	Excluding derivatives ($/Mcfe)			$	1.69			$	2.98		(43)%
Including derivatives ($/Mcfe)	$	2.17		$	2.30		(6)%		$	2.54			$	2.53		—%	Including derivatives ($/Mcfe)			$	2.16			$	2.92		(26)%


~~(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.~~

(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 ~~hedging~~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 9 7 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 ~~June 30, 2019:~~March 31, 2020:


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas
2020	199	$	(0.44)
2021	103	(0.03)
2022	88	(0.48)
Total	390

Physical NYMEX Sales Arrangements – Natural Gas
2020	178	$	(0.28)
2021	94	(0.29)
Total	272

Volume (Bcf) Basis Differential
Basis Swaps - Natural Gas
2019 80
$ (0.45 )
2020 132
(0.34 )
2021 28
(0.51 )
Total 240

Physical NYMEX Sales Arrangements - Natural Gas
2019 134
$ (0.24 )
2020 103
(0.13 )
Total 237

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In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of ~~June 30, 2019:~~March 31, 2020:


	Remaining 2019	Full Year 2020	Full Year 2021		Remaining 2020	Full Year 2021	Full Year 2022
Natural gas (Bcf)	223	172	37	Natural gas (Bcf)	438	330	120
Oil (MBbls)	2,043	2,563	—	Oil (MBbls)	4,383	3,773	1,104
Ethane (MBbls)				Ethane (MBbls)	6,952	3,017	—
Propane (MBbls)	2,231	2,562	—	Propane (MBbls)	4,324	2,460	—
Ethane (MBbls)	1,858	732	—
Total financial protection on future production (Bcfe)	260	207	37	Total financial protection on future production (Bcfe)	532	386	127

We refer you to Note 9 7 of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

Operating Costs and Expenses


	For the three months ended March 31,					Increase/(Decrease)
(in millions except percentages)	2020		2019
Lease operating expenses	$	194	$	166	17%
General & administrative expenses	23		34		(32)%

Restructuring charges	10		3		233%
Taxes, other than income taxes	13		19		(32)%
Full cost pool amortization	106		103		3%
Non-full cost pool DD&A	5		7		(29)%
Impairments	1,479		—		100%
Total operating costs	$	1,830	$	332	451%

For the three months ended June 30, Increase/(Decrease) For the six months ended June 30, Increase/(Decrease)
(in millions except percentages) 2019 2018

2019 2018
Lease operating expenses $ 169
$ 215

(21%) $ 335
$ 428
(22%)
General & administrative expenses 35
53
⁽¹⁾
(34%) 69
101
⁽¹⁾
(32%)
Restructuring charges 2
16

(88)% 5
16
(69)%
Taxes, other than income taxes 17
13

31% 36
34
6%
Full cost pool amortization 108
117

(8%) 211
225
(6%)
Non-full cost pool DD&A 10
9

11% 17
18
(6%)
Total operating costs $ 341
$ 423
(19%) $ 673
$ 822
(18%)

(1) Includes $7.9 million of legal settlement charges for the three and six months ended June 30, 2018.

For the three months ended June 30, Increase/ For the six months ended June 30, Increase/
Average unit costs per Mcfe: 2019 2018 (Decrease) 2019 2018 (Decrease)
Lease operating expenses ⁽¹⁾
$ 0.90
$ 0.91
(1%) $ 0.90
$ 0.93
(3%)
General & administrative expenses $ 0.19
⁽²⁾
$ 0.19
⁽³⁾
—% $ 0.19
⁽²⁾
$ 0.20
⁽³⁾
(5%)
Taxes, other than income taxes $ 0.09
$ 0.06
⁽⁴⁾
50% $ 0.10
$ 0.07
⁽⁴⁾
43%
Full cost pool amortization $ 0.58
$ 0.50
16% $ 0.57
$ 0.49
16%


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


~~(2)~~	~~Excludes $2 million and $5 million of restructuring charges for the three and six months ended June 30, 2019, respectively.~~


~~(3)~~	~~Excludes $15 million of restructuring charges and $7.9 million of legal settlement charges for the three and six months ended June 30, 2018.~~


~~(4)~~	~~Excludes $1 million of restructuring charges for the three and six months ended June 30, 2018.~~


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

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

(2)Excludes a $10 million in restructuring charges for the three months ended March 31, 2020.

(3)Excludes $3 million of ~~Contents~~restructuring charges for the three months ended March 31, 2019.



Class						Outstanding as of ~~August 2, 2019~~April 28, 2020
Common Stock, Par Value $0.01						~~541,316,769~~541,688,616



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			8
			Note 1. Basis of Presentation	8
			Note 2. ~~Divestitures~~Restructuring Charges	8
			Note 3. ~~Restructuring Charges~~Revenue Recognition	9
			Note 4. ~~Leases~~	9
	~~Note 5. Revenue Recognition~~	11
	~~Note 6.~~ Cash and Cash Equivalents	1411
			Note 7.5. Natural Gas and Oil Properties	1411
			Note 8.6. Earnings per Share	1411
			Note 9.7. Derivatives and Risk Management	1513
			Note ~~10.~~8. Reclassifications From Accumulated Other Comprehensive Income (Loss)	2220
			Note ~~11.~~9. Fair Value Measurements	2220
			Note ~~12.~~10. Debt	2622
			Note ~~13.~~1 1 . Commitments and Contingencies	2824
			Note ~~14.~~1 2 . Income Taxes	2926
			Note ~~15.~~1 3 . Pension Plan and Other Postretirement Benefits	3026
			Note ~~16.~~1 4 . Stock-Based Compensation	3027
			Note ~~17.~~1 5 . Segment Information	3330
			Note ~~18.~~1 6 . New Accounting Pronouncements	3431
	~~Note 19. Condensed Consolidated Financial Information~~	35
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			4231
		Results of Operations			4434
		Liquidity and Capital Resources			5140
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			5645
Item 4.		Controls and Procedures			5645

PART II – OTHER INFORMATION

Item 1.		Legal Proceedings			5746
Item 1A.		Risk Factors			5747
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			5747
Item 3.		Defaults Upon Senior Securities			5747
Item 4.		Mine Safety Disclosures			5747
Item 5.		Other Information			5747
Item 6.		Exhibits			5848



Right-of-use asset balance: (in millions)	June 30, 2019
Operating leases	$	103
Lease liability balance: (in millions)
Short-term operating leases	$	47
Long-term operating leases	56
Total operating leases	$	103

Weighted average remaining lease term: (years)
Operating leases	3.8

Weighted average discount rate:
Operating leases	6.28		%


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


(in millions)	March 31, 2020		March 31, 2019
Natural gas (per MMBtu)	$	2.30	$	3.07
Oil (per Bbl)	$	55.77	$	63.00
NGLs (per Bbl)	$	9.96	$	17.65


	For the three months ended March 31,
(in millions, except share/per share amounts)	2020		2019
Operating Revenues:
Gas sales	$	248	$	430
Oil sales	52		39
NGL sales	50		81
Marketing	239		438
Other	3		2
	592		990
Operating Costs and Expenses:
Marketing purchases	248		441
Operating expenses	193		165
General and administrative expenses	26		37

Restructuring charges	10		3
Depreciation, depletion and amortization	113		112
Impairments	1,479		—
Taxes, other than income taxes	13		19
	2,082		777
Operating Income (Loss)	(1,490)		213
Interest Expense:
Interest on debt	40		42
Other interest charges	2		1
Interest capitalized	(23)		(29)
	19		14

Gain (Loss) on Derivatives	339		(32)
Gain on Early Extinguishment of Debt	28		—
Other Income, Net	1		1

Income (Loss) Before Income Taxes	(1,141)		168
Provision (Benefit) for Income Taxes:
Current	(2)		—
Deferred	408		(426)
	406		(426)
Net Income (Loss)	$	(1,547)	$	594


Earnings (Loss) Per Common Share:
Basic	$	(2.86)	$	1.10
Diluted	$	(2.86)	$	1.10

Weighted Average Common Shares Outstanding:
Basic	540,308,491		539,721,751
Diluted	540,308,491		541,320,487



	For the three months ended June 30,						For the six months ended June 30,
(in millions, except share/per share amounts)	2019			2018			2019			2018
Operating Revenues:
Gas sales	$	275		$	407		$	705		$	947
Oil sales	47			44			86			79
NGL sales	58			75			139			140
Marketing	287			265			725			518
Gas gathering	—			24			—			48
Other	—			1			2			4
	667			816			1,657			1,736
Operating Costs and Expenses:
Marketing purchases	293			265			734			520
Operating expenses	169			193			334			382
General and administrative expenses	40			59			77			114
Loss on sale of operating assets	3			—			3			—
Restructuring charges	2			18			5			18
Depreciation, depletion and amortization	121			142			233			285
Taxes, other than income taxes	17			15			36			38
	645			692			1,422			1,357
Operating Income	22			124			235			379
Interest Expense:
Interest on debt	41			59			83			124
Other interest charges	2			2			3			4
Interest capitalized	(28		)	(29		)	(57		)	(57		)
	15			32			29			71

Gain (Loss) on Derivatives	152			(36		)	120			(43		)
Loss on Early Extinguishment of Debt	—			(8		)	—			(8		)
Other Income (Loss), Net	(6		)	3			(5		)	2

Income Before Income Taxes	153			51			321			259
Provision (Benefit) for Income Taxes
Current	—			—			—			—
Deferred	15			—			(411		)	—
	15			—			(411		)	—
Net Income	$	138		$	51		$	732		$	259
Participating securities - mandatory convertible preferred stock	—			—			—			2
Net Income Attributable to Common Stock	$	138		$	51		$	732		$	257

Earnings Per Common Share
Basic	$	0.26		$	0.09		$	1.36		$	0.45
Diluted	$	0.26		$	0.09		$	1.35		$	0.44

Weighted Average Common Shares Outstanding:
Basic	539,005,941			581,159,200			539,362,984			576,255,744
Diluted	539,947,053			582,878,106			540,624,742			578,222,740


~~(1)~~	~~In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.~~


~~(2)~~	~~Primarily related to settlement of pension assets in the second quarter of 2019. Net of $1 million in taxes for the three and six months ended June 30, 2019.~~


	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
Treasury stock	—	—		—		—		—		—	—			—
Performance units vested	—	—		—		—		—		—	—			—
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


~~(1)~~	Total restructuring charges were $2 million and $5 million for the Company’s E&P segment for the three and six months ended June 30, 2019, respectively, and $16 million and $2 million for the Company’s E&P and Midstream segments, respectively, for the three and six months ended June 30, 2018.


(in millions)
Liability at December 31, 2019	$	2
Additions	10
Distributions	(12)
Liability at March 31, 2020	$	—



(in millions)	June 30, 2019
Liability at December 31, 2018	$	5
Additions	5
Distributions	(10		)
Liability at June 30, 2019	$	—



	For the six months ended June 30, 2019
(in millions)	For the six months ended June 30, 2019
Operating lease cost	$	22
Short-term lease cost	31
Variable lease cost	—
Total lease cost	$	53


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Three months ended March 31, 2020
Gas sales	$	239	$	—	$	9	$	248
Oil sales	52		—		—		52
NGL sales	50		—		—		50
Marketing	—		548		(309)		239
Other ⁽¹⁾	3		—		—		3
Total	$	344	$	548	$	(300)	$	592

Three months ended March 31, 2019
Gas sales	$	421	$	—	$	9	$	430
Oil sales	39		—		—		39
NGL sales	81		—		—		81
Marketing	—		940		(502)		438
Other ⁽²⁾	1		1		—		2
Total	$	542	$	941	$	(493)	$	990


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



(in millions)	E&P		Midstream		Intersegment Revenues			Total
Three months ended June 30, 2019
Gas sales	$	267	$	—	$	8		$	275
Oil sales	46		—		1			47
NGL sales	58		—		—			58
Marketing	—		626		(339		)	287
Total	$	371	$	626	$	(330	)	$	667

Three months ended June 30, 2018
Gas sales	$	400	$	—	$	7		$	407
Oil sales	44		—		—			44
NGL sales	75		—		—			75
Marketing	—		728		(463		)	265
Gas gathering ⁽¹⁾	—		69		(45		)	24
Other ⁽²⁾	1		—		—			1
Total	$	520	$	797	$	(501	)	$	816


~~(1)~~	~~The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale.~~


~~(2)~~	~~Other E&P revenues consists primarily of water sales to third-party operators, and other Midstream revenues consists primarily of sales of gas from storage.~~



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 ~~which,~~that, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

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

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

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


Financial Protection on Production
		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair Value at March 31, 2020 (in millions)
Natural Gas
2020
Fixed price swaps	279	$	2.50	$	—	$	—	$	—	$	—	$	181	⁽¹⁾
Two-way costless collars	23	—		—		2.50		2.79		—		3
Three-way costless collars	136	—		2.08		2.42		2.70		—		15
Total	438											$	199
2021
Fixed price swaps	36	$	2.53	$	—	$	—	$	—	$	—	$	5
Two-way costless collars	29	—		—		2.28		2.77		—		(1)
Three-way costless collars	265	—		2.18		2.49		2.84		—		(20)
Total	330											$	(16)
2022
Two-way costless collars	29	$	—	$	—	$	2.10	$	2.83	$	—	$	—
Three-way costless collars	91	—		2.10		2.46		2.86		—		(2)
Total	120											$	(2)
2023

Three-way costless collars	2	$	—	$	2.15	$	2.55	$	3.35	$	—	$	—

Basis Swaps
2020	199	$	—	$	—	$	—	$	—	$	(0.44)	$	(3)
2021	103	—		—		—		—		(0.03)		12
2022	88	—		—		—		—		(0.48)		(4)
Total	390											$	5



	Volume (MBbls)	Weighted Average Strike Price per Bbl								Fair Value at June 30, 2019 (in millions)
	Volume (MBbls)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Fair Value at June 30, 2019 (in millions)
Oil
2019
Fixed price swaps⁽¹⁾	1,003	$	60.89	$	—	$	—	$	—	$	4
Two-way costless collars	764	—		—		61.45		67.16		4
Three-way costless collars	276	—		45.00		55.00		63.67		—
Total	2,043									$	8
2020
Fixed price swaps	1,556	$	60.18	$	—	$	—	$	—	$	7
Two-way costless collars	366	—		—		60.00		69.80		3
Three-way costless collars	641	—		45.00		55.00		63.36		1
Total	2,563									$	11

Propane
2019
Fixed price swaps	1,955	$	30.18	$	—	$	—	$	—	$	14
Two-way costless collars	276	—		—		25.62		28.77		1
Total	2,231									$	15
2020
Fixed price swaps	2,196	$	26.97	$	—	$	—	$	—	$	6
Two-way costless collars	366	—		—		25.20		$	29.40	1
Total	2,562									$	7

Ethane
2019
Fixed price swaps	1,858	$	13.90	$	—	$	—	$	—	$	10
2020
Fixed price swaps	732	$	13.49	$	—	$	—	$	—	$	2



	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Basis Differential per MMBtu			Fair Value at June 30, 2019 ($ in millions)
Storage ⁽¹⁾
2019
Purchased fixed price swaps	1	$	2.87	$	—		$	(1	)
Purchased basis swaps	1	—		(0.53		)	—
Total	2						$	(1	)

2020
Fixed price swap	1	$	3.14	$	—		$	—



Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations	Amount Reclassified from Accumulated Other Comprehensive Income
		For the six months ended June 30, 2019
		(in millions)
Pension and other postretirement:
Amortization of prior service cost and net loss⁽¹⁾	Other Income, Net	$	5
	Provision for income taxes	1
	Net income	$	4

Total reclassifications for the period	Net income	$	4



		Pension Benefits
	Consolidated Statements of Operations Classification of Net Periodic Benefit Cost	For the three months ended June 30,						For the six months ended June 30,
(in millions)		2019			2018			2019			2018
Service cost	General and administrative expenses	$	2		$	3		$	4		$	6
Interest cost	Other Income (Loss), Net	1			1			2			3
Expected return on plan assets	Other Income (Loss), Net	(1		)	(2		)	(3		)	(4		)
Amortization of prior service cost	Other Income (Loss), Net	—			—			—			—
Amortization of net loss	Other Income (Loss), Net	—			—			1			—
Settlement loss	Other Income (Loss), Net	4			—			4			—
Net periodic benefit cost		$	6		$	2		$	8		$	5



	Number of Shares ⁽¹⁾		Weighted Average Fair Value
	(in thousands)
Unvested units at December 31, 2018	598		$	10.01
Granted	—		$	—
Vested	(371	)	$	9.73
Forfeited	(30	)	$	10.47
Unvested units at June 30, 2019	197		$	10.47



(in millions)	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
Three months ended June 30, 2019
Operating Revenues:
Gas sales	$	—	$	275		$	—	$	—		$	275
Oil sales	—		47			—		—			47
NGL sales	—		58			—		—			58
Marketing	—		287			—		—			287
	—		667			—		—			667
Operating Costs and Expenses:
Marketing purchases	—		293			—		—			293
Operating expenses	—		169			—		—			169
General and administrative expenses	—		40			—		—			40
Loss on sale of operating assets	—		3			—		—			3
Restructuring charges	—		2			—		—			2
Depreciation, depletion and amortization	—		121			—		—			121
Taxes, other than income taxes	—		17			—		—			17
	—		645			—		—			645
Operating Income	—		22			—		—			22
Interest Expense, Net	15		—			—		—			15
Gain on Derivatives	—		152			—		—			152
Other Loss, Net	—		(6		)	—		—			(6		)
Equity in Earnings of Subsidiaries	153		—			—		(153		)	—

Income (Loss) Before Income Taxes	138		168			—		(153		)	153
Provision for Income Taxes	—		15			—		—			15
Net Income (Loss)	$	138	$	153		$	—	$	(153	)	$	138

Net Income (Loss)	$	138	$	153		$	—	$	(153	)	$	138
Other Comprehensive Income	4		—			—		—			4
Comprehensive Income (Loss)	$	142	$	153		$	—	$	(153	)	$	142



	Three months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2018 sales revenues⁽¹⁾	$	400		$	44		$	75		$	519
Changes associated with the Fayetteville Shale sale⁽²⁾	(139		)	—			—			(139		)
2018 sales revenues, net of Fayetteville Shale revenues	261			44			75			380
Changes associated with prices	(22		)	(10		)	(27		)	(59		)
Changes associated with production volumes	28			12			10			50
2019 sales revenues	$	267		$	46		$	58		$	371
Increase (decrease) from 2018, net of Fayetteville Shale revenues	2		%	5		%	(23		)%	(2		%)



	Six months ended June 30,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2018 sales revenues ⁽¹⁾	$	935		$	78		$	140		$	1,153
Changes associated with the Fayetteville Shale sale⁽²⁾	(291		)	—			—			(291		)
2018 sales revenues, net of Fayetteville Shale revenues	644			78			140			862
Changes associated with prices	(22		)	(19		)	(32		)	(73		)
Changes associated with production volumes	66			26			31			123
2019 sales revenues ⁽³⁾	$	688		$	85		$	139		$	912
Increase (decrease) from 2018, net of Fayetteville Shale revenues	7		%	9		%	(1		)%	6		%



	Volume (Bcf)	Basis Differential
Basis Swaps - Natural Gas
2019	80	$	(0.45	)
2020	132	(0.34		)
2021	28	(0.51		)
Total	240

Physical NYMEX Sales Arrangements - Natural Gas
2019	134	$	(0.24	)
2020	103	(0.13		)
Total	237


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

Gain on sale of operating assets	—			(1)			(100)%
Operating income (loss)	$	(4)		$	3		(233)%

Volumes marketed (Bcfe)	263			289			(9)%

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


~~(1)~~	~~Reflects the sale of our Fayetteville Shale-related gathering business, which was sold in December 2018.~~


~~(2)~~	~~Includes $2 million of restructuring charges for the three months ended June 30, 2018.~~


~~(3)~~	~~Includes $10 million impairment related to certain non-core gathering assets and $2 million of restructuring charges for the six months ended June 30, 2018.~~


~~(4)~~	~~Includes the effect of the purchase and sale of a portion of the production from the buyer of the Fayetteville Shale, which was sold in December 2018.~~