Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§(§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

~~256,333,325~~259,778,494 Common Shares were outstanding on ~~October 26,~~July 23, ~~2020~~2021

Unless the context otherwise indicates, all references in this report to “Range Resources,” “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its directly and indirectly owned subsidiaries. For certain industry specific terms used in this Form 10-Q, please see “Glossary of Certain Defined Terms” in our ~~2019~~2020 Annual Report on Form 10-K.

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

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the bank credit facility agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the bank credit facility agreement) of no less than ~~1.0.~~1.0. In addition, the ratio of the present value of proved reserves (as defined in the bank credit facility agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at ~~September~~June 30, ~~2020.~~2021.

(11) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We utilize commodity swaps, collars, three-way collars or swaptions to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. The fair value of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange ~~(“NYMEX”)~~(NYMEX) for natural gas and crude oil or Mont Belvieu for NGLs, approximated a net loss of ~~$83.5~~$287.7 million at ~~September~~June 30, ~~2020.~~2021. These contracts expire monthly through December ~~2021.~~ 2022. The following table sets forth our commodity-based derivative

volumes by year as of ~~September~~June 30, ~~2020,~~2021, excluding our basis and freight swaps and divestiture contingent consideration which are discussed separately below:

Period

Contract Type

Volume Hedged

Weighted Average Hedge Price

Swap

Sold Put

Floor

Ceiling
Natural Gas ⁽¹⁾






2020

Swaps

1,133,587 Mmbtu/day

$
2.63

2021

Swaps

510,000 Mmbtu/day

$
2.77

2020

Collars

5,041 Mmbtu/day

$ 2.00

$ 2.50
January – October 2021

Collars

342,237 Mmbtu/day

$ 2.51

$ 3.00
2020

Three-way Collars

79,891 Mmbtu/day

$ 2.23

$ 2.58

$ 3.19
2021

Three-way Collars

240,000 Mmbtu/day

$ 1.99

$ 2.33

$ 2.60

Crude Oil






2020

Swaps

6,000 bbls/day

$
58.02

2021

Swaps

1,000 bbls/day

$
55.00

NGLs (C3-Propane)

2020

Swaps

6,000 bbls/day

$
0.51/gallon

NGLs (NC4-Normal Butane)

2020

Swaps

1,000 bbls/day

$
0.60/gallon

NGLs (C5-Natural Gasoline)

2020

Swaps

2,000 bbls/day

$
0.89/gallon


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
			Swap			Sold Put	Floor		Ceiling
Natural Gas (1)
2021	Swaps	575,000 Mmbtu/day	$	2.78
2021	Collars	293,696 Mmbtu/day					$	2.65	$	3.16
2021	Three-way Collars	309,728 Mmbtu/day			$	2.14	$	2.47	$	2.84
2022	Swaps	190,000 Mmbtu/day	$	2.82
2022	Collars	40,000 Mmbtu/day					$	2.90	$	3.29
2022	Three-way Collars	200,000 Mmbtu/day			$	2.20	$	2.72	$	3.35

Crude Oil (1)
2021	Swaps	7,166 bbls/day	$	56.28
2022	Swaps	4,560 bbls/day	$	60.39

NGLs (C3-Propane)
2021	Swaps	6,000 bbls/day	$	0.90/gallon
July – September 2021	Collars	5,000 bbls/day					$	0.95/gallon	$	1.05/gallon

NGLs (NC4-Normal Butane)
2021	Swaps	2,000 bbls/day	$	1.05/gallon
2021	Collars	2,500 bbls/day					$	0.94/gallon	$	1.08/gallon

NGLs (C5-Natural Gasoline)
2021	Swaps	3,000 bbls/day	$	1.28/gallon
2021	Collars	2,000 bbls/day					$	1.34/gallon	$	1.55/gallon
2022	Swaps	1,000 bbls/day	$	1.50/gallon
2022	Collars	1,000 bbls/day					$	1.40/gallon	$	1.60/gallon

(1) We also sold natural gas call swaptions of 180,000 Mmbtu/day for 2022 at a weighted average price of $2.86. In addition, we sold oil call swaptions of 1,000 bbls per day for 2022 at a weighted average price of $54.00.

⁽¹⁾	We also sold natural gas call swaptions of 140,000 Mmbtu/day for 2021 at a weighted average price of $2.88. In addition, we sold natural gas call swaptions of 280,000 bbls per day for 2022 at a weighted average price of $2.81.

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. We recognize all changes in fair value of these derivatives as earnings in derivative fair value income or loss in the periods in which they occur.

Basis Swap Contracts

In addition to the swaps, collars and swaptions described above, at ~~September~~June 30, ~~2020,~~2021, we had natural gas basis swap contracts which lock in the differential between NYMEX Henry Hub and certain of our physical pricing indices. These contracts settle monthly through December 2024 and include a total volume of ~~81,745,000~~229,880,000 Mmbtu. The fair value of these contracts was a gain of ~~$5.4~~$25.7 million at ~~September~~June 30, ~~2020.~~2021.

At ~~September~~June 30, ~~2020,~~2021, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. The contracts settle monthly ~~in 2020 and include a total volume of 312,500 barrels.~~through 2022. The fair value of these contracts was a ~~loss~~gain of ~~$529,000~~$376,000 at ~~September~~June 30, ~~2020.~~2021.

Freight Swap Contracts

In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at ~~September~~June 30, ~~2020,~~2021, we had freight swap contracts on the Baltic Exchange which lock in the freight rate for a specific trade route. These contracts settle monthly ~~through December~~and cover 10,000 metric tons per month in third quarter 2021 ~~with~~and 12,000 metric tons for the remainder of 2021. The fair value of these contracts equal to a ~~loss~~gain of ~~$1.4 million~~$37,000 at ~~September~~June 30, ~~2020.~~2021.

Divestiture Contingent Consideration

In addition to the derivatives described above, our right to receive contingent consideration in conjunction with the sale of our North Louisiana assets was determined to be a derivative financial instrument that is not designated as a hedging instrument. The remaining contingent consideration of up to ~~$90.0~~$75.0 million is based on future achievement of natural gas and oil prices based on published indexes and realized NGLs prices of the buyer ~~from July through December 2020 and~~ for the years 2021, 2022 and 2023. All changes in the

fair value are recognized as a gain or loss in earnings in the period they occur in derivative fair value income or loss in our consolidated statements of operations. For first six months 2021, this fair value has increased $21.4 million.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019~~2020 is summarized below. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. The tables below provide additional information relating to our master netting arrangements with our derivative counterparties (in thousands):

September 30, 2020


Gross
Amounts of
Recognized
Assets


Gross
Amounts
Offset in the
Balance Sheet


Net Amounts
of Assets Presented
in the
Balance Sheet

Derivative assets:







Natural gas
–swaps

$
10,083


$
(9,159
)

$
924

–three-way collars

680

(680
)

0

–basis swaps

6,620

(3,263
)

3,357

Crude oil
–swaps

14,065

(13,566
)

499

NGLs
–C3 propane spread swaps

2,974

(2,974
)

0

–C3 propane swaps

101

0

101

–NC4 normal butane swaps

17

(17
)

0

−C5 natural gasoline swaps

25

0

25

Freight
−swaps

19

(19
)

0

Divestiture contingent consideration

15,420

0

15,420


$
50,004


$
(29,678
)

$
20,326


		June 30, 2021
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	7,453	$	(7,856	)	$	(403	)
	–collars		114		(114	)		0
	–three-way collars		12		(12	)		0
	–basis swaps		28,810		(15,453	)		13,357
Crude oil	–swaps		33		(472	)		(439	)
NGLs	–C3 propane spread swaps		6,807		(6,807	)		0
	–C3 propane collars		0		(219	)		(219	)
	–NC4 butane collars		0		(944	)		(944	)
	−C5 natural gasoline swaps		0		(439	)		(439	)
	−C5 natural gasoline collars		0		(962	)		(962	)
Freight	−swaps		57		(10	)		47
Divestiture contingent consideration			37,350		0			37,350
		$	80,636	$	(33,288	)	$	47,348


		June 30, 2021
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(122,709	)	$	7,856	$	(114,853	)
	–swaptions		(22,135	)		0		(22,135	)
	–collars		(31,242	)		114		(31,128	)
	–three-way collars		(62,594	)		12		(62,582	)
	–basis swaps		(3,123	)		15,453		12,330
Crude oil	–swaps		(28,323	)		472		(27,851	)
	–swaptions		(4,279	)		0		(4,279	)
NGLs	–C3 propane spread swaps		(6,431	)		6,807		376
	–C3 propane swaps		(8,490	)		0		(8,490	)
	–C3 collars		(1,092	)		219		(873	)
	–NC4 butane swaps		(2,744	)		0		(2,744	)
	–NC4 butane collars		(3,413	)		944		(2,469	)
	–C5 natural gasoline swaps		(7,028	)		439		(6,589	)
	–C5 natural gasoline collars		(1,309	)		962		(347	)
Freight	–swaps		(20	)		10		(10	)
		$	(304,932	)	$	33,288	$	(271,644	)


		December 31, 2020
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	33,559	$	(16,821	)	$	16,738
	–collars		7,016		(2,329	)		4,687
	–three-way collars		535		(6,139	)		(5,604	)
	–basis swaps		7,894		(3,502	)		4,392
Crude oil	–swaps		2,465		(829	)		1,636
NGLs	–C3 propane spread swaps		4,863		(4,863	)		0
	–C3 propane collars		0		(107	)		(107	)
Freight	–swaps		2,310		0			2,310
Divestiture contingent consideration			15,960		0			15,960
		$	74,602	$	(34,590	)	$	40,012


		December 31, 2020
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(10,120	)	$	16,821	$	6,701
	–swaptions		(9,803	)		0		(9,803	)
	–collars		0			2,329		2,329
	–three-way collars		(18,353	)		6,139		(12,214	)
	–basis swaps		(4,197	)		3,502		(695	)
Crude oil	–swaps		(5,471	)		829		(4,642	)
NGLs	–C3 propane spread swaps		(4,069	)		4,863		794
	–C3 propane swaps		(8,243	)		0		(8,243	)
	–C3 propane collars		(3,086	)		107		(2,979	)
	–C5 natural gasoline swaps		(4,897	)		0		(4,897	)
	–C5 natural gasoline calls		(546	)		0		(546	)
	–NC4 butane swaps		(651	)		0		(651	)
	–NC4 butane collars		(401	)		0		(401	)
Freight	–swaps		(1,206	)		0		(1,206	)
		$	(71,043	)	$	34,590	$	(36,453	)

September 30, 2020


Gross
Amounts of
Recognized
(Liabilities)


Gross
Amounts
Offset in the
Balance Sheet

Net Amounts
of (Liabilities) Presented in the
Balance Sheet

Derivative (liabilities):





Natural gas
–swaps

$
(33,359
)

$
9,159

$
(24,200
)

–swaptions

(20,368
)

0

(20,368
)

–collars

(14,169
)

0

(14,169
)

–three-way collars

(40,563
)

680

(39,883
)

–basis swaps

(1,220
)

3,263

2,043

Crude oil
–swaps

0

13,566

13,566

NGLs
–C3 propane spread swaps

(3,503
)

2,974

(529
)

–NC4 normal butane calls

0

17

17

Freight
–swaps

(1,407
)

19

(1,388
)

$
(114,589
)

$
29,678

$
(84,911
)

December 31, 2019


Gross
Amounts of
Recognized
Assets


Gross Amounts
Offset in the Balance Sheet


Net Amounts of
Assets Presented in the
Balance Sheet

Derivative assets:







Natural gas
–swaps

$
134,364


$
(2,913
)

$
131,451

–swaptions

0

(1,325
)

(1,325
)

–basis swaps

10,766

(1,092
)

9,674

Crude oil
–swaps

3,893

(4,794
)

(901
)

–swaptions

0

(1,597
)

(1,597
)

–calls

0

(349
)

(349
)
NGLs
–C3 propane spread swaps

1,913

(1,913
)

0

–NC4 normal butane swaps


167

0



167

–C5 natural gasoline swaps

60

(127
)

(67
)
Freight
–swaps

1,529

(1,028
)

501


$
152,692


$
(15,138
)

$
137,554

December 31, 2019


Gross
Amounts of
Recognized (Liabilities)


Gross Amounts
Offset in the
Balance Sheet

Net Amounts of
(Liabilities) Presented in the
Balance Sheet

Derivative (liabilities):





Natural gas
–swaps

$
(1,657
)

$
2,913

$
1,256

–swaptions

(2,594
)

1,325

(1,269
)

–basis swaps

(1,371
)

1,092

(279
)
Crude oil
–swaps

(4,814
)

4,794

(20
)

–swaptions

(2,254
)

1,597

(657
)

–calls

(349
)

349

0

NGLs
–C3 propane spread swaps

(16,040
)

1,913

(14,127
)

–C5 natural gasoline swaps

(127
)

127

0

Freight
–swaps

0

1,028

1,028

$
(29,206
)

$
15,138

$
(14,068
)

The effects of our derivatives on our consolidated statements of operations are summarized below (in thousands):

Derivative Fair Value (Loss) Income

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

2020

2019

Commodity swaps
$
(91,425
)

$
60,090

$
142,413

$
161,799

Swaptions

(14,166
)

10,358

(15,520
)

39,451

Three-way collars

(20,705
)

—

(38,267
)

0

Collars

(16,893
)

356

(14,336
)

(3,590
)
Calls

(255
)

(224
)

(12
)

(224
)
Basis swaps

15,587

3,448

31,750

7,801

Freight swaps

2,737

648

(4,276
)

2,953

Divestiture contingent consideration

430

—

430

—

Total
$
(124,690
)

$
74,676

$
102,182

$
208,190


	Derivative Fair Value (Loss) Income
	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Commodity swaps	$	(172,566	)	$	5,484		$	(225,330	)	$	233,838
Swaptions		(19,268	)		(2,019	)		(16,612	)		(1,353	)
Three-way collars		(53,705	)		(6,200	)		(52,832	)		(17,562	)
Collars		(38,934	)		2,557			(52,222	)		2,557
Calls		0			(33	)		(775	)		242
Basis swaps		17,368			(5,180	)		19,523			16,163
Freight swaps		(38	)		(912	)		(704	)		(7,013	)
Divestiture contingent consideration		17,460			0			21,390			0
Total	$	(249,683	)	$	(6,303	)	$	(307,562	)	$	226,872

1816

(12) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:



Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.



Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.



Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

•

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Significant uses of fair value measurements include:



impairment assessments of long-lived assets; and



recorded value of derivative instruments and trading securities.

•

~~impairment assessments of long-lived assets;~~

•

~~recorded value of derivative instruments and trading securities; and~~

•

~~our divestiture contract obligation.~~

The need to test long-lived assets can be based on several indicators, including a significant reduction in prices of natural gas, oil and condensate, NGLs, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which a property is located.

1917

Fair Values – Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. The following tables present the fair value hierarchy for assets and liabilities measured at fair value, on a recurring basis (in thousands):

Fair Value Measurements at September 30, 2020 using:

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total
Carrying
Value as of
September 30,
2020

Trading securities held in the deferred compensation plans
$
56,859

$
0

$
0

$
56,859

Commodity price derivatives –swaps

0

(9,068
)

0

(9,068
)
                                               –collars

0

(14,169
)

0

(14,169
)
                                               –three-way collars

0

(39,883
)

0

(39,883
)
                                               –basis swaps

0

4,871

0

4,871

                                               –swaptions

0

0

(20,368
)

(20,368
)
Derivatives–freight swaps

0

(1,388
)

0

(1,388
)
Divestiture contingent consideration

0

15,420

0

15,420


		Fair Value Measurements at June 30, 2021 using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Carrying Value as of June 30, 2021
Trading securities held in the deferred compensation plans		$	66,804	$	0		$	0		$	66,804

Commodity price derivatives	–swaps		0		(161,808	)		0			(161,808	)
	–collars		0		(31,128	)		(5,814	)		(36,942	)
	–three-way collars		0		(62,582	)		0			(62,582	)
	–basis swaps		0		26,063			0			26,063
	–swaptions		0		0			(26,414	)		(26,414	)
Derivatives–freight swaps			0		37			0			37
Divestiture contingent consideration			0		37,350			0			37,350


		Fair Value Measurements at December 31, 2020 using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Carrying Value as of December 31, 2020
Trading securities held in the deferred compensation plans		$	63,942	$	0		$	0		$	63,942

Commodity price derivatives	–swaps		0		6,642			0			6,642
	–calls		0		0			(546	)		(546	)
	–collars		0		7,016			(3,487	)		3,529
	–three-way collars		0		(17,818	)		0			(17,818	)
	–basis swaps		0		4,491			0			4,491
	–swaptions		0		0			(9,803	)		(9,803	)
Derivatives–freight swaps			0		1,104			0			1,104
Divesture contingent consideration			0		15,960			0			15,960

Fair Value Measurements at December 31, 2019 using:

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)


Significant
Other
Observable
Inputs
(Level 2)


Significant
Unobservable
Inputs
(Level 3)


Total
Carrying
Value as of
December 31,
2019

Trading securities held in the deferred compensation plans
$
62,009


$
0


$
0


$
62,009

Commodity price derivatives –swaps

0



131,886



0



131,886

                                               –calls

0

(349
)

0

(349
)
                                               –basis swaps

0

(4,732
)

0

(4,732
)
                              ��                –swaptions

0

0

(4,848
)

(4,848
)
Derivatives–freight swaps

0

1,529

0

1,529

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using end of period market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. As of ~~September~~June 30, ~~2020,~~2021, a portion of our natural gas and oil derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a pre-determined date. In addition to our swaptions in Level 3 at June 30, 2021, we have NGLs collars. Derivatives in Level 3 are also measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. ~~Subjectivity~~However, the subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our ~~swaptions.~~derivatives in Level 3 and is considered a significant unobservable input. For our swaptions, we used a weighted average implied volatility of 23% for natural gas and 31% for crude oil. We ~~utilize~~also utilized a range of implied volatilities from ~~21%~~29% to ~~32%~~50% for our NGLs collars with a weighted average implied volatility of ~~26%~~36%. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

As of
September 30,
2020

Balance at December 31, 2019

$
(4,848
)
Total losses:

Included in earnings

(19,124
)
Settlements, net

2,769

Transfers in and/or out of Level 3

835

Balance at September 30, 2020

$
(20,368
)


	As of June 30, 2021
Balance at December 31, 2020	$	(13,836	)
Total losses:
Included in earnings		(7,627	)
Additions		(20,515	)
Settlements		5,176
Transfers out of Level 3		4,574
Balance at June 30, 2021	$	(32,228	)

Divestiture Contingent Consideration. In August 2020, we completed the sale of our North Louisiana assets where we are entitled to receive contingent consideration ~~of up to $90 million,~~ based on future achievement of natural gas and oil prices based on published indexes along with NGLs prices based on the realized NGLs prices of the buyer. We used an option pricing model to estimate the fair value of the contingent consideration using significant Level 2 inputs that include quoted future commodity prices based on active ~~markets and implied volatility factors. See also Note 4 and Note 11 for additional information.~~markets.

Trading securities.Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations. For ~~third~~second quarter ~~2020,~~2021, interest and dividends were ~~$114,000~~$118,000 and the mark-to-market adjustment was a gain of ~~$3.2~~$2.3 million compared to interest and dividends of ~~$197,000~~$124,000 and a mark-to-market ~~loss~~gain of ~~$361,000~~$7.6 million in ~~third~~second quarter ~~2019.~~2020. For first ~~nine~~six months ~~2020~~2021, interest and dividends were ~~$385,000~~$227,000 and the mark-to-market adjustment was a gain of ~~$234,000~~$4.3 million compared to interest and dividends of ~~$560,000~~$227,000 and a mark-to-market adjustment of a ~~gain~~loss of ~~$6.3~~$3.0 million in ~~the same period of 2019.~~first six months 2020.

Fair Values – Non-recurring

Certain assets are measured at fair value on a non-recurring basis. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. As a result of such a proved property review in fourth quarter 2019, we recorded noncash impairment charges to reduce the carrying value of our North Louisiana assets. We calculated the fair value of these assets using a discounted cash flow model which uses Level 3 inputs. There were 0 proved property impairment charges in first nine months 2019. The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands):

Year Ended December 31, 2019

Fair Value

Impairment

North Louisiana

$  370,500

$  1,093,531

In first quarter 2020, we recognized ~~additional~~ impairment charges of ~~$77.0~~$77.0 million that reduced the carrying value to the anticipated sales proceeds for our North Louisiana assets which is a market approach using Level 2 inputs. ~~See also Note 4 and Note 14 for additional information.~~

~~North Louisiana Divestiture.~~ ~~We have recorded a divestiture contract obligation~~These assets were sold in conjunction with the sale of our North Louisiana assets. The fair value of this obligation was determined as of the closing date using Level 3 inputs based on a probability-weighted forecast that considers historical results, market conditions and various potential development plans of the buyer to arrive at the estimated present value of the future payments. The present value of the future cash payments was determined using a 12 percent discount rate. See also Note 4 and Note 14 for additional information.third quarter 2020. There were

~~Leases.~~ As part of our ongoing effort to reduce general and administrative expense due to both the lower commodity price environment and in conjunction with the sale of our North Louisiana assets, we have vacated one floor in our Fort Worth headquarters. We have recorded an impairment related to this lease of $2.0 million which is included in impairment of0 proved property ~~and other assets~~impairment charges in ~~our consolidated statements of operations for third~~second quarter ~~2020.~~or first six months 2021.

Fair Values – Reported

The following presents the carrying amounts and the fair values of our financial instruments as of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019~~2020 (in thousands):

September 30, 2020

December 31, 2019

Carrying
Value

Fair
Value

Carrying
Value

Fair
Value

Assets:

Commodity swaps, collars and basis swaps

$
4,906

$
4,906

$
137,554

$
137,554

Divestiture contingent consideration

15,420

15,420

0

0

Marketable securities ^(a)

56,859

56,859

62,009

62,009

(Liabilities):

Commodity swaps, collars and basis swaps

(84,911
)

(84,911
)

(14,068
)

(14,068
)
Bank credit facility ^(b)

(706,000
)

(706,000
)

(477,000
)

(477,000
)
5.75% senior notes due 2021 ^(b)

(25,496
)

(25,592
)

(374,139
)

(375,909
)
5.00% senior notes due 2022 ^(b)

(169,589
)

(163,558
)

(511,886
)

(501,582
)
5.875% senior notes due 2022 ^(b)

(48,528
)

(47,819
)

(297,617
)

(294,757
)
Other senior notes due 2022 ^(b)

(490
)

(482
)

(590
)

(592
)
5.00% senior notes due 2023 ^(b)

(532,335
)

(505,787
)

(741,531
)

(683,291
)
4.875% senior notes due 2025 ^(b)

(750,000
)

(676,425
)

(750,000
)

(645,098
)
9.25% senior notes due 2026 ^(b)

(850,000
)

(873,103
)

0

0

5.75% senior subordinated notes due 2021 ^(b)

(19,896
)

(19,477
)

(22,214
)

(21,539
)
5.00% senior subordinated notes due 2022 ^(b)

(9,730
)

(8,666
)

(19,054
)

(17,011
)
5.00% senior subordinated notes due 2023 ^(b)

(7,712
)

(7,127
)

(7,712
)

(7,654
)
Deferred compensation plan ^(c)

(84,538
)

(84,538
)

(74,472
)

(74,472
)


	June 30, 2021						December 31, 2020
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and basis swaps	$	9,998		$	9,998		$	24,052		$	24,052
Divestiture contingent consideration		37,350			37,350			15,960			15,960
Marketable securities (a)		66,804			66,804			63,942			63,942
(Liabilities):
Commodity swaps, collars and basis swaps		(271,644	)		(271,644	)		(36,453	)		(36,453	)
Bank credit facility (b)		(121,000	)		(121,000	)		(702,000	)		(702,000	)
5.75% senior notes due 2021 (b)		0			0			(25,496	)		(25,474	)
5.00% senior notes due 2022 (b)		(169,589	)		(173,691	)		(169,589	)		(170,128	)
5.875% senior notes due 2022 (b)		(48,528	)		(49,676	)		(48,528	)		(48,471	)
Other senior notes due 2022 (b)		0			0			(490	)		(490	)
5.00% senior notes due 2023 (b)		(532,335	)		(553,879	)		(532,335	)		(521,699	)
4.875% senior notes due 2025 (b)		(750,000	)		(778,718	)		(750,000	)		(707,918	)
9.25% senior notes due 2026 (b)		(850,000	)		(937,423	)		(850,000	)		(888,208	)
8.25% senior notes due 2029 (b)		(600,000	)		(676,512	)		0			0
5.75% senior subordinated notes due 2021 (b)		0			0			(19,896	)		(19,589	)
5.00% senior subordinated notes due 2022 (b)		0			0			(9,730	)		(9,247	)
5.00% senior subordinated notes due 2023 (b)		0			0			(7,712	)		(6,604	)
Deferred compensation plan (c)		(148,205	)		(148,205	)		(96,563	)		(96,563	)

(a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.

(b) The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.

(c) The fair value of our deferred compensation plan is updated to the closing price on the balance sheet date which is a Level 1 input.

^(a)

~~Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.~~

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.

^(c)	~~The fair value of our deferred compensation plan is updated to the closing price on the balance sheet date which is a Level 1 input.~~

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivable and payable. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical and expected incurrence of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations, operating lease liabilities and the divestiture contract ~~obligation.~~ obligation that we incurred in conjunction with the sale of our North Louisiana assets.

Concentrations of Credit Risk

As of ~~September~~June 30, ~~2020,~~2021, our primary concentrations of credit risk are the risks of not collecting accounts receivable and the risk of a counterparty’s failure to perform under derivative obligations. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate ~~securities~~assurances are obtained as deemed necessary to limit our risk of loss. Our allowance for uncollectable receivables was ~~$3.0 million~~$393,000 at ~~September~~June 30, ~~2020 and $8.8~~2021 compared to $3.0 million at December 31, ~~2019.~~2020. Our derivative exposure to credit risk is diversified primarily among major investment grade financial institutions, where we have master netting agreements which provide for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. At ~~September~~June 30, ~~2020,~~2021, our derivative counterparties include ~~NaN~~19 financial institutions, of which all but ~~five~~5 are secured lenders in our bank credit facility. At ~~September~~June 30, ~~2020,~~2021, our net derivative asset includes a net ~~payable~~receivable of ~~$2.2~~$9.7 million ~~to 2~~from four of these counterparties that are not participants in our bank credit facility and aan aggregate net ~~receivable~~payable of ~~$3.3~~$5.6 million ~~from three~~to one of these counterparties.

Allowance for Expected Credit Losses. Each reporting period, we assess the recoverability of material receivables using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. The loss given default method is used when, based on management’s judgment, an allowance for expected credit losses should be accrued on a material receivable to reflect the net amount to be collected. ~~See Note 3 for a discussion on adoption of the new accounting standards update on financial instruments-credit losses.~~

2220

(13) STOCK-BASED COMPENSATION PLANS

Stock-Based Awards

We have 2 active equity-based stock ~~plans;~~plans: our Amended and Restated 2005 Equity-Based Incentive Compensation Plan ~~which we refer to as the 2005 Plan~~ and ~~the~~our Amended and Restated 2019 Equity-Based Compensation ~~Plan, which was approved by our stockholders in May 2019 and amended in May 2020.~~Plan. Under these plans, various awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is composed of only non-employee, independent directors.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock and performance units. Unlike the other forms of stock-based compensation, the mark-to-market adjustment of the liability related to the vested restricted stock held in our deferred compensation plan is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. The following details the allocation of stock-based compensation to functional expense categories (in thousands):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

2020

2019

Direct operating expense
$
(74
)

$
319

$
810

$
1,459

Brokered natural gas and marketing expense

324

522

905

1,523

Exploration expense

189

496

891

1,372

General and administrative expense

6,863

8,423

24,071

27,561

Termination costs

2,020

(1
)

2,020

25

Total stock-based compensation
$
9,322

$
9,759

$
28,697

$
31,940


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Direct operating expense	$	340	$	434	$	667	$	884
Brokered natural gas and marketing expense		443		168		893		581
Exploration expense		362		372		748		702
General and administrative expense		9,382		9,179		18,787		17,208
Total stock-based compensation expense	$	10,527	$	10,153	$	21,095	$	19,375

Stock-Based Awards

Restricted Stock Awards. We grant restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, generally vest over a three-year period, contingent on the recipient’s continued employment. The grant date fair value of the Equity Awards is based on the fair market value of our common stock on the date of grant.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. We also grant restricted stock to certain employees for retention purposes. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and ~~immediate~~one year vesting for non-employee directors. ~~In May 2020, vesting for non-employee directors was changed to one year after grant date.~~ All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock award recipients have the right to vote such stock and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are generally placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. In early 2021, vesting for new grants of restricted stock Liability Awards changed to a three-year cliff vesting from a ratable 30%-30%-40% vesting schedule. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we can also utilize treasury shares when available.

Stock-Based Performance Units. We grant 3 types of performance share awards: 2 based on internal performance conditions which were initially measured against internal debt-adjusted performance metrics (Production Per Share Awards or ~~“PS-PSUs”~~PS-PSUs and ~~Reserve~~Reserves Per Share Awards or ~~“RS-PSUs”)~~RS-PSUs) and 1 based on market conditions measured based on Range’s performance relative to a predetermined peer group ~~(“TSR Awards”~~(TSR Awards or ~~“TSR-PSUs”)~~TSR-PSUs).In first quarter 2021, our internal performance metrics were changed to focus on debt reduction and to include an environmental component. For shares granted in first quarter 2021, the performance conditions will be measured against internal metrics of Debt/EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration expense) and emission intensity performance. These shares will vest at the end of three years and the three-year performance target was set in first quarter 2021.

Each unit granted represents 1 share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can berange from 0 to ~~200%~~200% based on performance achieved, which is determined by the Compensation Committee and (2) the value of our common stock on the vesting ~~date which is determined by the Compensation Committee.~~date. Dividend equivalents may accrue during the performance period and are paid in stock at the end of the performance period. The performance period for the TSR-PSUs is three ~~years. The~~years. Prior to 2021, the performance period for the PS/RS-PSUs iswas based on annual performance targets earned over a three-year period.

2321

Restricted Stock – Equity Awards

In first ~~nine~~six months ~~2020,~~2021, we granted ~~4.5~~2.3 million restricted stock Equity Awards to employees at an average grant date fair value of ~~$3.42~~$10.20 which generally vest over a three-year period compared to ~~2.8~~4.5 million at an average grant date fair value of ~~$10.59~~$3.42 in first ~~nine~~six months ~~2019.~~2020. We recorded compensation expense for these outstanding awards of ~~$13.4~~$10.3 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$18.9~~$10.0 million in the same period of ~~2019.~~2020. Restricted stock Equity Awards are not issued to employees until such time as they are ~~vested and the employees~~vested. Employees do not have the option to receive cash.

Restricted Stock – Liability Awards

In first ~~nine~~six months ~~2020,~~2021, we granted ~~3.3~~1.2 million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of ~~$3.03~~$9.30 which generally vest ~~over~~at the end of a three-year period and ~~217,000~~97,000 shares were granted to non-employee directors at an average price of ~~$5.38~~$11.99 with vesting ~~over one year.~~at the end of a one-year period. In first ~~nine~~six months ~~2019,~~2020, we granted ~~1.0~~3.3 million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of ~~$10.39~~$3.03 with vesting generally over a three-year period and ~~183,000 shares~~217,000 were granted to non-employee directors at an average price of ~~$9.11~~$5.38 with ~~immediate vesting.~~vesting at the end of a one-year period. We recorded compensation expense for these Liability Awards of ~~$7.9~~ $5.7million in first ~~nine~~six months ~~2020~~2021 compared to ~~$7.0~~$5.4 million in first ~~nine~~six months ~~2019.~~2020. The majority of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The following is a summary of the status of our non-vested restricted stock outstanding at ~~September~~June 30, ~~2020:~~2021:


	Restricted Stock Equity Awards					Restricted Stock Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2020		2,815,860		$	4.97		1,186,636		$	4.18
Granted		2,340,114			10.20		1,283,039			9.50
Vested		(1,217,427	)		7.45		(941,832	)		6.52
Forfeited		(60,377	)		6.22		0			0
Outstanding at June 30, 2021		3,878,170		$	7.33		1,527,843		$	7.20

Restricted Stock
Equity Awards


Restricted Stock
Liability Awards

Shares

Weighted
Average Grant
Date Fair Value


Shares

Weighted
Average Grant
Date Fair Value

Outstanding at December 31, 2019

2,002,239

$
12.32



411,126

$
10.94

Granted

4,462,711

3.42



3,529,686

3.18

Vested

(1,788,235
)

7.08



(2,003,051
)

4.03

Forfeited

(431,201
)

8.47



(81,570
)

3.02

Outstanding at September 30, 2020

4,245,514

$
5.56



1,856,191

$
3.98

Stock-Based Performance Units

~~Production Per Share and Reserve Per Share Awards (debt-adjusted).~~Internal Performance Metric Awards. These awards ~~The PS-PSUs and RS-PSUs~~ vest at the end of the three-year performance period. The performance metrics ~~for each year~~ are set by the Compensation ~~Committee no later than March 31 of such year.~~Committee. If the performance metric for the applicable period is not met, that portion is considered forfeited and there is an adjustment to the expense recorded. See additional information above for shares granted in first quarter 2021. The following is a summary of our non-vested ~~PS/RS-PSUs~~internal performance awards outstanding at ~~September~~June 30, ~~2020:~~2021:


	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2020		1,099,102		$	5.92
Units granted (a)		303,231			9.81
Vested and issued (b)		(306,978	)		12.20
Forfeited		0			0
Outstanding at June 30, 2021		1,095,355		$	7.80

(a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between 0 and 200% depending on achievement of specifically identified performance targets. Units granted in first quarter 2021 were to our CEO, CFO and COO only.

Number of
Units

Weighted
Average Grant Date Fair Value

Outstanding at December 31, 2019

881,573

$
11.70

Units granted ^(a)

777,847

2.33

Vested ^(b)

(101,150
)

15.32

Forfeited ^(c)

(259,711
)

2.33

Outstanding at September 30, 2020

1,298,559

$
5.37

(b) For certain of the PS-PSUs and RS-PSUs awards issued during 2018 the aggregate payout was approximately 137% of target for the March 2018 grants with a positive performance adjustment of 290,140 shares.

^(a)

Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between 0 and 200% depending on achievement of specifically identified performance targets.

^(b)	For the PS-PSUs and RS-PSUs awards issued during 2017 the aggregate payout was approximately 150% of target for the March 2017 and May 2017 grants with a positive performance adjustment of 58,591 shares.

^(c)	~~For PS-PSU’s tranches granted in 2018, 2019 and 2020 which were set to vest in 2021 and the performance metric is not expected to be met.~~

We recorded ~~PS/RS-PSUs~~ compensation ~~income~~expense of ~~$2.3~~$1.8 million in first ~~nine~~six months ~~2020~~2021 compared to expense of ~~$2.3~~$1.8 millionin first ~~nine~~six months ~~2019.~~2020.

TSR Awards. TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair

value of the award. The fair value is recognized as stock-based compensation expense over the three-year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of TSR-PSUs granted during first ~~nine~~six months ~~2020~~2021 and ~~2019:~~2020:

Nine Months
Ended
September 30,

2020

2019

Risk-free interest rate

1.4
%

2.4
%

Expected annual volatility

65
%

46
%

Grant date fair value per unit

$
3.85

$
11.34


	Six Months Ended June 30,
	2021			2020
Risk-free interest rate		0.2	%		1.4	%
Expected annual volatility		75	%		65	%
Grant date fair value per unit	$	12.58		$	3.85

The following is a summary of our non-vested ~~TSR~~ – ~~PSUs~~TSR-PSUs award activities:

Number of
Units

Weighted
Average
Grant Date
Fair Value

Outstanding at December 31, 2019

993,452

$
19.00

Units granted ^(a)

610,155

3.85

Vested ^(b)

(278,184
)

26.12

Forfeited

(75,899
)

26.66

Outstanding at September 30, 2020

1,249,524

$
9.55


	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2020		1,249,524		$	9.55
Units granted (a)		223,687			12.58
Vested and issued (b)		(325,217	)		18.51
Forfeited		0			0
Outstanding at June 30, 2021		1,147,994		$	7.60

(a ) These amounts reflect the number of performance units granted. The actual payout of shares may be between 0 and 200% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

(b) Includes TSR-PSUs awards issued related to the 2018 performance period where the return on our common stock was was negative and therefore, the performance multiple and actual payout was reduced to 100%.

^(a)	~~These~~ amounts reflect the number of performance units granted. The actual payout of shares may be between 0 and 200% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

^(b)	~~Includes TSR-PSUs awards issued related to the 2017 performance period where the return on our common stock was in the 60~~^th ~~percentile for the March 2017 grant and the 80~~^th ~~percentile for the May 2017 grant. The remaining 2017 awards are considered to be forfeited.~~

We recorded TSR-PSUs compensation expense of ~~$1.9~~$1.2 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$2.2~~$1.5 million in the same period of ~~2019.~~2020. Fair value is amortized over the performance period with no adjustment to the expense recorded for actual targets achieved.

Other Post Retirement Benefits

Effective fourth quarter 2017, as part of our officer succession plan, we implemented a post retirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. These benefits are not funded in advance and are provided up to age 65 or at the date they become eligible for Medicare, subject to various cost-sharing features. There was approximately ~~$90,000~~$90,000 of estimated prior service costs amortized from accumulated other comprehensive income into general and administrative expense in both the three months ended ~~September~~June 30, 2021 and 2020 and ~~2019 and~~ approximately ~~$275,000~~$185,000 amortized in both the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019.~~2020. Those employees that ~~qualified~~qualify for this ~~new~~ retirement health care ~~plan were also fully vested in all equity grants. Effective October 2018, officers who qualify for the~~ plan are required to provide reasonable notice of retirement and ~~beginning in 2019 must~~ provide one year of service after ~~the~~an equity grant date to be fully vested in ~~an equity~~the grant.

Deferred Compensation Plan

Our deferred compensation plan gives non-employee directors and officers the ability to defer all or a portion of their salaries, bonuses or director fees and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution to officers which vests over three ~~years.~~years. In early 2021, vesting for the matching contribution was changed to a three-year cliff vesting schedule. The assets of the plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our general creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected as deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our

consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value as other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred

compensation plan expense each quarter. We recorded a mark-to-market loss of ~~$6.2~~$35.5 million in ~~third~~second quarter ~~2020~~2021 compared to a mark-to-market ~~gain~~loss of ~~$8.9~~$12.6 million in ~~third~~second quarter ~~2019.~~2020. We recorded a mark-to-market loss of ~~$10.3~~$55.3 million in first ~~nine~~six months ~~2020~~2021 compared to a ~~mark-to-market gain~~loss of ~~$16.4~~$4.1 million in first ~~nine~~six months ~~2019.~~2020. The Rabbi Trust held ~~6.1~~6.5 million shares ~~(4.4~~(5.0 million of which were vested) of Range stock at ~~September~~June 30, ~~2020~~2021 compared to ~~3.2~~6.1 million shares (~~2.7~~5.0 million of which were vested) at December 31, ~~2019.~~2020.

(14) EXIT AND TERMINATION COSTS

Exit Costs

In August 2020, we sold our North Louisiana assets and retained certain gathering, transportation and processing obligations which extend into 2030. These are contracts where we will not realize any future benefit. The estimated obligations are included in current and long-term divestiture contract obligation in our consolidated balance ~~sheet. The present value~~sheets. In first six months 2021, we recorded accretion expense of ~~our estimated obligations was~~$25.0 million. In second quarter 2021, we recorded ~~as an exit cost which totaled $479.8 million. Also associated with this sale, we agreed to pay~~ a ~~midstream company $28.5~~net favorable adjustment of $28.2 million to reduce this obligation due to a reduction of certain contractual payments compared to those originally estimated and a change to our ~~financial~~estimated drilling plans of the buyer. The estimated discounted divestiture contract obligation ~~related to the minimum volume commitments associated with this asset which~~ was ~~also recorded as an exit cost in third quarter 2020.~~$436.1 million at June 30, 2021.

In second quarter 2020, we negotiated capacity releases on certain transportation pipelines in Pennsylvania effective May31, 2020 and extending through the remainder of the contract. ~~As a result of these releases, we~~We recorded ~~exit~~termination costs of ~~$10.4~~$10.4 million which ~~represents~~represented the discounted present value of our remaining ~~obligations~~obligation to the ~~third party.~~third-party. The estimated remaining discounted obligation for these transportation capacity releases as of June 30, 2021 was $8.4 million.

Termination Costs

In third quarter 2020, we completed the sale of our North Louisiana assets. We recorded $2.5 million of severance costs and stock-based compensation expense associated with this sale. In third quarter 2020, we also announced an additional reduction in our work force as we continue to focus on lowering administrative expenses and recorded $3.7 million of severance costs and stock-based compensation expense related to this reduction in force. In first quarter 2020, we completed the sale of our shallow legacy assets in ~~Northwest~~northwestern Pennsylvania and we recorded ~~$1.6~~$1.6 million of severance costs ~~in first quarter 2020~~ which is primarily related to the sale of these assets. In third quarter 2019, we sold various non-core assets in Pennsylvania and accrued $819,000 of severance costs related to this sale. In second quarter 2019, we announced another reduction in our work force and recorded $2.2 million of severance costs related to this work force reduction. The following summarizes our exit and termination costs for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

2020

2019

Severance costs
$
4,191

$
819

$
5,638

$
3,000

Transportation contract capacity releases (including accretion of
   discount)

233

0

10,678

0

Divestiture contract obligation (including accretion of discount)

486,689

0

486,689

0

One-time minimum volume commitment contract payment

28,500

0

28,500

0

Stock-based compensation

2,020

0

2,020

25

$
521,633

$
819

$
533,525

$
3,025


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Severance costs	$	0		$	(148	)	$	509		$	1,447
Transportation contract capacity releases (including accretion of discount)		184			10,445			394			10,445
Divestiture contract obligation (including accretion of discount)		(16,130	)		0			(3,135	)		0
	$	(15,946	)	$	10,297		$	(2,232	)	$	11,892

The following details the accrued exit and termination cost liability activity for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 (in thousands):

Exit
Costs

Termination
Costs

Balance at December 31, 2019
$
0

$
4,692

Accrued severance costs

0

5,638

Accrued contract obligations

490,115

0

Accretion of discount

7,252

0

Payments

(959
)

(6,170
)

Balance at September 30, 2020
$
496,408

$
4,160


	Exit Costs (1)			Termination Costs
Balance at December 31, 2020	$	493,543		$	1,454
Accrued severance costs		0			509
Accretion of discount		25,424			0
Divestiture contract obligation - changes in estimate		(28,165	)		0
Payments		(46,321	)		(1,594	)
Balance at June 30, 2021	$	444,481		$	369

(1) Includes the divestiture contract obligation and the transportation contract capacity release obligation.

2624

(15) CAPITAL STOCK

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. We currently have 0 preferred stock issued or outstanding. The following is a schedule of changes in the number of common shares outstanding since the beginning of ~~2019:~~2020:


	Six Months Ended June 30, 2021		Year Ended December 31, 2020
Beginning balance		246,348,092		249,630,803
Restricted stock grants		1,286,737		3,390,358
Restricted stock units vested		1,483,436		1,226,473
Performance stock units issued		640,468		279,420
Performance stock dividends		13,966		18,700
Treasury shares		1,112		(8,197,662	)
Ending balance		249,773,811		246,348,092

Nine Months
Ended
September 30,
2020

Year
Ended
December 31,
2019

Beginning balance

249,630,803

249,510,022

Restricted stock grants

3,390,358

1,186,290

Restricted stock units vested

1,104,596

720,212

Performance stock units issued

279,420

12,747

Performance stock dividends

18,700

0

Treasury shares acquired

(8,197,662
)

(1,798,468
)
Ending balance

246,226,215

249,630,803

Stock Repurchase Program

In October 2019, our Board of Directors authorized a ~~$100.0~~$100.0 million common stock repurchase program. Under this program, we may repurchase shares in open market transactions, from time to time, in accordance with applicable SEC rules and federal securities laws. The following is a schedule of the change in treasury shares for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020:~~2021:

Three Months
Ended
September 30,
2020

Nine Months
Ended
September 30,
2020

Beginning balance

10,007,327

1,808,133

Rabbi trust shares distributed/sold

(1,532
)

(2,338
)
Shares repurchased

0

8,200,000

Ending balance

10,005,795

10,005,795


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
Beginning balance		10,004,683		10,005,795
Rabbi trust shares distributed/sold		0		(1,112	)
Shares repurchased		0		0
Ending balance		10,004,683		10,004,683

(16) SUPPLEMENTAL CASH FLOW INFORMATION

Nine Months
Ended
September 30,

2020

2019

(in thousands)

Net cash provided from operating activities included:

Income taxes refunded from taxing authorities

$
343

$
0

Interest paid

(145,319
)

(151,602
)
Non-cash investing and financing activities included:

Increase in asset retirement costs capitalized

4,587

812

Decrease in accrued capital expenditures

(38,942
)

(4,424
)


	Six Months Ended June 30,
	2021			2020
	(in thousands)
Net cash provided from operating activities included:
Income taxes refunded from taxing authorities	$	0		$	2,154
Interest paid		(87,337	)		(78,265	)
Non-cash investing and financing activities included:
Increase in asset retirement costs capitalized		2,098			4,247
Increase (decrease) in accrued capital expenditures		3,185			(31,307	)

(17) COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions and administrative proceedings arising in the ordinary course of our business including, but not limited to, royalty claims, contract claims and environmental claims. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these actions, proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations.

When deemed necessary, we establish reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible we could incur additional losses with respect to those matters in

which reserves have been established. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

We have incurred and will continue to incur capital, operating and remediation expenditures as a result of environmental laws and regulations. As of ~~September~~June 30, ~~2020,~~2021, liabilities for remediation were not material. We are not aware of any environmental claims existing as of ~~September~~June 30, ~~2020~~2021 that have not been provided for or would otherwise have a material impact on our financial position or results of operations. Environmental liabilities normally involve estimates that are subject to revision until final resolution, settlement or remediation occurs.

~~Obligations Following Divestitures~~

~~Certain contractual obligations were retained by us after our divestiture~~On March 4, 2021 a punitive class action lawsuit was filed in the Western District of Pennsylvania in Case No. 2:21-CV-301 (Jacobowitz v. Range Resources Corporation et al.) in which the Plaintiff seeks to represent a class of Range stockholders who purchased or acquired stock from April 29, 2016 to February 10, 2021. This lawsuit has been transferred to the U.S. District Court for the Northern District of Texas (Fort Worth Division). The lawsuit claims that Range misclassified certain wells as inactive rather than having plugged the wells and that such alleged misclassification affected the determination of our ~~North Louisiana assets. These obligations are primarily related~~asset retirement obligation accrual. The lawsuit claims that the disclosure of a $294,000 agreed penalty that we paid to ~~gathering, processing and transportation agreements including certain minimum volume commitments. For additional information see Note 4 and Note 14.~~

~~Transportation, Gathering and Processing Commitments~~

~~We have entered into firm transportation, gathering and processing commitments~~the Pennsylvania Department of Environmental Protection (DEP) in connection with ~~various pipeline carriers and midstream companies associated with our Pennsylvania production. The accrued obligations shown below is primarily~~ the ~~contractual obligations retained after the sale~~DEP’s investigation of our ~~North Louisiana assets~~application for inactive status for a small number of our wells which the DEP disclosed during market hours on February 10, 2021 was the basis for the Plaintiffs’ discovery of the alleged misrepresentations. We maintain that the factual allegations and the claims made in the litigation are baseless; there were no misrepresentations made and our asset retirement obligation was properly calculated. We also maintain that the market fully absorbed the information disclosed by the DEP on February 10, 2021 and the stock price on that day did not decrease. Given our view of the litigation as baseless, we plan to vigorously defend the litigation.

(18) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is ~~not included~~made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in ~~total commitments below.~~ natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The ~~ultimate settlement amount and timing of these accrued obligations cannot be precisely determined. As of September~~following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, ~~2020, future minimum transportation, gathering and processing fees are as follows~~2021 (in thousands):

Remainder 2020
$
212,604

2021

849,807

2022

812,176

2023

779,226

2024

763,965

Thereafter

4,817,605

Total commitments
$
8,235,383

Accrued obligations (see also Note 14)
$
496,408


	2021

Balance at beginning of period	$	7,709
Additions to capitalized exploratory well costs pending the determination of proved reserves		5,431
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(13,140	)
Capitalized exploratory well costs, charged to expense		0
Balance at end of period	$	0
Less exploratory well costs that have been capitalized for a period of one year or less	$	0
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	0

2826

~~(18)~~

(19) Costs Incurred for Property Acquisition, Exploration and Development^(a)

Nine Months
Ended
September 30,
2020

Year
Ended
December 31, 2019

(in thousands)

Acquisitions:

Acreage purchases

$
11,864

$
57,324

Development

283,354

666,984

Exploration:

Expense

22,296

35,117

Stock-based compensation expense

895

1,566

Gas gathering facilities:

Development

2,764

3,583

Subtotal

321,173

764,574

Asset retirement obligations

4,587

11,193

Total costs incurred

$
325,760

$
775,767


	Six Months Ended June 30, 2021		Year Ended December 31, 2020
	(in thousands)
Acquisitions:
Acreage purchases	$	10,142	$	26,166
Development		207,354		369,093
Exploration:
Drilling		5,432		7,709
Expense		9,818		31,376
Stock-based compensation expense		748		1,279
Gas gathering facilities:
Development		2,179		3,694
Subtotal		235,673		439,317
Asset retirement obligations		2,098		2,610
Total costs incurred	$	237,771	$	441,927

(a) Includes costs incurred whether capitalized or expensed.

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

^(a)

~~Includes costs incurred whether capitalized or expensed.~~

~~ITEM 2.~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, ~~and~~ natural gas liquids ~~(“NGLs”)~~(NGLs) and oil company primarily engaged in the exploration, development and acquisition of natural gas properties in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or an area-by-area basis.

Our overarching business objective is to build stockholder value through returns-focused development ~~measured on a per share debt adjusted basis.~~of natural gas properties. Our strategy to achieve our business objective is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core or, at times, core assets. In addition, we target funding our capital spending to at or below operating cash flow. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and NGLs and on our ability to economically find, develop, acquire, produce and market natural gas and NGLs reserves. Commodity prices have been and are expected to remain volatile. ~~We believe that we are well-positioned to manage~~Our primary near-term focus includes the ~~challenges presented in a volatile pricing environment by:~~following:



operate safely and efficiently;



target limiting capital spending at or below cash flow;



reduce direct emissions and target net zero direct emissions by 2025;



achieve competitive returns on investments;



preserve liquidity and improve financial strength;



focus on organic opportunities through disciplined capital investments;



improve operational efficiencies and economic returns;



attract and retain quality employees; and



align incentives with our stockholders’ interests and key business objectives.

•

~~exercising discipline in our capital program as we target capital spending within operating cash flows and, if required, with borrowing under our bank credit facility;~~

•

~~continuing to optimize drilling, completion and operational efficiencies;~~

•

~~continuing to focus on improving our cost structure;~~

•

~~continuing to pursue asset sales to reduce debt;~~

•

~~continuing to manage price risk by hedging our production; and~~

•

~~continuing to manage our balance sheet.~~

We prepare our financial statements in conformity with U.S. GAAP which requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas and NGLs reserves. We use the successful efforts method of accounting for our natural gas, NGLs and ~~NGLs~~oil activities.

Prices for natural gas, NGLs and oil fluctuate widely and affect:



revenues, profitability and cash flow;



the quantity of natural gas, NGLs and oil we can economically produce;



the quantity of natural gas, NGLs and oil shown as proved reserves;



the amount of cash flows available for capital expenditures; and



our ability to borrow and raise additional capital.

•

~~revenues, profitability and cash flow;~~

•

~~the quantity of natural gas, NGLs and oil we can economically produce;~~

•

~~the quantity of natural gas, NGLs and oil shown as proved reserves;~~

•

~~the amount of cash flows available for capital expenditures; and~~

•

~~our ability to borrow and raise additional capital.~~

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.

~~Impact of the COVID-19 Pandemic~~

The COVID-19 pandemic has resulted in a worldwide economic downturn and there continues to be considerable uncertainty with respect to the economic effects the pandemic will have on financial and commodity markets. One of the impacts of COVID-19 has been a significant decline in the demand for crude oil, and to a lesser extent, natural gas.

~~We have three priorities while navigating through this continuing period of volatility and uncertainty:~~

•

~~First, to ensure the health and safety of our employees and the contractors which provide services to us;~~

•

~~Second, to continue to monitor the impact this pandemic has on demand for our products and related commodity prices impacts; and~~

•

Third, to ensure Range adapts and emerges from this event in as strong of a position as possible. Our objective and focus when the pandemic comes to an end is to emerge as a better company as we continue to drive our long-term strategies.

This pandemic could affect our operations, major facilities or employees’ health; however, as of the date of this filing, we have not experienced a significant disruption to our operations and we have implemented pre-existing contingency

planning, with many employees working remotely where possible in compliance with governmental restrictions and CDC best practices. We have a crisis team in place monitoring the rapidly evolving situation and recommending risk mitigation actions; we have implemented travel restrictions as well as visitor protocols; and we are following masking and social distancing practices in our offices and other work sites. There has been no material impact on supply for most of our sourced materials and to the extent such an impact has been realized or anticipated, continuity plans have been activated. We are also working closely with our processing and pipeline transportation partners to anticipate possible impacts on our continued operations. Our efforts to respond to the challenges presented by this pandemic have helped to minimize the impact of the pandemic to our business and operations.

The impact that COVID-19 will have on our business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the ultimate geographic spread and severity of the virus, any resurgence in COVID-19 transmission and infection, the consequences of governmental and other measures designed to mitigate the spread of the virus and alleviate strain on the healthcare system, the development of effective treatments, actions taken by customers, suppliers and other third parties, workforce availability and the timing and extent to which normal economic and operating conditions resume.

Market Conditions

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently ~~volatile.~~volatile and are affected by many factors outside of our control. Natural gas and oil benchmarks ~~decreased~~increased in ~~third~~second quarter ~~2020~~2021 when compared to the same period in ~~2019~~2020 and asalso in the first six months 2021 when compared to the same period in 2020. As a result, we experienced ~~decreased~~increased price realizations. ~~In March 2020, Saudi Arabia~~NYMEX natural gas futures have shown some improvements based on market expectations that gas supplies will be limited due to slower growth of associated gas related activity in oil basins combined with reduced activity in natural gas basins and ~~Russia engaged in~~growing demand for liquefied natural gas exports. Through the end of second quarter 2021, uncertainty continued related to how long it will take to return to a ~~dispute over production levels that caused global~~balanced oil ~~prices~~supply and demand environment. Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions to ~~decline at a historic rate. On April 9, 2020, OPEC~~combat the virus are expected to directly impact the

recovery of world economic growth and ~~Russia reached an agreement to reduce crude oil production by 9.7MMbbl per day.~~the demand for oil. As we continue to monitor the impact of the actions of OPEC and other large producing nations ~~the dispute over production levels between Russia and Saudi Arabia~~ and the ~~level of demand impacted by COVID-19,~~uncertainty associated with governmental policies aimed at redirecting fossil fuel consumption towards lower carbon energy, we expect prices for some or all of the commodities we produce to remain ~~volatile~~volatile.

Throughout the COVID-19 pandemic, we leveraged our emergency response protocols and ~~could decline further from current levels.~~

~~While crude oil prices have recovered from~~business continuity plan to help manage our operations and workforce. Much of our workforce worked remotely for a significant period of time since the lows experienced in April 2020, they remain at depressed levels. NYMEX natural gas futures have shown some improvements based on market expectations that declines in future natural gas supplies due to a substantial reductionpandemic began. During June 2021, the majority of ~~associated gas related~~our corporate workforce returned to the ~~curtailment of~~office. Working remotely did not negatively impact our ability to maintain operations ~~in oil basins throughout the United States will more than offset the lower demand experienced with the COVID-19 pandemic.~~ and did not cause us to incur significant additional expenses.

The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

2020

2019

Benchmarks:

Average NYMEX prices ^(a)

Natural gas (per mcf)
$
1.95

$
2.23

$
1.87

$
2.67

Oil (per bbl)

40.90

56.42

38.87

57.33

Mont Belvieu NGLs composite (per gallon) ^(b)

0.40

0.38

0.35

0.46


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Benchmarks:
Average NYMEX prices (a)
Natural gas (per mcf)	$	2.84	$	1.72	$	2.76	$	1.83
Oil (per bbl)		65.96		27.09		62.06		38.03
Mont Belvieu NGLs composite (per gallon) (b)		0.63		0.30		0.62		0.32

(a) Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange (“NYMEX”).

(b) Based on our estimated NGLs product composition per barrel.

^(a)

~~Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange (“NYMEX”).~~

^(b)	~~Based on our estimated NGLs product composition per barrel.~~

Our price realizations (not including the impact of our derivatives) may differ from ~~the~~these benchmarks for many reasons, including quality, location or production being sold at different indices.

Consolidated Results of Operations

Overview of ~~Third~~Second Quarter ~~2020~~2021 Results

Our financial results are significantly impacted by commodity prices. For ~~third~~second quarter ~~2020,~~2021, we experienced ~~a decrease~~an increase in revenue from the sale of natural gas, NGLs and oil due to a ~~21% decrease~~75% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) ~~and slightly~~somewhat offset by lower production volumes when compared to the same quarter of ~~2019.~~2020. Daily production averaged ~~2.2~~2.1 Bcfe in ~~both the third~~second quarter ~~2020 and~~2021 compared to 2.3 Bcfe in the same period of the prior ~~year. Reduced~~year due to the sale of our North Louisiana properties in third quarter 2020. In addition, net operating costs ~~offset a portion of these price declines~~were lower when compared to the same period of ~~2019.~~2020.

During ~~third~~second quarter ~~2020,~~2021, we recognized a net loss of ~~$680.0~~$156.5 million, or ~~$2.83~~$0.65 per diluted common share compared to a net loss of ~~$27.6~~$167.6 million, or ~~$0.11~~$0.70 per diluted common share, during ~~third~~second quarter ~~2019.~~2020. The ~~decrease~~improvement in our net ~~income~~loss for ~~third~~second quarter 2021 compared to the second quarter 2020 ~~from third quarter 2019 is primarily due to the accrual of~~includes significantly higher realized prices, lower net operating costs and a favorable divestiture contract obligation ~~associated with the sale of our North Louisiana assets,~~adjustment offset by reduced derivative fair value income (or the non-cash fair value adjustment related to our derivatives) due to higher commodity prices and ~~lower net realized prices partially offset by lower operating costs.~~higher deferred compensation expense.

Our ~~third~~second quarter ~~2020~~2021 financial and operating performance included the following results:



revenue from the sale of natural gas, NGLs and oil increased 78% from the same period of 2020 with a 99% increase in average realized prices (before cash settlements on our derivatives) partially offset by lower production volumes;



revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased 24% from the same period of 2020;



direct operating expense per mcfe was 9% lower than the same period of 2020 (see discussion on page 34);



reduced our depletion, depreciation and amortization (“DD&A”) rate per mcfe by 4% from the same period of 2020; and



reduced debt by $66.3 million with cash flow from operations.

•

extended our debt maturities by issuing $300.0 million of additional new senior notes and used the proceeds, along with proceeds received from the sale of our North Louisiana assets, to redeem $500.0 million principal amount of certain senior and senior subordinated notes due in 2021, 2022 and 2023;

•

~~repurchased in the open market $2.9 million face value of certain of our senior and senior subordinated notes at a discount and recorded a gain on early extinguishment of debt;~~

•

~~reduced transportation, gathering, processing and compression on a per mcfe basis 7%, and on an absolute basis 9%, when compared to the same period of 2019;~~

•

~~direct operating expense per mcfe was 41% lower from the same period of 2019 (see discussion on page 38);~~

•

~~reduced general and administrative expense on a per mcfe basis 5%, and on an absolute basis 7%, when compared to the same period of 2019 (see discussion on page 38);~~

•

~~reduced our depletion, depreciation and amortization (“DD&A”) rate per mcfe by 28% from the same period of 2019;~~

•

revenue from the sale of natural gas, NGLs and oil decreased 20% from the same period of 2019 with an 18% decrease in average realized prices (before cash settlements on our derivatives) and slightly lower production volumes;

•

~~revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) decreased 16% from the same period of 2019; and~~

•

~~entered into additional derivative contracts for 2020 through 2024.~~

Our cash flow from operating activities in ~~third~~second quarter ~~2020~~2021 was ~~a negative $24.3~~$174.2 million, ~~a decrease~~an increase of ~~$128.2~~$95.4 million from ~~third~~second quarter ~~2019. The third~~2020. Second quarter ~~2020~~2021 cash flow from operating activities includes the $28.5 million one-time minimum volume commitment payment paid to a midstream company to lower our financial commitment related to minimum volume commitments retained in the sale of our North Louisiana assets, approximately $28.5 million of closing adjustments related to the sale of our North Louisiana assets, lower netincluded significantly higher realized prices and ~~higher comparative working capital outflows partially offset by~~ lower net operating ~~expenses. We continue~~costs compared to ~~repurchase in the open market our senior and senior subordinated notes at a discount. Since August 2019, we have repurchased $362.6~~second quarter 2020.

~~million principal amount of various senior and senior subordinated notes at a discount of $47.4 million.~~

Overview of First ~~Nine Months 2020~~Six months 2021 Results

For first ~~nine~~six months ~~2020,~~2021, we experienced ~~a decrease~~an increase in revenue from the sale of natural gas, NGLs and oil due to a ~~34% decrease~~50% increase in net realized prices (average prices including all ~~derivative~~derivatives settlements and third-party transportation costs paid by us) ~~partially~~somewhat offset by ~~slightly higher~~lower production volumes when compared to ~~first nine months 2019.~~the same period of 2020. Daily production ~~averaged~~average 2.1 Bcfe in first six months 2021 compared to 2.3 Bcfe in ~~both~~ the ~~first nine month periods~~same period of ~~2020 and 2019. Operating~~the prior year due to the sale of our North Louisiana properties in third quarter 2020. In addition, net operating costs were lower when compared to the same period of ~~the prior year which partially offset the significant declines in realized prices.~~2020.

During first ~~nine~~six months ~~2020,~~2021, we recognized a net loss of ~~$681.6~~$129.3 million, or ~~$2.82~~$0.53 per diluted common share compared to a net ~~income~~loss of ~~$89.0~~$1.4 million, or ~~$0.35~~$0.01 per diluted common share, during ~~first nine months 2019.~~the same period of 2020. The ~~decline~~increase in our net ~~income~~loss for first ~~nine~~six months ~~2020~~2021 from first ~~nine~~six months ~~2019~~2020 is primarily due to ~~the accrual of a divestiture contract obligation associated with the sale of our North Louisiana assets,~~ reduced derivative fair value income (or the non-cash fair value ~~adjustments~~adjustment related to our derivatives), a lower gain on asset sales and higher ~~impairment charges and lower net realized prices~~deferred compensation plan expense partially offset by significantly higher realized prices, lower net operating costs, ~~slightly higher production volumes~~lower proved property impairment and ~~a gain on sale of assets.~~lower DD&A expense.

Our first ~~nine~~six months ~~2020~~ financial and operating performance included the following results:

•

issued $850.0 million of new senior notes and used those proceeds, along with the proceeds from the sale of our North Louisiana assets, to redeem $1.0 billion of senior and senior subordinated notes due in 2021, 2022 and 2023;



revenue from the sale of natural gas, NGLs and oil increased 57% from the same period of 2020 with a 75% increase in average realized prices (before cash settlements on our derivatives) partially offset by lower production volumes;

•

~~repurchased in the open market $161.0 million face value of certain of our senior and senior subordinated notes at a discount and recorded a gain on early extinguishment of debt;~~



revenue from the sale of natural gas, NGLs and oil (including settlements on our derivatives) increased 14% from the same period of 2020;

•

~~maintained liquidity under the bank credit facility with the reaffirmation of a $3.0 billion borrowing base and $2.4 billion in lender commitments;~~



direct operating expense per mcfe was 23% lower than the same period of 2020 (see discussion on page 34);

•

~~repurchased 8.2 million shares of common stock in the open market;~~



reduced transportation, gathering, processing and compression on an absolute basis by 1% when compared to the same period of 2020 (see discussion on page 32);

•

~~realized $179.0 million of cash flow from operating activities;~~



reduced general and administrative expense on an absolute basis by 3% when compared to the same period of 2020 (see discussion on page 35);

•

revenue from the sale of natural gas, NGLs and oil decreased 32% from the same period of 2019 with a 33% decrease in average realized prices (before cash settlements on our derivatives) partially offset by an increase in production volumes;



reduced our DD&A rate per mcfe by 4% from the same period of 2020;

•

~~revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) decreased 21% from the same period of 2019;~~

•

~~reduced transportation, gathering, processing and compression on a per mcfe basis 9%, and on an absolute basis 8%, when compared to the same period of 2019;~~

•

~~reduced direct operating expenses per mcfe 29% from the same period of 2019 (see discussion on page 38);~~

•

~~reduced general and administrative expense per mcfe 14% from the same period of 2019 (see discussion on page 38);~~

•

~~reduced interest expense per mcfe 4% from the same period of 2019;~~

•

~~reduced our DD&A rate per mcfe by 28% from the same period of 2019; and~~

•

~~entered into additional derivative contracts for 2020 through 2024.~~

~~We generated $179.0~~issued $600.0 million of new senior notes and used the proceeds to reduce our bank credit facility borrowing; and



reduced debt by $44.3 million with cash flow from operations.

Our cash flow from operating activities in first ~~nine~~six months ~~2020, a decrease~~2021 was $283.4 million, an increase of ~~$370.5~~$80.2 million from first ~~nine~~six months ~~2019, which reflects~~2020. First six months 2021 cash flow from operating activities included significantly higher realized prices and lower net realized prices, the one-time $28.5 million minimum volume commitment payment paid to a midstream company to lower our financial commitment related to the minimum volume commitments retained on the sale of our North Louisiana assets and approximately $28.5 million of closing adjustments related to the sale of our North Louisiana assetsoperating costs partially offset by ~~lower operating expenses and slightly~~the impact of negative working capital due to higher ~~production volumes.~~commodity prices.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. Our revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured. In ~~third~~second quarter ~~2020,~~2021, natural gas, NGLs and oil sales ~~decreased 20%~~increased 78% compared to ~~third~~second quarter ~~2019~~2020 with ~~an 18% decrease~~a 99% increase in average realized prices (before cash settlements on our derivatives). partially offset by a 10% reduction in production volumes. In first ~~nine~~six months ~~2020,~~2021, natural gas, NGLs and oil sales ~~decreased 32%~~increased 57% compared to ~~the same period of 2019~~first six months 2020 with a ~~33% decrease~~75% increase in average realized prices ~~(before cash settlements on derivatives)~~ partially offset by a ~~slight increase~~10% reduction in ~~production.~~production volumes. The following table illustrates the primary components of natural gas, NGLs, oil and condensate sales for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Natural gas, NGLs and oil sales

Natural gas
$
211,638

$
284,980

$
(73,342
)

(26
%)

$
679,094

$
1,063,323

$
(384,229
)
(36
%)
NGLs

149,263

143,195

6,068

4
%

416,885

508,035

(91,150
)
(18
%)
Oil

20,652

46,579

(25,927
)

(56
%)

66,928

138,629

(71,701
)
(52
%)
Total natural gas, NGLs and
oil sales
$
381,553

$
474,754

$
(93,201
)

(20
%)

$
1,162,907

$
1,709,987

$
(547,080
)
(32
%)


	Three Months Ended June 30,									Six Months Ended June 30,
	2021		2020		Change		%			2021		2020		Change		%
Natural gas, NGLs and oil sales
Natural gas	$	321,565	$	214,207	$	107,358		50	%	$	657,366	$	467,456	$	189,910		41	%
NGLs		255,533		124,383		131,150		105	%		485,941		267,622		218,319		82	%
Oil		44,757		10,668		34,089		320	%		81,895		46,276		35,619		77	%
Total natural gas, NGLs and oil sales	$	621,855	$	349,258	$	272,597		78	%	$	1,225,202	$	781,354	$	443,848		57	%

Our production is determined by drilling success which offsets the natural decline of our natural gas and oil reserves through production and asset sales. ~~Third quarter 2020 production volumes from the Marcellus Shale were 2.1Bcfe per day, an increase of 5% when compared to the same period of 2019. Third~~Second quarter 2020 production volumes from our North Louisiana properties were

approximately ~~72.5~~179.2 Mmcfe per ~~day. Our North Louisiana~~day and were 172.6 mcfe per day for first six months 2020. These assets were sold in third quarter 2020. ~~Production~~

volumes for first nine months 2020 for Marcellus shale properties were 2.1 Bcfe per day, an increase of 5% compared to the same period of 2019. Production volumes for the first nine months 2020 for our North Louisiana properties were approximately 139.0 Mmcfe per day. Our production for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 is set forth in the following table:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Production ^(a)

Natural gas (mcf)

142,876,351

143,721,265

(844,914
)

(1
%)

439,764,525

427,405,931

12,358,594

3
%
NGLs (bbls)

9,176,553

9,511,234

(334,681
)

(4
%)

28,525,849

28,971,049

(445,200
)
(2
%)
Crude oil (bbls)

656,319

939,541

(283,222
)

(30
%)

2,244,741

2,727,415

(482,674
)
(18
%)
Total (mcfe) ^(b)

201,873,583

206,425,915

(4,552,332
)

(2
%)

624,388,065

617,596,715

6,791,350

1
%

Average daily production ^(a)

Natural gas (mcf)

1,553,004

1,562,188

(9,184
)

(1
%)

1,604,980

1,565,589

39,391

3
%
NGLs (bbls)

99,745

103,383

(3,638
)

(4
%)

104,109

106,121

(2,012
)
(2
%)
Crude oil (bbls)

7,134

10,212

(3,078
)

(30
%)

8,192

9,991

(1,799
)
(18
%)
Total (mcfe) ^(b)

2,194,278

2,243,760

(49,482
)

(2
%)

2,278,789

2,262,259

16,530

1
%


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
Production (a)
Natural gas (mcf)		131,886,931		151,127,582		(19,240,651	)		(13	)%		262,215,672		296,888,174		(34,672,502	)		(12	)%
NGLs (bbls)		9,153,411		9,716,261		(562,850	)		(6	)%		17,896,355		19,349,296		(1,452,941	)		(8	)%
Crude oil (bbls)		777,067		720,125		56,942			8	%		1,535,058		1,588,422		(53,364	)		(3	)%
Total (mcfe) (b)		191,469,799		213,745,898		(22,276,099	)		(10	)%		378,804,150		422,514,482		(43,710,332	)		(10	)%

Average daily production (a)
Natural gas (mcf)		1,449,307		1,660,743		(211,436	)		(13	)%		1,448,705		1,631,254		(182,549	)		(11	)%
NGLs (bbls)		100,587		106,772		(6,185	)		(6	)%		98,875		106,315		(7,440	)		(7	)%
Crude oil (bbls)		8,539		7,913		626			8	%		8,481		8,728		(247	)		(3	)%
Total (mcfe) (b)		2,104,064		2,348,856		(244,792	)		(10	)%		2,092,841		2,321,508		(228,667	)		(10	)%

(a)Represents volumes sold regardless of when produced.

(b) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

^(a)

~~Represents volumes sold regardless of when produced.~~

^(b)	Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Our average realized price received (including all derivative settlements and third-party transportation costs) during ~~third~~second quarter ~~2020~~2021 was ~~$0.99~~$1.56 per mcfe compared to ~~$1.25~~$0.89 per mcfe in ~~third~~second quarter ~~2019.~~2020. Our average realized price received (including all derivative settlements and third-party transportation costs) during first ~~nine~~six months 2020 was ~~$1.02~~$1.55 per mcfe compared to ~~$1.54~~$1.03 per mcfe in ~~the same period of 2019.~~first six months 2020. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. Average realized prices (excluding derivative settlements) do not include derivative settlements or third-party transportation costs which are reported in transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations. Average realized prices (excluding derivative settlements) do include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 are shown below:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Average Prices

Average realized prices (excluding derivative settlements):

Natural gas (per mcf)
$
1.48

$
1.98

$
(0.50
)

(25
%)

$
1.54

$
2.49

$
(0.95
)
(38
%)
NGLs (per bbl)

16.27

15.06

1.21

8
%

14.61

17.54

(2.93
)
(17
%)
Crude oil and condensate (per bbl)

31.47

49.58

(18.11
)

(37
%)

29.82

50.83

(21.01
)
(41
%)
Total (per mcfe) ^(a)

1.89

2.30

(0.41
)

(18
%)

1.86

2.77

(0.91
)
(33
%)
Average realized prices (including all derivative settlements):

Natural gas (per mcf)
$
2.00

$
2.49

$
(0.49
)

(20
%)

$
2.10

$
2.70

$
(0.60
)
(22
%)
NGLs (per bbl)

16.17

15.80

0.37

2
%

15.18

19.19

(4.01
)
(21
%)
Crude oil and condensate (per bbl)

50.81

49.73

1.08

2
%

49.49

50.16

(0.67
)
(1
%)
Total (per mcfe) ^(a)

2.32

2.69

(0.37
)

(14
%)

2.35

2.99

(0.64
)
(21
%)
Average realized prices (including all derivative settlements and third-party transportation costs paid by Range):

Natural gas (per mcf)
$
0.90

$
1.23

$
(0.33
)

(27
%)

$
0.98

$
1.41

$
(0.43
)
(30
%)
NGLs (per bbl)

4.09

3.65

0.44

12
%

3.38

7.28

(3.90
)
(54
%)
Crude oil and condensate (per bbl)

50.56

49.73

0.83

2
%

49.07

50.16

(1.09
)
(2
%)
Total (per mcfe) ^(a)

0.99

1.25

(0.26
)

(21
%)

1.02

1.54

(0.52
)
(34
%)


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
Average Prices
Average realized prices (excluding derivative settlements):
Natural gas (per mcf)	$	2.44	$	1.42	$	1.02			72	%	$	2.51	$	1.57	$	0.94			60	%
NGLs (per bbl)		27.92		12.80		15.12			118	%		27.15		13.83		13.32			96	%
Crude oil and condensate (per bbl)		57.60		14.81		42.79			289	%		53.35		29.13		24.22			83	%
Total (per mcfe) (a)		3.25		1.63		1.62			99	%		3.23		1.85		1.38			75	%
Average realized prices (including all derivative settlements):
Natural gas (per mcf)	$	2.38	$	2.02	$	0.36			18	%	$	2.47	$	2.15	$	0.32			15	%
NGLs (per bbl)		25.64		13.51		12.13			90	%		24.26		14.71		9.55			65	%
Crude oil and condensate (per bbl)		42.20		45.03		(2.83	)		(6	)%		40.91		48.95		(8.04	)		(16	)%
Total (per mcfe) (a)		3.04		2.19		0.85			39	%		3.02		2.37		0.65			27	%
Average realized prices (including all derivative settlements and third-party transportation costs paid by Range):
Natural gas (per mcf)	$	1.18	$	0.91	$	0.27			30	%	$	1.25	$	1.01	$	0.24			24	%
NGLs (per bbl)		12.12		2.12		10.00			472	%		11.05		3.05		8.00			262	%
Crude oil and condensate (per bbl)		41.63		43.93		(2.30	)		(5	)%		40.62		48.45		(7.83	)		(16	)%
Total (per mcfe) (a)		1.56		0.89		0.67			75	%		1.55		1.03		0.52			50	%

(a) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

^(a)

Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices

we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis:

Three Months
Ended
September 30,

Nine Months Ended
September 30,

2020

2019

2020

2019

Average natural gas differentials below NYMEX
$
(0.47
)

$
(0.25
)

$
(0.33
)

$
(0.18
)
Realized gains (losses) on basis hedging
$
0.05

$
(0.01
)

$
0.04

$
0.03


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Average natural gas differentials below NYMEX	$	(0.39	)	$	(0.30	)	$	(0.25	)	$	(0.26	)
Realized gains (losses) on basis hedging	$	0.01		$	(0.01	)	$	(0.01	)	$	0.04

The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices):


	Three Months Ended September 30,												Nine Months Ended September 30,								Three Months Ended June 30,									Six Months Ended June 30,
		2019		Price Variance			Volume Variance			2020		2019			Price Variance			Volume Variance		2020	2020		Price Variance		Volume Variance			2021		2020		Price Variance		Volume Variance			2021
Natural gas
Price (per mcf)	$	1.98	$	(0.50	)	$	—		$	1.48	$	2.49		$	(0.95	)	$	—	$	1.54	$	1.42	$	1.02	$	—		$	2.44	$	1.57	$	0.94	$	—		$	2.51
Production (Mmcf)		143,721		—			(845	)		142,876		427,406			—			12,359		439,765		151,127		—		(19,240	)		131,887		296,888		—		(34,672	)		262,216
Natural gas sales	$	284,980	$	(71,667	)	$	(1,675	)	$	211,638	$	1,063,323		$	(414,975	)	$	30,746	$	679,094	$	214,207	$	134,630	$	(27,272	)	$	321,565	$	467,456	$	244,502	$	(54,592	)	$	657,366


	Three Months Ended September 30,											Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
		2019		Price Variance		Volume Variance			2020		2019			Price Variance			Volume Variance			2020	2020		Price Variance		Volume Variance			2021		2020		Price Variance		Volume Variance			2021
NGLs
Price (per bbl)	$	15.06	$	1.21	$	—		$	16.27	$	17.54		$	(2.93	)	$	—		$	14.61	$	12.80	$	15.12	$	—		$	27.92	$	13.83	$	13.32	$	—		$	27.15
Production (Mbbls)		9,511		—		(334	)		9,177		28,971			—			(445	)		28,526		9,716		—		(563	)		9,153		19,349		—		(1,453	)		17,896
NGLs sales	$	143,195	$	11,107	$	(5,039	)	$	149,263	$	508,035		$	(83,343	)	$	(7,807	)	$	416,885	$	124,383	$	138,355	$	(7,205	)	$	255,533	$	267,622	$	238,415	$	(20,096	)	$	485,941


	Three Months Ended September 30,												Nine Months Ended September 30,									Three Months Ended June 30,								Six Months Ended June 30,
		2019		Price Variance			Volume Variance			2020		2019			Price Variance			Volume Variance			2020	2020		Price Variance		Volume Variance		2021		2020		Price Variance		Volume Variance			2021
Crude oil
Price (per bbl)	$	49.58	$	(18.11	)	$	—		$	31.47	$	50.83		$	(21.01	)	$	—		$	29.82	$	14.81	$	42.79	$	—	$	57.60	$	29.13	$	24.22	$	—		$	53.35
Production (Mbbls)		940		—			(284	)		656		2,727			—			(482	)		2,245		720		—		57		777		1,588		—		(53	)		1,535
Crude oil sales	$	46,579	$	(11,886	)	$	(14,041	)	$	20,652	$	138,629		$	(47,168	)	$	(24,533	)	$	66,928	$	10,668	$	33,246	$	843	$	44,757	$	46,276	$	37,174	$	(1,555	)	$	81,895


	Three Months Ended September 30,												Nine Months Ended September 30,								Three Months Ended June 30,									Six Months Ended June 30,
		2019		Price Variance			Volume Variance			2020		2019			Price Variance			Volume Variance		2020	2020		Price Variance		Volume Variance			2021		2020		Price Variance		Volume Variance			2021
Consolidated
Price (per mcfe)	$	2.30	$	(0.41	)	$	—		$	1.89	$	2.77		$	(0.91	)	$	—	$	1.86	$	1.63	$	1.62	$	—		$	3.25	$	1.85	$	1.38	$	—		$	3.23
Production (Mmcfe)		206,426		—			(4,552	)		201,874		617,597			—			6,791		624,388		213,746		—		(22,276	)		191,470		422,514		—		(43,710	)		378,804
Total natural gas, NGLs and oil sales	$	474,754	$	(82,731	)	$	(10,470	)	$	381,553	$	1,709,987		$	(565,883	)	$	18,803	$	1,162,907	$	349,258	$	308,996	$	(36,399	)	$	621,855	$	781,354	$	524,681	$	(80,833	)	$	1,225,202

Transportation, gathering, processing and compression expense was ~~$268.1~~$282.8 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$295.9~~$278.9 million in ~~third~~second quarter ~~2019.~~2020. These third-party costs are ~~lower~~higher in ~~third~~second quarter ~~2020~~2021 when compared to ~~third~~second quarter

~~2019~~ 2020 due to ~~certain midstream contract provisions~~the impact of higher NGLs prices which result in ~~North Louisiana being met late last year,~~higher processing costs and higher fuel costs partially offset by transportation capacity releases in Pennsylvania and the impact of the sale of our North Louisiana assets in ~~mid-third~~third quarter 2020.

Transportation, gathering, processing and compression expense was ~~$831.7~~$557.2 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$899.8~~$563.6 million in first ~~nine~~six months ~~2019.~~2020. These third-party costs are lower when compared to the same period of the prior year due to ~~certain midstream contract provisions in North Louisiana being met late last year,~~ transportation capacity ~~releases~~released in Pennsylvania and the impact of ~~lower NGLs prices on our processing costs and~~ the sale of our North Louisiana ~~assets.~~assets in third quarter 2020 partially offset by the impact of higher NGLs prices which result in higher processing costs and higher fuel costs. We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 on a per mcf and per barrel basis (in thousands, except for costs per unit):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Transportation, gathering, processing and compression

Natural gas
$
157,097

$
180,353

$
(23,256
)

(13
%)

$
494,305

$
554,789

$
(60,484
)
(11
%)
NGLs

110,849

115,559

(4,710
)

(4
%)

336,491

344,997

(8,506
)
(2
%)
Oil

162

—

162

100
%

952

—

952

100
%
Total
$
268,108

$
295,912

$
(27,804
)

(9
%)

$
831,748

$
899,786

$
(68,038
)
(8
%)

Natural gas (per mcf)
$
1.10

$
1.25

$
(0.15
)

(12
%)

$
1.12

$
1.30

$
(0.18
)
(14
%)
NGLs (per bbl)
$
12.08

$
12.15

$
(0.07
)

(1
%)

$
11.80

$
11.91

$
(0.11
)
(1
%)
Oil (per bbl)
$
0.25

$
—

$
0.25

100
%

$
0.42

$
—

$
0.42

100
%


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
Transportation, gathering, processing and compression
Natural gas	$	158,637	$	167,367	$	(8,730	)		(5	)%	$	320,297	$	337,208	$	(16,911	)		(5	)%
NGLs		123,758		110,718		13,040			12	%		236,428		225,642		10,786			5	%
Oil		449		790		(341	)		(43	)%		449		790		(341	)		(43	)%
Total	$	282,844	$	278,875	$	3,969			1	%	$	557,174	$	563,640	$	(6,466	)		(1	)%

Natural gas (per mcf)	$	1.20	$	1.11	$	0.09			8	%	$	1.22	$	1.14	$	0.08			7	%
NGLs (per bbl)	$	13.52	$	11.40	$	2.12			19	%	$	13.21	$	11.66	$	1.55			13	%
Oil (per bbl)	$	0.58	$	1.10	$	(0.52	)		(47	)%	$	0.29	$	0.50	$	(0.21	)		(42	)%

Derivative fair value (loss) income was a loss of ~~$124.7~~$249.7 million in ~~third~~second quarter ~~2020~~2021 compared to a loss of $6.3million in second quarter 2020. Derivative fair value loss was $307.6 million in first six months 2021 compared to income of ~~$74.7million in third quarter 2019. Derivative fair value income was $102.2~~$226.9 million in first ~~nine~~six months ~~2020 compared to $208.2 million in first nine months 2019.~~2020. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate potentially lower wellhead revenues in the future while losses indicate potentially higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

2020

2019

Derivative fair value (loss) income per consolidated statements of operations
$
(124,690
)

$
74,676

$
102,182

$
208,190

Non-cash fair value (loss) gain: ⁽¹⁾

Natural gas derivatives
$
(197,028
)

$
(17,345
)

$
(231,805
)

$
126,296

Oil derivatives

(15,145
)

15,925

17,589

(11,857
)
NGLs derivatives

(2,329
)

(3,849
)

13,642

(46,598
)
Freight derivatives

3,568

(63
)

(2,917
)

2,000

Divestiture contingent consideration

430

—

430

—

Total non-cash fair value (loss) gain ⁽¹⁾
$
(210,504
)

$
(5,332
)

$
(203,061
)

$
69,841

Net cash receipt (payment) on derivative settlements:

Natural gas derivatives
$
74,035

$
72,809

$
245,044

$
92,333

Oil derivatives

12,694

146

44,166

(1,819
)
NGLs derivatives

(915
)

7,053

16,033

47,835

Total net cash receipt (payment)
$
85,814

$
80,008

$
305,243

$
138,349


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Derivative fair value (loss) income per consolidated statements of operations	$	(249,683	)	$	(6,303	)	$	(307,562	)	$	226,872

Non-cash fair value (loss) gain: (1)
Natural gas derivatives	$	(199,825	)	$	(76,330	)	$	(211,945	)	$	(34,777	)
Oil derivatives		(21,494	)		(34,515	)		(29,563	)		32,734
NGLs derivatives		(5,422	)		(14,722	)		(6,669	)		15,971
Freight derivatives		(89	)		(236	)		(1,067	)		(6,485	)
Divestiture contingent consideration		17,460			—			21,390			—
Total non-cash fair value (loss) gain (1)	$	(209,370	)	$	(125,803	)	$	(227,854	)	$	7,443

Net cash (payment) receipt on derivative settlements:
Natural gas derivatives	$	(7,514	)	$	90,837		$	(8,862	)	$	171,009
Oil derivatives		(11,961	)		21,758			(19,089	)		31,472
NGLs derivatives		(20,838	)		6,905			(51,757	)		16,948
Total net cash (payment) receipt	$	(40,313	)	$	119,500		$	(79,708	)	$	219,429

(1) Non-cash fair value adjustments on commodity derivatives is a non-U.S. GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under U.S. GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of operations. This also includes the change in fair value of our divestiture contingent consideration.

⁽¹⁾

Non-cash fair value adjustments on commodity derivatives is a non-U.S. GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under U.S. GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of operations.

Brokered natural gas, marketing and other revenue in ~~third~~second quarter ~~2020~~2021 was ~~$42.5~~$62.6 million compared to ~~$73.0~~$33.6 million in ~~third~~second quarter ~~2019~~2020 which is the result of significantly higher broker sales prices somewhat offset by lower broker sales volumes (volumes not related to our production) ~~and lower broker sales prices.~~. Brokered natural gas, marketing and other revenue in first six months 2021 was ~~$104.7~~$143.1 million compared to $62.2 million in first ~~nine~~six months 2020 ~~compared to $303.8 million in first nine months 2019~~ which is the result of significantly ~~lower~~higher broker sales volumes, higher broker sales prices and ~~broker sale prices.~~$8.8 million received as part of a capacity release agreement. We continue to optimize our transportation portfolio using these volumes. See also Brokered natural gas and marketing expense below for more information on our net brokered margin.

Operating Costs per Mcfe

We believe some of our expense fluctuations are best analyzed on a unit-of-production or per mcfe basis. The following table presents information about certain of our expenses on a per mcfe basis for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Direct operating expense
$
0.10

$
0.17

$
(0.07
)

(41
%)

$
0.12

$
0.17

$
(0.05
)
(29
%)
Production and ad valorem tax expense

0.03

0.04

(0.01
)

(25
%)

0.03

0.05

(0.02
)
(40
%)
General and administrative expense

0.19

0.20

(0.01
)

(5
%)

0.19

0.22

(0.03
)
(14
%)
Interest expense

0.24

0.23

0.01

4
%

0.23

0.24

(0.01
)
(4
%)
Depletion, depreciation and amortization expense

0.48

0.67

(0.19
)

(28
%)

0.49

0.68

(0.19
)
(28
%)


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
Direct operating expense	$	0.10	$	0.11	$	(0.01	)		(9	)%	$	0.10	$	0.13	$	(0.03	)		(23	)%
Production and ad valorem tax expense		0.04		0.03		0.01			33	%		0.03		0.03		—			—	%
General and administrative expense		0.21		0.18		0.03			17	%		0.21		0.19		0.02			11	%
Interest expense		0.30		0.23		0.07			30	%		0.30		0.23		0.07			30	%
Depletion, depreciation and amortization expense		0.47		0.49		(0.02	)		(4	)%		0.47		0.49		(0.02	)		(4	)%

Direct operating expense was ~~$19.5~~$19.8 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$35.3~~$24.4 million in ~~third~~second quarter ~~2019.~~2020. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. Our direct operating costs decreased in ~~third~~second quarter ~~2020~~2021 primarily due to the impact of the sale of our higher cost North Louisiana properties ~~and various higher operating cost legacy properties~~ in ~~Pennsylvania in the current year and late in the prior year and lower workover costs.~~third quarter 2020. Our production volumes decreased 2%10% in ~~third~~second quarter ~~2020.~~2021. We incurred ~~$856,000~~$1.7 million of workover costs in ~~third~~second quarter ~~2020~~2021 compared to ~~$7.8~~$1.1 million in ~~third~~second quarter ~~2019.~~2020. On a per mcfe basis, direct operating expense in ~~third~~second quarter ~~2020~~2021 decreased ~~41%~~9% to $0.10 from ~~$0.17~~$0.11 in the same period of ~~2019,~~2020 with the decrease primarily due to the impact of the sale of our North Louisiana ~~properties and various higher operating cost legacy properties in Pennsylvania and lower workover costs.~~properties.

Direct operating expense was ~~$75.9~~$37.4 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$102.5~~$56.4 million in the same period ~~of 2019.~~2020. Our direct operating ~~costs~~expenses decreased in first ~~nine~~six months ~~2020~~2021 compared to the same period of ~~2019~~the prior year due to the impact of the sale of our higher ~~operating~~ cost ~~properties (including our~~ North Louisiana ~~properties)~~properties in third quarter 2020 and lower workover costs. Our production volumes decreased 10% in first six months 2021. We incurred ~~$6.4~~$2.4 million of workover costs in first ~~nine~~six months ~~2020~~2021 compared to ~~$16.2~~$5.6 million in first ~~nine~~six months ~~2019.~~2020. On a per mcfe basis, direct operating costs decreased ~~29%~~23% from ~~$0.17~~$0.13 to ~~$0.12 in the same period of 2019~~$0.10 with the decrease ~~resulting from~~due to the impact of the sale of ~~various~~our higher ~~operating~~ cost ~~properties and lower workover costs.~~North Louisiana properties. The following table summarizes direct operating expense per mcfe for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Direct operating

Lease operating expense
$
0.10

$
0.13

$
(0.03
)

(23
%)

$
0.11

$
0.14

$
(0.03
)
(21
%)
Workovers

—

0.04

(0.04
)

(100
%)

0.01

0.03

(0.02
)
(67
%)
Stock-based compensation

—

—

—

—
%

—

—

—

—
%
Total direct operating expense
$
0.10

$
0.17

$
(0.07
)

(41
%)

$
0.12

$
0.17

$
(0.05
)
(29
%)


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
Direct operating
Lease operating expense	$	0.09	$	0.10	$	(0.01	)		(10	)%	$	0.09	$	0.12	$	(0.03	)		(25	)%
Workovers		0.01		0.01		—			—	%		0.01		0.01		—			—	%
Stock-based compensation		—		—		—			—	%		—		—		—			—	%
Total direct operating expense	$	0.10	$	0.11	$	(0.01	)		(9	)%	$	0.10	$	0.13	$	(0.03	)		(23	)%

Production and ad valorem taxes are paid based on market prices rather than hedged prices. This expense category is predominately comprised of the Pennsylvania impact fee. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” which functions as a tax on unconventional natural gas and oil production from the Marcellus Shale in Pennsylvania. This impact fee was ~~$4.5~~$8.4 million in ~~third~~second quarter 2021 compared to $2.7 million in second quarter 2020 ~~compared~~due to ~~$4.7 million in third~~higher natural gas prices partially offset by the mix of wells relative to the impact fee structure where the fee declines over

time. In second quarter, ~~2019.~~we adjusted our impact fee accrual for the six months 2021 to reflect the impact higher natural gas prices have on impact fee rates. These rates are based on benchmark natural gas prices. Production and ad valorem taxes (excluding the impact fee) were ~~$1.6~~$12,000 in second quarter 2021 compared to $2.8 million in ~~third~~second quarter 2020 ~~compared to $3.1 million in third quarter 2019~~ with the decrease due to ~~lower~~the impact of the sale of our North Louisiana assets.

Included in first six months 2021 is a $13.0 million impact fee compared to $8.8 million in first six months 2020 with the increase due to higher natural gas ~~prices and an increase in production not subject to production taxes.~~

prices. Production and ad valorem taxes (excluding the impact fee) were ~~$7.4~~$19,000 in first six months 2021 compared to $5.8 million in first ~~nine~~six months 2020 ~~compared to $9.0 million in the same period of 2019. Included in first nine months 2020 is a $13.3 million impact fee compared to $20.0 million in the same period of 2019~~ with the decrease due to ~~lower natural gas prices.~~the impact of the sale of our North Louisiana assets. The following table summarizes production and ad valorem taxes per mcfe for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Production and ad valorem taxes

Production taxes
$
0.01

$
0.01

$
—

—
%

$
0.01

$
0.01

$
—

—
%
Ad valorem taxes

—

0.01

(0.01
)

(100
%)

—

—

—

—
%
Impact fee

0.02

0.02

—

—
%

0.02

0.04

(0.02
)
(50
%)
Total production and ad valorem taxes
$
0.03

$
0.04

$
(0.01
)

(25
%)

$
0.03

$
0.05

$
(0.02
)
(40
%)


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
Production and ad valorem taxes
Impact fee	$	0.04	$	0.02	$	0.02			100	%	$	0.03	$	0.02	$	0.01			50	%
Production and ad valorem taxes		—		0.01		(0.01	)		(100	)%		—		0.01		(0.01	)		(100	)%
Total production and ad valorem taxes	$	0.04	$	0.03	$	0.01			33	%	$	0.03	$	0.03	$	—			—	%

General and administrative ~~(“G&A”)~~(G&A) expense was ~~$38.2~~$40.2 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$41.0~~$38.3 million in ~~third~~second quarter ~~2019.~~2020. The ~~third~~second quarter ~~2020 decrease~~2021 increase of ~~$2.8~~$1.9 million when compared to the same period of ~~2019~~2020 is primarily due to ~~lower stock-based compensation of $1.6 million~~higher legal and ~~lower travel and~~general office expenses including technology ~~costs.~~costs of $1.9 million and higher employee benefit costs, including healthcare, of $1.1 million partially offset by lower legal settlements. At ~~September~~June 30, ~~2020,~~2021, the number of G&A employees decreased ~~16%~~12% when compared to ~~September~~June 30, ~~2019.~~2020. On a per mcfe basis, ~~third~~second quarter 2021 G&A expense was 17% higher than second quarter 2020 due to higher legal, technology and employee benefit costs along with the impact of lower production volumes.

G&A expense for first six months 2021 decreased 5%$2.3 million when compared to the same period ~~of 2019~~2020 due to ~~lower travel and office expenses, including technology costs.~~

~~G&Aexpense for first nine months 2020 decreased $19.6 million~~when compared to the same period of 2019 due to lower salaries and benefits of $7.5 million, lower stock-based compensation of $3.5 million, lower franchise and other taxes of $1.5 million, lower rig release penalties of $1.4 million, lower consulting costs of $2.9 million and lower travel and general office expenses including technology ~~costs.~~costs and lower legal settlements partially offset by higher legal expenses. On a per mcfe basis, first ~~nine~~six months 2021 G&A expense increased 11% from first six months 2020 ~~G&A expense decreased 14% from first nine months 2019~~ due to higher legal expenses and the impact of lower ~~salaries and benefits, lower rig release penalties, lower consulting costs and lower travel and general office expenses.~~production volumes. The following table summarizes G&A expenses on a per mcfe basis for the three and ~~nine~~six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,									Six Months Ended June 30,
	2021		2020		Change		%			2021		2020		Change		%
General and administrative
General and administrative	$	0.16	$	0.14	$	0.02		14	%	$	0.16	$	0.15	$	0.01		7	%
Stock-based compensation		0.05		0.04		0.01		25	%		0.05		0.04		0.01		25	%
Total general and administrative expense	$	0.21	$	0.18	$	0.03		17	%	$	0.21	$	0.19	$	0.02		11	%

~~ended September 30, 2020 and 2019:~~

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

General and administrative

General and administrative
$
0.15

$
0.16

$
(0.01
)

(6
%)

$
0.15

$
0.18

$
(0.03
)
(17
%)
Stock-based compensation (non-cash)

0.04

0.04

—

—
%

0.04

0.04

—

—
%
Total general and administrative expense
$
0.19

$
0.20

$
(0.01
)

(5
%)

$
0.19

$
0.22

$
(0.03
)
(14
%)

Interest expense was ~~$48.0~~$57.3 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$47.0~~$48.6 million in ~~third~~second quarter ~~2019.~~2020. Interest expense was ~~$144.1~~$114.2 million for first ~~nine~~six months ~~2020~~2021 compared to ~~$150.3~~$96.1 million ~~in the same period of 2019.~~for first six months 2020. The following table presents information about interest expense per mcfe for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Bank credit facility
$
0.04

$
0.04

$
—

—
%

$
0.03

$
0.05

$
(0.02
)
(40
%)
Senior notes

0.19

0.18

0.01

6
%

0.19

0.18

0.01

6
%
Subordinated notes

—

—

—

—
%

—

—

—

—
%
Amortization of deferred financing costs and other

0.01

0.01

—

—
%

0.01

0.01

—

—
%
Total interest expense
$
0.24

$
0.23

$
0.01

4
%

$
0.23

$
0.24

$
(0.01
)
(4
%)
Average debt outstanding ($000’s)
$
3,237,459

$
3,478,408

$
(240,949
)

(7
%)

$
3,268,227

$
3,773,783

$
(505,556
)
(13
%)
Average interest rate ^(a)

5.7
%

5.2
%

0.05
%

10
%

5.6
%

5.1
%

0.05
%
10
%


	Three Months Ended June 30,												Six Months Ended June 30,
	2021			2020			Change			%			2021			2020			Change			%
Bank credit facility	$	0.02		$	0.04		$	(0.02	)		(50	)%	$	0.02		$	0.04		$	(0.02	)		(50	)%
Senior notes		0.27			0.18			0.09			50	%		0.27			0.18			0.09			50	%
Amortization of deferred financing costs and other		0.01			0.01			—			—	%		0.01			0.01			—			—	%
Total interest expense	$	0.30		$	0.23		$	0.07			30	%	$	0.30		$	0.23		$	0.07			30	%
Average debt outstanding ($000’s)	$	3,146,680		$	3,306,517		$	(159,837	)		(5	)%	$	3,167,858		$	3,286,611		$	(118,753	)		(4	)%
Average interest rate (a)		7.0	%		5.6	%		1.4	%		25	%		6.9	%		5.6	%		1.3	%		23	%

(a) Includes commitment fees but excludes debt issue costs and amortization of discounts and premiums.

On an absolute basis, the increase in interest expense for ~~third~~second quarter ~~2020~~2021 from the same period of ~~2019~~2020 was primarily due to higher average interest rates partially offset by slightly lower overall average outstanding debt balances. Average debt outstanding on the bank credit facility for ~~third~~second quarter ~~2020~~2021 was ~~$684.6~~$195.5 million compared to ~~$592.7~~$681.3 million in ~~third~~second quarter ~~2019~~2020 and the weighted average interest rate on the bank credit facility was ~~2.4%~~2.0% in ~~third~~second quarter ~~2020~~2021 compared to ~~3.8%~~2.7% in ~~third~~second quarter ~~2019.~~2020.

On an absolute basis, the ~~decrease~~increase in interest expense for first ~~nine~~six months ~~2020~~2021 from the same period ~~of 2019~~2020 was primarily due to higher average interest rates partially offset by slightly lower overall average outstanding debt ~~balances partially offset by higher overall average interest rates.~~balances. Average debt outstanding on the bank credit facility was ~~$628.6~~$208.0 million for first ~~nine~~six months ~~2020~~2021 compared to ~~$861.0~~$600.6 million ~~in the same period of 2019~~for first six months 2020 and the weighted average interest rates were ~~2.7%~~2.1% in first ~~nine~~six months ~~2020~~2021 compared to ~~4.0%~~2.9% in first ~~nine~~six months ~~2019.~~2020.

Depletion, depreciation and amortization expense was ~~$96.2~~$90.6 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$137.8~~$104.6 million in ~~third~~second quarter ~~2019.~~2020. This decrease is due to a ~~27%~~4% decrease in depletion rates and a 2%10% decrease in production volumes. Depletion expense, the largest component of DD&A expense, was ~~$0.47~~$0.46 per mcfe in ~~third~~second quarter ~~2020~~2021 compared to ~~$0.64~~$0.48 per mcfe in ~~third~~second quarter ~~2019.~~2020. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. Our depletion rate per mcfe continues to decline due to asset sales and the mix of production from our properties with lower depletion ~~rates, asset sales and the impairment of our North Louisiana properties at the end of 2019.~~rates.

DD&A expense was ~~$303.8~~$179.0 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$418.0~~$207.6 million in the same period of ~~2019.~~2020. This is due to a ~~26%~~4% decrease in depletion rates ~~partially offset by~~and a ~~1% increase~~10% decrease in production volumes. Depletion expense per mcfe was ~~$0.48~~$0.46 per mcfe in first ~~nine~~six months ~~2020~~2021 compared to ~~$0.65~~$0.48 per mcfe in the same period of ~~2019.~~2020. The following table summarizes DD&A expense per mcfe for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019:~~2020:


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021		2020		Change			%
DD&A
Depletion and amortization	$	0.46	$	0.48	$	(0.02	)		(4	)%	$	0.46	$	0.48	$	(0.02	)		(4	)%
Depreciation		—		—		—			—	%		—		—		—			—	%
Accretion and other		0.01		0.01		—			—	%		0.01		0.01		—			—	%
Total DD&A expense	$	0.47	$	0.49	$	(0.02	)		(4	)%	$	0.47	$	0.49	$	(0.02	)		(4	)%

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

DD&A

Depletion and amortization
$
0.47

$
0.64

$
(0.17
)

(27
%)

$
0.48

$
0.65

$
(0.17
)
(26
%)
Depreciation

—

0.01

(0.01
)

(100
%)

—

0.01

(0.01
)
(100
%)
Accretion and other

0.01

0.02

(0.01
)

(50
%)

0.01

0.02

(0.01
)
(50
%)
Total DD&A expense
$
0.48

$
0.67

$
(0.19
)

(28
%)

$
0.49

$
0.68

$
(0.19
)
(28
%)

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties, exit and termination costs, deferred compensation plan expenses, loss or gain on early extinguishment of debt, impairment of proved properties and gain or loss on sale of assets. Stock-based compensation includes the amortization of restricted stock grants and PSUs. The following table details the allocation of stock-based compensation to functional expense categories for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Direct operating expense	$	340	$	434	$	667	$	884
Brokered natural gas and marketing expense		443		168		893		581
Exploration expense		362		372		748		702
General and administrative expense		9,382		9,179		18,787		17,208
Total stock-based compensation	$	10,527	$	10,153	$	21,095	$	19,375

Brokered natural gas and marketing expense was ~~$48.0~~$69.0 million in ~~third~~second quarter 2021 compared to $38.2 million in second quarter 2020 ~~compared to $79.9 million in third quarter 2019~~ due to ~~significantly lower~~higher broker purchase volumes (volumes not related to our production) and ~~lower~~significantly higher commodity prices. Brokered natural gas and marketing ~~expense~~ was ~~$118.8~~$141.3 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$313.4~~$70.8 million in first ~~nine~~six months ~~2019~~2020 due to significantly ~~lower~~higher broker purchase volumes and significantly ~~lower~~higher commodity prices. The following table details our brokered natural gas, marketing and other net margin for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Brokered natural gas and marketing

Brokered natural gas sales
$
39,180

$
70,404

$
(31,224
)

(44
%)

$
94,364

$
293,209

$
(198,845
)
(68
%)
Brokered NGLs sales

1,084

(183
)

1,267

692
%

3,230

1,425

1,805

127
%
Other marketing revenue

2,218

2,794

(576
)

(21
%)

7,128

9,200

(2,072
)
(23
%)
Brokered natural gas purchases ⁽¹⁾

(44,690
)

(76,722
)

32,032

42
%

(108,061
)

(303,275
)

195,214

64
%
Brokered NGLs purchases

(1,219
)

208

(1,427
)

(686
%)

(4,030
)

(1,321
)

(2,709
)
(205
%)
Other marketing expense

(2,058
)

(3,424
)

1,366

40
%

(6,661
)

(8,764
)

2,103

24
%
Net brokered natural gas and marketing margin
$
(5,485
)

$
(6,923

)

$
1,438

21
%

$
(14,030
)
$
(9,526
)
$
(4,504
)
(47
%)

⁽¹⁾

Three Months Ended
June 30,

Six Months Ended
June 30,

2021

2020

Change

%

2021

2020

Change

%

Brokered natural gas and marketing

Brokered natural gas sales

$
60,778

$
30,309

$
30,469

101
%

$
130,240

$
55,184

$
75,056

136
%
Brokered NGLs sales

722

1,006

(284
)

(28
)%

1,148

2,146

(998
)

(47
)%
Other marketing revenue

1,050

2,276

(1,226
)

(54
)%

11,726

4,910

6,816

139
%
Brokered natural gas purchases (1)

(65,668
)

(34,485
)

(31,183
)

(90
)%

(135,631
)

(63,372
)

(72,259
)

(114
)%
Brokered NGLs purchases

(660
)

(1,721
)

1,061

62
%

(1,057
)

(2,812
)

1,755

62
%
Other marketing expense

(2,676
)

(1,955
)

(721
)

(37
)%

(4,651
)

(4,601
)

(50
)

(1
)%
Net brokered natural gas and marketing margin

$
(6,454
)

$
(4,570
)

$
(1,884
)

(41
)%

$
1,775

$
(8,545
)

$
10,320

121
%

(1) Includes transportation costs.

~~Includes transportation costs.~~

Exploration expense was ~~$8.1~~$5.0 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$11.0~~$8.0 million in ~~third~~second quarter ~~2019~~2020 due to lower delay rentals and other expenses and lower personnel costs. Exploration expense was ~~$23.2~~$10.6 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$27.3~~$15.1 million in first ~~nine~~six months ~~2019~~2020 due to lower delay rentals and other expenses and lower personnel costs. The following table details our exploration expense for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2020

2019

Change

%

2020

2019

Change

%

Exploration

Delay rentals and other
$
6,737

$
8,746

$
(2,009
)

(23
%)

$
17,711

$
20,613

$
(2,902
)
(14
%)
Personnel expense

1,152

1,769

(617
)

(35
%)

4,580

5,833

(1,253
)
(21
%)
Stock-based compensation expense

189

496

(307
)

(62
%)

891

1,372

(481
)
(35
%)
Seismic

8

2

6

300
%

8

(485
)

493

102
%
Total exploration expense
$
8,086

$
11,013

$
(2,927
)

(27
%)

$
23,190

$
27,333

$
(4,143
)
(15
%)


	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			%			2021			2020		Change			%
Exploration
Delay rentals and other	$	3,516	$	5,762	$	(2,246	)		(39	)%	$	7,501		$	10,974	$	(3,473	)		(32	)%
Personnel expense		1,120		1,893		(773	)		(41	)%		2,399			3,428		(1,029	)		(30	)%
Stock-based compensation expense		362		372		(10	)		(3	)%		749			702		47			7	%
Seismic		30		—		30			100	%		(83	)		—		(83	)		(100	)%
Total exploration expense	$	5,028	$	8,027	$	(2,999	)		(37	)%	$	10,566		$	15,104	$	(4,538	)		(30	)%

Abandonment and impairment of unproved properties was ~~$5.7~~$2.2 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$16.2~~$5.5 million in ~~third~~second quarter ~~2019.~~2020. Abandonment and impairment of unproved properties was ~~$16.6~~$5.2 million in first ~~nine~~six months ~~2020~~2021 compared to ~~$41.6~~$10.9 million in ~~the same period of 2019. The unproved property value in North Louisiana was fully impaired in fourth quarter 2019. As a result, abandonment~~first six months 2020. Abandonment and impairment of unproved properties for ~~third~~second quarter and first ~~nine~~six months ~~2020~~2021 declined when compared to the same periods of ~~2019.~~2020 due to lower estimated expirations in Pennsylvania.

Exit and termination costs ~~were $521.6~~was a gain of $15.9 million in ~~third~~second quarter ~~2020~~2021 compared to ~~$819,000~~an expense of $10.3 million in ~~third~~second quarter ~~2019.~~2020. In ~~third~~second quarter ~~2020,~~2021, we ~~sold our North Louisiana assets and~~recorded $12.0 million accretion expense related to retained liabilities for certain gathering, transportation and processing obligations ~~which extend into~~extending until 2030. ~~The fair value~~In addition, we recorded a gain of ~~our estimated obligations was recorded at closing as an exit cost which totaled $479.8 million. As part of retaining these contract obligations, we paid $28.5~~$28.2 million to reduce our original estimate of these obligations due to payments being lower than our forecast and a midstream company to reduce these financial commitments. Also related to the sale of this asset, we recorded an accrual of $2.5 million for employee related expenses. During third quarter 2020, we also announced an additional general reductionchange in our ~~work force and recorded $3.7 million~~forecasted drilling plans of ~~severance and stock-based compensation for this reduction in force.~~the buyer. In second quarter 2020, we negotiated capacity releases on certain transportation pipelines in Pennsylvania and recorded termination costs of $10.4 million which represents the discounted present value of our remaining obligation to the third party. In first quarter 2020, we completed the sale of our legacy assets in Northwest Pennsylvania and recorded $1.6 million of employee related expenses which were primarily related to the sale of this asset. In third quarter 2019, we sold various non-core assets in Pennsylvania and accrued $819,000 of severance costs. In second quarter 2019, we announced a general reduction in our work force and recorded $2.2 million of severance costs related to this work force reduction.

Deferred compensation plan expense was a loss of ~~$6.2~~$35.5 million in ~~third~~second quarter ~~2020~~2021 compared to a ~~gain~~loss of ~~$8.9~~$12.6 million in ~~third~~second quarter ~~2019.~~2020. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Our stock price increased from ~~$5.63~~$10.33 at March 31, 2021 to $16.76 at June 30, ~~2020 to $6.62 at September 30, 2020.~~2021. In the same period of the prior year, our stock price ~~decreased~~increased from ~~$6.98~~$2.28 at March 31, 2020 to $5.63 at June 30, ~~2019 to $3.82 at September 30, 2019.~~2020. During first ~~nine~~six months ~~2020,~~2021, deferred compensation was a loss of ~~$10.3~~$55.3 million compared to a ~~gain~~loss of ~~$16.4~~$4.1 million in the same period of ~~2019.~~2020. Our stock price increased from $6.70 at December 31, 2020 to $16.76 at June 30, 2021. In the same period of the prior year, our stock price increased from $4.85 at December 31, 2019 to ~~$6.62~~$5.63 at ~~September~~June 30, 2020. ~~In the same period of 2019, our stock price decreased from $9.57 at December 31, 2018 to $3.82 at September30,2019.~~

Loss (gain) on early extinguishment of debt was a loss of ~~$7.8 million~~$63,000 in ~~third~~second quarter ~~2020 and a gain of $14.1 million in first nine months 2020~~2021 compared to a gain of ~~$3.0~~$9.0 million in ~~both~~second quarter 2020. In second quarter 2020, we repurchased in the ~~third quarter~~open market certain of our senior and ~~first nine months 2019.~~senior subordinated notes at a discount and recognized a gain of $9.0 million. In ~~third quarter~~January 2020, we purchased for cash $500.0 million aggregate principal amount of ~~various~~our 5.75% senior ~~and senior subordinated~~ notes due 2021 ~~2022~~ and ~~2023.~~our 5.875% senior notes due 2022. An early cash tender of $15.1 million was paid to note holders who tendered their notes within the early offer period. We recorded a loss on early extinguishment of debt in first quarter 2020 of ~~$8.0~~$17.5 million, net of transaction call premium costs and ~~expensing~~ the ~~remaining deferred financing costs. In addition, we purchased in the open market $2.7 million aggregate principal amounts~~expenses of ~~various senior and senior subordinated notes where we recorded a gain on early extinguishment of debt of $200,000, net of transaction costs and expensing~~ the remaining deferred financing costs on the repurchased debt. ~~In third~~The cash tender offer and early cash tender premium were financed from the issuance of our 9.25% senior notes. Also in first quarter ~~and first nine months 2019,~~2020, we purchased in the open market ~~$93.6~~$48.5 million ~~aggregate~~ principal amount of ~~various~~our 5.00% senior notes due 2022, $5.8 million principal amount of our 5.875% senior notes due 2022 and $56.6 million principal amount of our 5.00% senior notes due 2023. We recognized a gain on early extinguishment of debt in first quarter 2020 of ~~$3.0~~$30.4 million, net of transaction costs and the expensing of the remaining deferred financing costs on the repurchased debt.

Impairment of proved properties and other assets was ~~$2.0 million in third quarter 2020 and $79.0~~$77.0 million in first ~~nine~~six months 2020. There were no proved property impairments in ~~third quarter 2019 or~~ first ~~nine~~six months 2019. In third quarter 2020, as part of our continued effort to reduce general and administrative expense, we vacated one floor in our corporate office and recorded an impairment related to this lease of $2.0 million.2021. In fourth quarter 2019, we recorded impairment expense

related to our oil and gas properties in North Louisiana due to a shift in business strategy and the possibility of a divestiture of those assets. In first quarter 2020, additional impairment of $77.0 million was recorded related to these North Louisiana assets based on market indications of fair value for these assets.

Loss (gain) on the sale of assets was a ~~loss~~gain of ~~$9.2 million~~$646,000 in ~~third quarter 2020~~first six months 2021 compared to a ~~loss~~gain of ~~$36.3~~$121.7 million in the same period of ~~2019. Loss (gain)~~2020. In second quarter 2021, we recorded an additional gain on ~~the sale of assets was a gain of $112.4 million for first nine months 2020 compared to a loss of $30.7 million in the same period of 2019. Third quarter 2020 includes~~ the sale of our North Louisiana assets ~~for estimated fair value~~ of ~~$260.0~~$2.4 million ~~consisting of cash proceeds of $245.0 million and $15.0 million of contingent consideration which was the estimated fair value of contingent consideration we are entitled~~primarily related to ~~receive in the future, as of August 14, 2020. We recorded a pretax loss of $8.1 million on this sale, after~~final closing adjustments. ~~Third~~In first quarter ~~2019 included~~2021, we recorded an additional loss on the sale of ~~a proportionately reduced 2.5% overriding royalty in three separate transactions primarily covering~~ our ~~Washington County, Pennsylvania~~North Louisiana assets ~~for gross proceeds~~ of ~~$750.0 million for which we recognized a loss of $36.5 million which represents closing adjustments and transaction fees.~~$1.9 million. In first quarter 2020, we received approval from state governmental authorities for a change in operatorship for our shallow Northwest Pennsylvania properties and we recorded a gain on the sale of these legacy assets of $122.5 million. We did retain the deeper Utica rights on this acreage as part of this transaction.

Income tax ~~benefit~~(benefit) expense was ~~$105.3~~a benefit of $1.3 million in ~~third~~second quarter ~~2020~~2021 compared to a benefit ~~of $47.2~~$22.3 million in ~~third~~second quarter ~~2019.~~2020. Income tax ~~benefit~~expense was ~~$98.3 million in first nine months 2020 compared to a benefit of~~ $1.4 million in first ~~nine~~six months ~~2019. For third quarter 2020, the effective tax rate was 13.4%~~2021 compared to ~~63.1%~~$6.7 million in ~~the same period of 2019. For~~ first ~~nine~~six months ~~2020, the effective tax rate was 12.6% compared to (1.6%) in the same period of 2019.~~2020. The ~~2020~~2021 and ~~2019~~2020 effective tax rates were different than the statutory tax rate due to state income taxes, equity compensation, valuation allowances and other discrete tax items.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Cash Flow

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations are also impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and because our principal source of operating cash flows (proved reserves to be produced in future years) cannot be reported as working capital, we often have low or negative working capital. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. As of ~~September~~June 30, ~~2020,~~2021, we have entered into derivative agreements covering ~~117.8~~244.6 Bcfe for the remainder of ~~2020~~2021 and ~~380.0~~168.0 Bcfe for ~~2021,~~2022, not including our basis swaps.

4238

The following table presents sources and uses of cash and cash equivalents for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):


		Nine Months Ended September 30,					Six Months Ended June 30,
		2020			2019		2021			2020
Sources of cash and cash equivalents
Operating activities	$	178,974		$	549,431		$	283,435		$	203,268
Disposal of assets		246,083			784,527			195			1,071
Issuance of senior notes		850,000			—			600,000			550,000
Borrowing on credit facility		1,676,000			1,730,000			883,000			1,045,000
Other		21,664			22,011			30,572			17,288
Total sources of cash and cash equivalents	$	2,972,721		$	3,085,969		$	1,797,202		$	1,816,627

Uses of cash and cash equivalents
Additions to natural gas and oil properties	$	(321,849	)	$	(550,355	)	$	(205,923	)	$	(254,073	)
Repayment on credit facility		(1,447,000	)		(2,345,000	)		(1,464,000	)		(883,000	)
Acreage purchases		(18,554	)		(39,795	)		(15,917	)		(14,486	)
Additions to field service assets		(2,493	)		(803	)		(652	)		(1,851	)
Repayment of senior and senior subordinated notes		(1,120,634	)		(90,274	)		(63,324	)		(617,982	)
Treasury stock purchases		(22,992	)		—			—			(22,992	)
Dividends paid		—			(15,077	)
Debt issuance costs		(12,735	)		—			(8,591	)		(8,360	)
Other		(26,493	)		(44,856	)		(38,789	)		(13,861	)
Total uses of cash and cash equivalents	$	(2,972,750	)	$	(3,086,160	)	$	(1,797,196	)	$	(1,816,605	)

Sources of Cash and Cash Equivalents

Cash flows provided from operating activities in first ~~nine~~six months ~~2020~~2021 was ~~$179.0~~$283.4 million compared to ~~$549.4~~$203.3 million in first ~~nine~~six months ~~2019.~~2020. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The ~~decrease~~increase in cash provided from operating activities from first ~~nine~~six months ~~2019~~2020 to first ~~nine~~six months ~~2020~~2021 reflects ~~significantly lower net~~higher realized prices ~~(a decrease of 34%), the impact of our asset sales~~ and lower operating expenses partially offset by working capital cash ~~inflow partially offset by slightly higher production volumes~~outflow and lower ~~operating expenses.~~production volumes. As of ~~September~~June 30, ~~2020,~~2021, we have hedged more than 65% of our projected total production for the remainder of ~~2020,~~2021, with more than ~~80%~~75% of our projected natural gas production hedged. Net cash provided from operating activities was affected by a ~~1% increase~~10% decrease in production and working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for first ~~nine~~six months ~~2020~~2021 were negative ~~$47.8~~$73.7 million compared to a positive ~~$29.3~~$26.1 million for first ~~nine months 2019 which includes the impact of the closing adjustments related to the sale of our North Louisiana assets.~~quarter 2020.

Uses of Cash and Cash Equivalents

Additions to natural gas and oil properties for first ~~nine~~six months ~~2020~~2021 were consistent with expectations relative to our ~~$430.0~~$425.0 million ~~2020~~2021 capital budget.

Repayment of senior and senior subordinated notes for first ~~nine~~six months 2021 includes the redemption of various senior and senior subordinated notes due 2021, 2022 and 2023. The first six months 2020 includes purchases in the open market of ~~$1.1~~$48.5 million ~~principal amount of our 5.75% senior subordinated notes due 2021, $1.0 million principal amount~~ of our 5.00% senior subordinated notes due 2022, ~~$12.5 million principal amount of our 5.75% senior notes due 2021, $51.3 million principal amount of our 5.00% senior notes due 2022, $8.1~~$5.8 million principal amount of our 5.875% senior notes due 2022 and ~~$86.9~~$56.6 million principal amount of our 5.00% senior notes due 2023. In addition, in conjunction with the issuance of our ~~new $850.0~~$550.0 million aggregate principal amount 9.25% senior notes due 2026, we used the proceeds from this issuance ~~and proceeds from the sale of our North Louisiana assets~~ to redeem ~~$336.2~~$324.1 million of our 5.75% senior notes due 2021 ~~$241.0~~and $175.9 million of our 5.875% senior notes due 2022, $291.0 million of our 5.00% senior notes due 2022, $122.3 million of our 5.00% senior notes due 2023, $1.2 million of our 5.75% senior subordinated notes due 2021 and $8.3 million of our 5.00% senior subordinated notes due 2022. From time to time, we may continue to repurchase our senior notes based upon prevailing market or other conditions at the time.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash ~~flow~~flows from operating activities, a bank credit facility with uncommitted and committed availability, access to the debt and equity capital markets and asset sales. We

must ~~find new reserves and~~ develop existing reserves to maintain ~~and~~or grow our production and cash flows. We accomplish this primarily through successful drilling programs which require substantial capital expenditures. We continue to take steps to ensure we have adequate capital resources and liquidity to fund our capital expenditure program. In ~~first nine months 2020,~~second quarter 2021, we entered into additional commodity derivative contracts for ~~2020~~2021 through 2024 to protect future cash flows. ~~Additionally, we suspended the payment of our common stock dividend in January 2020.~~

During first ~~nine~~six months ~~2020,~~2021, our net cash provided from operating activities of ~~$179.0~~$283.4 million ~~proceeds from asset sales~~ and borrowings under our bank credit facility were used to fund approximately ~~$342.9~~$222.5 million of capital expenditures (including acreage acquisitions). At ~~September~~June 30, ~~2020,~~2021, we had ~~$517,000~~$464,000 in cash and total assets of ~~$6.0~~$6.2 billion.

Long-term debt at ~~September~~June 30, ~~2020~~2021 totaled ~~$3.1~~$3.0 billion, including ~~$706.0~~$121.0 million outstanding on our bank credit facility and ~~$2.4~~$2.9 billion of senior and senior subordinated notes. Our available committed borrowing capacity at ~~September~~June 30, ~~2020~~2021 was ~~$1.4~~$1.9 billion ~~with an additional $600.0 million in borrowing base capacity available for increased liquidity potential.~~under current bank commitments. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in maintaining ~~or growing~~ reserves and production will be highly dependent on capital resources ~~available and the success of finding or acquiring additional reserves.~~available. We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives contracts currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. While our expectation is to operate within our internally generated cash flow, to the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity securities may be issued to fund these requirements. Long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business. A material decline in natural gas, NGLs and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and operate profitably. We establish a capital budget at the beginning of each calendar year and review it during the course of the year, taking into account various factors including the commodity price environment. Our ~~initial 2020~~2021 capital budget was announced in early ~~January~~February at ~~$520.0 million which was subsequently reduced $90.0 million to $430.0 million based on the lower commodity price environment. We currently estimate our spending for 2020 will not be more than $415.0~~$425.0 million.

Commodity prices have remained highly volatile and have ~~declined~~increased during first ~~nine~~six months ~~2020~~2021 compared to fourth quarter ~~2019.~~2020. Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for and our ability to develop our reserves of natural gas, NGLs and oil. We have adjusted and must continue to adjust our business through efficiencies and ~~cost reductions to compete in the current price environment which also requires reductions in overall debt levels over time.~~margin enhancements. We plan to continue to work towards ~~profitable growth within cash flows.~~improved profitability and debt metrics. We would expect to monitor the market and look for opportunities to refinance or reduce debt based on market conditions. We believe we are well-positioned to manage the challenges presented in a low commodity price environment and that we can endure continued volatility in current and future commodity prices by:



exercising discipline in our capital program with the expectation of funding our capital expenditures with operating cash flow and, if required, with borrowings under our bank credit facility;



continuing to optimize our drilling, completion and operational efficiencies;



continuing to focus on improving our cost structure;



continuing to pursue asset sales to reduce debt;



continuing to manage price risk by hedging our production volumes; and



continuing to manage our balance sheet.

•

~~exercising discipline in our capital program with the expectation of funding our capital expenditures with operating cash flow and, if required, with borrowings under our bank credit facility;~~

•

~~continuing to optimize our drilling, completion and operational efficiencies;~~

•

~~continuing to focus on improving our cost structure;~~

•

~~continuing to pursue asset sales to reduce debt;~~

•

~~continuing to manage price risk by hedging our production volumes; and~~

•

~~continuing to manage our balance sheet.~~

Credit Arrangements

As of ~~September~~June 30, ~~2020,~~2021, we maintained a revolving credit facility with a borrowing base of $3.0 billion and aggregate lender commitments of $2.4 billion, which we refer to as our bank credit facility or bank debt. The bank credit facility is secured by substantially all of our assets and has a maturity date of April 13, 2023. ~~See Note 9 to our unaudited consolidated financial statements for additional information regarding our bank debt.~~ Availability under the bank credit facility is subject to a borrowing base set by the lenders. As of ~~September~~June 30, ~~2020,~~2021, the outstanding balance under our bank credit facility was ~~$706.0~~$121.0 million. Additionally, we had ~~$332.0~~$334.6 million of undrawn letters of credit leaving ~~$1.4~~$1.9 billion of committed borrowing capacity available under the bank credit facility at the end of ~~third~~second quarter ~~2020, with an additional $600.0 million in borrowing base capacity for potential increases in lender commitments.~~2021.

Our bank credit facility imposes limitations on the payment of dividends and other restricted payments (as defined under our bank credit facility). The bank credit facility also contains customary covenants relating to debt incurrence, liens, investments and financial ratios. We were in compliance with all covenants at ~~September~~June 30, ~~2020.~~2021. See Note 9 to our unaudited consolidated financial statements for additional information regarding our bank debt.

44Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to sell an indeterminate amount of various types of debt and equity securities.

Cash Dividend Payments

In January 2020, we announced that the Board of Directors suspended the dividend on our common stock. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and primarily depends on ~~earnings,~~cash flow, capital expenditures, debt covenants and various other factors.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, processing and gathering commitments including the divestiture contractual commitment. As of ~~September~~

June 30, ~~2020,~~2021, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of ~~September~~June 30, ~~2020,~~2021, we had a total of ~~$332.0~~$334.6 million of undrawn letters of credit under our bank credit facility.

Since December 31, ~~2019,~~2020, there have been no material changes to our contractual obligations other than the changes to our indebtedness as discussed further in Note 9 and a reduction in our ~~transportation, gathering and processing contracts~~divestiture contract obligation as ~~further~~ discussed in Note ~~17.~~14.

Interest Rates

At ~~September~~June 30, ~~2020,~~2021, we had approximately ~~$3.1~~$3.0 billion of debt outstanding. Of this amount, ~~$2.4~~$2.9 billion bore interest at fixed rates averaging ~~6.5%~~6.9%. Bank debt totaling ~~$706.0~~$121.0 million bears interest at a floating rate, which was 2.2% at ~~September~~June 30, ~~2020.~~2021. The 30-day LIBOR Rate on ~~September~~June 30, ~~2020~~2021 was approximately 0.1%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on ~~September~~June 30, ~~2020~~2021 would result in approximately ~~$7.1~~$1.2 million in additional annual interest expense.

Off-Balance Sheet Arrangements

We do not currently utilize any significant off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, some of which are described above under Cash Contractual Obligations.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. We expect costs for the remainder of ~~2020~~2021 to continue to be a function of supply and demand.

Forward-Looking Statements

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our current forecasts for our existing operations and do not include the potential impact of any future events. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, ~~2019,~~2020, as filed with the SEC on February ~~27, 2020.~~23, 2021.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~ITEM 3.~~

~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of

expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivative instruments apply to a varying portion of our production and provide only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Changes in natural gas prices affect us more than changes in oil prices because approximately ~~67%~~65% of our December 31, ~~2019~~2020 proved reserves are natural gas and 2% of proved reserves are ~~oil.~~oil and condensate. In addition, a portion of our NGLs, which are 33% of proved reserves, are also

impacted by changes in oil prices. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, ~~2019~~2020 to ~~September~~June 30, ~~2020.~~2021.

Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program can also include collars, which establish a minimum floor price and a predetermined ceiling price. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (which we refer to as a swaption). Our program may also include a three-way collar which is a combination of three options. At ~~September~~June 30, ~~2020,~~2021, our derivative program includes swaps, collars, three-way collars and swaptions. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation based on a comparison of the contract price and a reference price, generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs, as of ~~September~~June 30, ~~2020,~~2021, approximated a net unrealized pretax loss of ~~$83.5~~$287.7 million. These contracts expire monthly through December ~~2021.~~2022. At ~~September~~June 30, ~~2020,~~2021, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:

Period

Contract Type

Volume Hedged

Weighted Average Hedge Price

Fair Market Value

Swap

Sold Put

Floor

Ceiling

(in thousands)
Natural Gas ⁽¹⁾




2020

Swaps

1,133,587 Mmbtu/day

$
2.63

$
2,687
2021

Swaps

510,000 Mmbtu/day

$
2.77

$
(25,963)
2020

Collars

5,041 Mmbtu/day

$ 2.00

$ 2.50

$
―
January – October 2021

Collars

342,237 Mmbtu/day

$ 2.51

$ 3.00

$
(14,169)
2020

Three-way Collars

79,891 Mmbtu/day

$ 2.23

$ 2.58

$ 3.19

$
227
2021

Three-way Collars

240,000 Mmbtu/day

$ 1.99

$ 2.33

$ 2.60

$
(40,110)

Crude Oil




2020

Swaps

6,000 bbls/day

$
58.02

$
9,576
2021

Swaps

1,000 bbls/day

$
55.00

$
4,489

NGLs (C3-Propane)

2020

Swaps

6,000 bbls/day

$
0.51/gallon

$
101

NGLs (NC4-Normal Butane)

2020

Swaps

1,000 bbls/day

$
0.60/gallon

$
17

NGLs (C5-Natural Gasoline)




2020

Swaps

2,000 bbls/day

$
0.89/gallon

$
25


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price								Fair Market Value
			Swap		Sold Put		Floor		Ceiling
											(in thousands)
Natural Gas (1)
2021	Swaps	575,000 Mmbtu/day	$	2.78							$	(91,772	)
2021	Collars	293,696 Mmbtu/day					$	2.65	$	3.16	$	(29,935	)
2021	Three-way Collars	309,728 Mmbtu/day			$	2.14	$	2.47	$	2.84	$	(49,883	)
2022	Swaps	190,000 Mmbtu/day	$	2.82							$	(23,484	)
2022	Collars	40,000 Mmbtu/day					$	2.90	$	3.29	$	(1,193	)
2022	Three-way Collars	200,000 Mmbtu/day			$	2.20	$	2.72	$	3.35	$	(12,699	)

Crude Oil (1)
2021	Swaps	7,166 bbls/day	$	56.28							$	(19,391	)
2022	Swaps	4,560 bbls/day	$	60.39							$	(8,899	)

NGLs (C3-Propane)
2021	Swaps	6,000 bbls/day	$0.90/gallon								$	(8,490	)
July – September 2021	Collars	5,000 bbls/day					$0.95/gallon		$1.05/gallon		$	(1,092	)

NGLs (NC4-Normal Butane)
2021	Swaps	2,000 bbls/day	$1.05/gallon								$	(2,744	)
2021	Collars	2,500 bbls/day					$0.94/gallon		$1.08/gallon		$	(3,413	)

NGLs (C5-Natural Gasoline)
2021	Swaps	3,000 bbls/day	$1.28/gallon								$	(6,952	)
2021	Collars	2,000 bbls/day					$1.34/gallon		$1.55gallon		$	(1,268	)
2022	Swaps	1,000 bbls/day	$1.50/gallon								$	(76	)
2022	Collars	1,000 bbls/day					$1.40/gallon		$1.60/gallon		$	(41	)

(1) We also sold natural gas call swaptions of 180,000 Mmbtu/day for 2022 at a weighted average price of $2.86. The fair market value of these swaptions at June 30, 2021 was a net derivative liability of $22.1 million. In addition, we sold oil call swaptions of 1,000 bbls per day for 2022 at a weighted average price of $54.00 which has a fair value of a loss of $4.3 million at June 30, 2021.

⁽¹⁾

We also sold natural gas call swaptions of 140,000 Mmbtu/day for 2021 at a weighted average price of $2.88. In addition, we sold natural gas call swaptions of 280,000 Mmbtu/day per day for 2022 at a weighted average price of $2.81. The fair market value of these swaptions at September 30, 2020 was a net derivative liability of $20.4 million.

~~In the future, we expect our NGLs production to continue to increase.~~ We believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional and international markets. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas.

Currently, the Appalachian region has limited local demand and infrastructure to accommodate ethane. We have agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area. We cannot ensure that

these facilities will remain available. If we are not able to sell ethane under at least one of these agreements, we may be required to curtail production or, as we have done in the past, purchase or divert natural gas to blend with our rich residue gas.

Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. Therefore, in addition to the swaps, collars, three-way collars and ~~calls~~swaptions discussed above, we have entered into natural gas basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX Henry Hub price because of basis adjustments, relative quality and other factors. Basis swap agreements effectively fix the basis adjustments. The fair value of the natural gas basis swaps was a gain of ~~$5.4~~$25.7 million ~~at September~~June 30, ~~2020~~2021 and they settle monthly through December 2024.

At ~~September~~June 30, ~~2020,~~2021, we also had propane ~~basis~~spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. These contracts settle monthly ~~in 2020 and include a total volume of 312,500 barrels.~~through 2021. The fair value of these contracts was a ~~loss~~gain of ~~$529,000~~$376,000 at ~~September~~June 30, ~~2020.~~2021.

At ~~September~~June 30, ~~2020,~~2021, we ~~have~~are entitled to receive contingent ~~divestiture~~ consideration associated with the sale of our North Louisiana assets, ~~where we are entitled to receive contingent consideration,~~ annually through 2023, of up to ~~$90.0~~$75.0 million based on future achievement of certain natural gas and oil prices based on published indexes along with the realized NGLs prices of the buyer. The fair value at ~~September~~June 30, ~~2020~~2021 was a gain of ~~$15.4~~$37.4 million.

The following table shows the fair value of our derivatives and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at ~~September~~June 30, ~~2020.~~2021. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

Hypothetical Change in Fair Value

Hypothetical Change in Fair Value




Increase in Commodity Price of

Decrease in Commodity Price of


Fair Value


10%


25%

10%


25%

Swaps

$
(9,068
)

$
(85,281
)

$
(213,200
)

$
85,281

$
213,203

Collars

(14,169
)

(23,530
)

(62,083
)

22,437

56,852

Three-way collars

(39,883
)

(22,017
)

(57,582
)

19,770

44,403

Swaptions

(20,368
)

(23,315
)

(72,837
)

13,104

19,374

Basis swaps

4,871

2,587

6,469

(2,587
)

(6,469
)
Freight swaps

(1,388
)

664

1,659

(664
)

(1,659
)
Divestiture contingent consideration

15,420

4,480

11,570

(3,950
)

(8,890
)


				Hypothetical Change in Fair Value						Hypothetical Change in Fair Value
				Increase in Commodity Price of						Decrease in Commodity Price of
	Fair Value			10%			25%			10%			25%
Swaps	$	(161,808	)	$	(91,130	)	$	(227,825	)	$	91,130		$	227,825
Collars		(36,942	)		(28,066	)		(72,480	)		25,844			57,780
Three-way collars		(62,582	)		(33,999	)		(90,105	)		30,994			72,773
Swaptions		(26,414	)		(21,880	)		(56,376	)		17,073			25,740
Basis swaps		26,063			11,208			28,029			(11,194	)		(27,890	)
Freight swaps		37			346			866			(346	)		(866	)
Divestiture contingent consideration		37,350			6,810			15,380			(7,570	)		(18,770	)

Our commodity-based derivative contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified primarily among major investment grade financial institutions and we have master netting agreements with our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At ~~September~~June 30, ~~2020,~~2021, our derivative counterparties include ~~twenty-one~~nineteen financial institutions, of which all but five are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are primarily major investment grade financial institutions, the fair value of our derivative contracts has been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial. ~~Our~~Through March 31, 2021, our propane and butane sales from the Marcus Hook facility near Philadelphia ~~are~~were short-term and ~~are~~ to a single ~~purchaser. Our~~purchaser and our ethane sales ~~from Marcus Hook are~~were to a single international customer. As of April 1, 2021, other than limited spot sales, our propane and butane sales have been diversified among several purchasers and are for set terms of twelve to twenty-four months.

Interest Rate Risk

We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior and senior subordinated debt and variable rate bank debt. At ~~September~~June 30, ~~2020,~~2021, we had ~~$3.1~~$3.0 billion of debt outstanding. Of this amount, ~~$2.4~~$2.9 billion bears interest at fixed rates averaging ~~6.5%~~6.9%. Bank debt totaling ~~$706.0~~$121.0 million bears interest at floating rates, which was 2.2% on ~~September~~June 30, ~~2020.~~2021. On ~~September~~June 30, ~~2020,~~2021, the 30-day LIBOR Rate was

approximately 0.1%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on ~~September~~June 30, ~~2020,~~2021 would result in approximately ~~$7.1~~$1.2 million in additional annual interest expense.

ITEM 4. CONTROLS AND PROCEDURES

~~ITEM 4.~~

~~CONTROLS AND PROCEDURES~~

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2020~~2021 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in ~~Rules~~Exchange Act Rule 13a-15(f) ~~and 15d-15(f)~~ under the Exchange Act) during the ~~quarter~~three months ended ~~September~~June 30, ~~2020~~2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

~~ITEM 1.~~

~~LEGAL PROCEEDINGS~~

See Note 17 to our unaudited consolidated financial statements entitled “Commitments and Contingencies” included in Part I Item 1 above for a summary of our legal proceedings, such information being incorporated herein by reference.

Environmental Proceedings

Our subsidiary, Range Resources – Appalachia, ~~LLC,~~ was ~~ordered in January 2020~~notified by the ~~Pennsylvania Department of Environmental Protection (“DEP”),~~DEP that it intends to ~~take remedial actions pursuant to~~assess a civil penalty under the ~~Pennsylvania~~ Clean Streams Law and the 2012 Oil and Gas Act in connection with ~~respect to~~ one well in Lycoming ~~County. While Range has undertaken~~County and ordered us to conduct certain remedial ~~efforts~~work and monitoring to prevent methane and other substances from allegedly escaping the gas well into the surrounding environment including into soil, groundwater, streams and other surrounding water sources. DEP initially issued an order specifying its demands to the subsidiary on May 11, 2015. We appealed the order and the appeal was subsequently settled and discontinued whereupon we agreed to conduct certain, limited remedial work at the one well and continue monitoring water sources in the ~~past~~area and DEP did not assess any fines at that time. Thereafter, on January 13, 2020, DEP issued a new order regarding the ~~direction~~same one well in Lycoming County which set forth similar allegations and demands as set forth above. This new order was issued despite considerable data and evidence presented to DEP over the course of the ~~DEP regarding this well, Range has and continues to vigorously dispute the allegations~~investigation that this one well has not been nor is currently the source of methane in ~~surrounding groundwater and~~the environment nor any water ~~wells as contended by DEP. Range has considerable evidence to~~supplies, but rather the ~~contrary, including that~~ methane ~~had~~ existed in the ~~groundwater~~environment before the commencement of our operations. ~~Range~~We appealed the January 2020 order ~~to the Environmental Hearing Board. While we~~and intend to vigorously defend against the allegations ~~in the Order, nonetheless,~~asserted by DEP; however, a resolution of this matter may nonetheless result in ~~penalties~~monetary sanctions of more than ~~$100,000.~~$250,000.

From time to time, we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of ~~$100,000.~~$250,000.

ITEM 1A. RISK FACTORS

~~ITEM 1A.~~

~~RISK FACTORS~~

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, ~~2019 and disclosed in our first quarter 10-Q for the quarter ended March 31,~~ 2020.

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

~~The following table provides information about purchases by Range during the~~During second quarter ~~ended September~~2021, we did not purchase any shares. Through June 30, ~~2020 of equity securities that are registered pursuant to Section 12 of the Securities Exchange Act of 1934:~~

~~Period~~	~~Total Number of Shares Purchased~~	~~Average Price Paid Per Share~~	~~Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs~~	~~Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (a)~~

~~7/1/20 – 7/31/20~~	—	~~$ —~~	—	~~$ 70,099,593~~
~~8/1/20 – 8/31/20~~	—	—	—	~~$ 70,099,593~~
~~9/1/20 – 9/30/20~~	—	—	—	~~$ 70,099,593~~
~~Total~~	—	~~$ —~~	—

^(a)~~In October 2019, we announced a $100.0 million share repurchase program. As of September 30, 2020,~~2021, we have repurchased 10.0 million shares of common stock at a cost of approximately ~~$29.7~~$29.9 million, excluding fees and ~~commissions.~~commissions, as part of a $100.0 million share repurchase program announced in October 2019. Shares repurchased as of ~~September~~June 30, ~~2020~~2021 are held as treasury stock.

4944

ITEM 6. EXHIBITS

Exhibit index


Exhibit Number		~~EXHIBITS~~

~~Exhibit index~~

Exhibit Number		Exhibit Description
	3.1
	~~3.1~~	Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of ~~Third~~First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

	3.2	Amended and Restated By-laws of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2016)

	~~10.1~~31.1*	Sixth Amended and Restated Credit Agreement, dated April 13, 2018 among Range Resources Corporation (as borrower) and JPMorgan Chase Bank, N.A. as administrative agent and the other lenders and agents party thereto ~~(incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 16, 2018)~~

	~~10.2~~	First Amendment to the Sixth Amended and Restated Credit Agreement, dated as of October 18, 2019 among Range Resources Corporation (as borrower) and JPMorgan Chase Bank, N.A. as administrative agent and the other lenders and agents party thereto ~~(incorporated by reference to Exhibit 10.2 to our Form 10-Q (File No. 001-12209) as filed with the SEC on October 23, 2019)~~

	~~10.3~~	Second Amendment to the Sixth Amended and Restated Credit Agreement, dated as of March 27, 2020 among Range Resources Corporation (as borrower) and JPMorgan Chase Bank N.A. as administrative agent and the other lenders and agents party thereto ~~(incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 1, 2020)~~

	~~10.4~~	~~Range Resources Corporation 2019 Equity-Based Compensation Plan~~ ~~(incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (File No. 001-12209) as filed with the SEC on May 16, 2019)~~

	~~10.5~~	~~Range Resources Corporation Amended and Restated 2019 Equity & Based Compensation Plan~~ ~~(incorporated by reference to Exhibit A to our Definitive Proxy Statement for the 2020 Annual Meeting of Stockholders. (File No. 001-12209, as filed with the SEC on April 3, 2020)~~

	~~10.6~~	~~Purchase Agreement, dated as of August 18, 2020, by and among Range Resources Corporation and JPMorgan Securities LLC (as representative of the several initial purchasers identified therein)~~ ~~(incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (File No. 001-12209) as filed with the SEC on August 19, 2020)~~

	31.1*	Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2*	Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1**	Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2**	Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	101. INS*	Inline XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document

	101. SCH*	Inline XBRL Taxonomy Extension Schema

	101. CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit Number			~~Exhibit Description~~
		101. DEF*
	101. DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document

	101. LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document

	101. PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document

	104 *		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

*	~~filed herewith~~

**	~~furnished herewith~~

51* filed herewith

** furnished herewith

~~SIGNATURES~~

SIGNATURES

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

Date: ~~October 29, 2020~~July 26, 2021


RANGE RESOURCES CORPORATION

By:		/s/ MARK S. SCUCCHI
		Mark S. Scucchi
		Senior Vice President and Chief Financial Officer

Date: ~~October 29, 2020~~July 26, 2021


RANGE RESOURCES CORPORATION

By:		/s/ DORI A. GINN
		Dori A. Ginn
		Senior Vice President – Controller and Principal Accounting Officer

~~Delaware~~		~~34-1312571~~
Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200 Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

~~Large Accelerated Filer~~	☑	~~Accelerated Filer~~		☐

~~Non-Accelerated~~Large Accelerated Filer	☐		Accelerated Filer		

Non-Accelerated Filer		Smaller Reporting Company		☐
		Emerging Growth Company		☐


		Page
PART I – FINANCIAL INFORMATION
ITEM 1.	Financial Statements:
	Consolidated Balance Sheets (Unaudited)		3
	Consolidated Statements of Operations (Unaudited)		4
	Consolidated Statements of Comprehensive ~~(Loss) Income~~Loss (Unaudited)		5
	Consolidated Statements of Cash Flows (Unaudited)		6
	Consolidated Statements of Stockholders’ Equity (Unaudited)		7
	Notes to Consolidated Financial Statements (Unaudited)		9
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		3028
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		4541
ITEM 4.	Controls and Procedures		4844
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings		4844
ITEM 1A.	Risk Factors		4844
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		4944
ITEM 6.	Exhibits		5045

	SIGNATURES		5246

	September 30,			December 31,
	2020			2019
Assets	(Unaudited)
Current assets:
Cash and cash equivalents	$	517		$	546
Accounts receivable, less allowance for doubtful accounts of $3,004 and $8,784		182,698			272,900
Derivative assets		5,264			136,848
Other current assets		20,668			17,508
Total current assets		209,147			427,802
Derivative assets		15,062			706
Natural gas properties, successful efforts method		9,646,901			10,213,737
Accumulated depletion and depreciation		(3,975,930	)		(4,172,702	)
		5,670,971			6,041,035
Other property and equipment		79,632			102,083
Accumulated depreciation and amortization		(75,203	)		(96,708	)
		4,429			5,375
Operating lease right-of-use assets		43,763			62,053
Other assets		69,526			75,432
Total assets	$	6,012,898		$	6,612,403

Liabilities
Current liabilities:
Accounts payable	$	84,554		$	155,341
Asset retirement obligations		2,103			2,393
Accrued liabilities		310,376			356,392
Accrued interest		31,680			39,299
Derivative liabilities		53,408			13,119
Divestiture contract obligation		102,665			0
Current maturities of long-term debt		45,334			0
Total current liabilities		630,120			566,544
Bank debt		696,172			464,319
Senior notes		2,328,585			2,659,844
Senior subordinated notes		17,375			48,774
Deferred tax liabilities		62,319			160,196
Derivative liabilities		31,503			949
Deferred compensation liabilities		69,927			64,070
Operating lease liabilities		32,238			41,068
Asset retirement obligations and other liabilities		98,359			259,151
Divestiture contract obligation		383,796			0
Total liabilities		4,350,394			4,264,915
Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, 0ne issued and outstanding		0			0
Common stock, $0.01 par, 475,000,000 shares authorized, 256,232,010 issued at September 30, 2020 and 251,438,936 issued at December 31, 2019		2,562			2,514
Common stock held in treasury, 10,005,795 shares at September 30, 2020 and 1,808,133 shares at December 31, 2019		(30,131	)		(7,236	)
Additional paid-in capital		5,679,197			5,659,832
Accumulated other comprehensive loss		(574	)		(788	)
Retained deficit		(3,988,550	)		(3,306,834	)
Total stockholders’ equity		1,662,504			2,347,488
Total liabilities and stockholders’ equity	$	6,012,898		$	6,612,403


	June 30,			December 31,
	2021			2020
Assets	(Unaudited)
Current assets:
Cash and cash equivalents	$	464		$	458
Accounts receivable, less allowance for doubtful accounts of $393 and $3,004		299,590			252,642
Derivative assets		25,865			23,332
Other current assets		13,793			13,408
Total current assets		339,712			289,840
Derivative assets		21,483			16,680
Natural gas properties, successful efforts method		9,973,112			9,751,114
Accumulated depletion and depreciation		(4,239,713	)		(4,064,305	)
		5,733,399			5,686,809
Other property and equipment		80,503			79,878
Accumulated depreciation and amortization		(76,677	)		(75,717	)
		3,826			4,161
Operating lease right-of-use assets		52,291			63,581
Other assets		78,722			75,865
Total assets	$	6,229,433		$	6,136,936

Liabilities
Current liabilities:
Accounts payable	$	144,454		$	132,421
Asset retirement obligations		6,689			6,689
Accrued liabilities		358,640			348,333
Accrued interest		76,909			54,742
Derivative liabilities		249,277			26,707
Divestiture contract obligation		89,950			92,593
Current maturities of long-term debt		0			45,356
Total current liabilities		925,919			706,841
Bank debt		114,025			693,123
Senior notes		2,922,632			2,329,745
Senior subordinated notes		0			17,384
Deferred tax liabilities		134,000			135,267
Derivative liabilities		22,367			9,746
Deferred compensation liabilities		121,010			81,481
Operating lease liabilities		32,770			43,155
Asset retirement obligations and other liabilities		87,336			91,157
Divestiture contract obligation		346,113			391,502
Total liabilities		4,706,172			4,499,401
Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, 0ne issued and outstanding		0			0
Common stock, $0.01 par, 475,000,000 shares authorized, 259,778,494 issued at June 30, 2021 and 256,353,887 issued at December 31, 2020		2,598			2,563
Common stock held in treasury, 10,004,683 shares at June 30, 2021 and 10,005,795 shares at December 31, 2020		(30,085	)		(30,132	)
Additional paid-in capital		5,699,240			5,684,268
Accumulated other comprehensive loss		(338	)		(479	)
Retained deficit		(4,148,154	)		(4,018,685	)
Total stockholders’ equity		1,523,261			1,637,535
Total liabilities and stockholders’ equity	$	6,229,433		$	6,136,936


☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019			2021			2020			2021			2020

Revenues and other income:
Natural gas, NGLs and oil sales	$	381,553		$	474,754		$	1,162,907		$	1,709,987		$	621,855		$	349,258		$	1,225,202		$	781,354
Derivative fair value (loss) income		(124,690	)		74,676			102,182			208,190			(249,683	)		(6,303	)		(307,562	)		226,872
Brokered natural gas, marketing and other		42,482			73,015			104,722			303,834			62,550			33,591			143,114			62,240
Total revenues and other income		299,345			622,445			1,369,811			2,222,011			434,722			376,546			1,060,754			1,070,466
Costs and expenses:
Direct operating		19,515			35,276			75,944			102,484			19,758			24,394			37,408			56,429
Transportation, gathering, processing and compression		268,108			295,912			831,748			899,786			282,844			278,875			557,174			563,640
Production and ad valorem taxes		6,106			7,805			20,682			29,004			8,414			5,557			13,039			14,576
Brokered natural gas and marketing		47,967			79,938			118,752			313,360			69,004			38,161			141,339			70,785
Exploration		8,086			11,013			23,190			27,333			5,028			8,027			10,566			15,104
Abandonment and impairment of unproved properties		5,667			16,202			16,604			41,631			2,177			5,524			5,206			10,937
General and administrative		38,153			41,047			118,695			138,316			40,242			38,288			78,246			80,542
Exit and termination costs		521,633		819				533,525			3,025			(15,946	)		10,297			(2,232	)		11,892
Deferred compensation plan		6,237			(8,871	)		10,287			(16,432	)		35,462			12,587			55,273			4,050
Interest		47,999			46,997			144,141			150,261			57,287			48,624			114,165			96,142
Loss (gain) on early extinguishment of debt		7,821			(2,985	)		(14,093	)		(2,985	)		63			(8,991	)		98			(21,914	)
Depletion, depreciation and amortization		96,167			137,751			303,779			417,974			90,629			104,626			179,012			207,612
Impairment of proved properties and other assets		1,955		0				78,955		0
Loss (gain) on the sale of assets		9,230			36,341			(112,443	)		30,663
Impairment of proved properties														0			0			0			77,000
(Gain) loss on the sale of assets														(2,506	)		426			(646	)		(121,673	)
Total costs and expenses		1,084,644			697,245			2,149,766			2,134,420			592,456			566,395			1,188,648			1,065,122
(Loss) income before income taxes		(785,299	)		(74,800	)		(779,955	)		87,591			(157,734	)		(189,849	)		(127,894	)		5,344
Income tax (benefit) expense:
Income tax expense (benefit):
Current	0				4,079			(366	)		4,079			2,569			(3	)		2,737			(366	)
Deferred		(105,251	)		(51,298	)		(97,947	)		(5,511	)		(3,831	)		(22,263	)		(1,310	)		7,098
		(105,251	)		(47,219	)		(98,313	)		(1,432	)		(1,262	)		(22,266	)		1,427			6,732
Net (loss) income	$	(680,048	)	$	(27,581	)	$	(681,642	)	$	89,023
Net (loss) income per common share:
Net loss													$	(156,472	)	$	(167,583	)	$	(129,321	)	$	(1,388	)
Net loss per common share:
Basic	$	(2.83	)	$	(0.11	)	$	(2.82	)	$	0.35		$	(0.65	)	$	(0.70	)	$	(0.53	)	$	(0.01	)
Diluted	$	(2.83	)	$	(0.11	)	$	(2.82	)	$	0.35		$	(0.65	)	$	(0.70	)	$	(0.53	)	$	(0.01	)
Dividends paid per common share	0			$	0.02		0			$	0.06
Weighted average common shares outstanding:
Basic		239,895			248,082			241,770			247,878			242,592			239,472			242,377			242,717
Diluted		239,895			248,082			241,770			248,823			242,592			239,472			242,377			242,717

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019

Net (loss) income	$	(680,048	)	$	(27,581	)	$	(681,642	)	$	89,023
Other comprehensive loss:
Postretirement benefits:
Actuarial (loss) gain		—			(12	)		7			(37	)
Amortization of prior service costs		92			92			277			276
Income tax expense		(22	)		(20	)		(70	)		(59	)
Total comprehensive (loss) income	$	(679,978	)	$	(27,521	)	$	(681,428	)	$	89,203

Fiscal Year 2020					Common									Accumulated

Fiscal Year 2021																								Common									Accumulated
					stock			Additional						other										stock			Additional						other
	Common stock				held in			paid-in			Retained			comprehensive						Common stock				held in			paid-in			Retained			comprehensive
	Shares		Par value		treasury			capital			deficit			loss			Total			Shares		Par value		treasury			capital			deficit			loss			Total
Balance as of December 31, 2019		251,439	$	2,514	$	(7,236	)	$	5,659,832		$	(3,306,834	)	$	(788	)	$	2,347,488
Issuance of common stock		4,246		42		—			(1,406	)		—			—			(1,364	)
Stock-based compensation expense		—		—		—			5,963			—			—			5,963
Treasury stock		—		—		(22,514	)		(33	)		—			—			(22,547	)
Other comprehensive income		—		—		—			—			—			73			73
Net income		—		—		—			—			144,975			—			144,975
Balance as of March 31, 2020		255,685		2,556		(29,750	)		5,664,356			(3,161,859	)		(715	)		2,474,588
Balance as of December 31, 2020																					256,354	$	2,563	$	(30,132	)	$	5,684,268		$	(4,018,685	)	$	(479	)	$	1,637,535
Issuance of common stock		376		4		—			854			—			—			858			3,218		33		0			(7,654	)		0			0			(7,621	)
Issuance of common stock upon vesting of PSUs		19		—		—			74			(74	)		—			—			—		0		0			148			(148	)		0			0
Stock-based compensation expense		—		—		—			7,312			—			—			7,312			—		0		0			6,713			0			0			6,713
Treasury stock		—		—		(444	)		—			—			—			(444	)		—		0		47			(47	)		0			0			0
Other comprehensive income		—		—		—			—			—			71			71			—		0		0			0			0			70			70
Net loss		—		—		—			—			(146,569	)		—			(146,569	)
Balance as of June 30, 2020		256,080		2,560		(30,194	)		5,672,596			(3,308,502	)		(644	)		2,335,816
Net income																					—		0		0			0			27,151			0			27,151
Balance as of March 31, 2021																					259,572		2,596		(30,085	)		5,683,428			(3,991,682	)		(409	)		1,663,848
Issuance of common stock		152		2		—			73			—			—			75			206		2		0			9,289			0			0			9,291
Stock-based compensation expense		—		—		—			6,591			—			—			6,591			—		0		0			6,523			0			0			6,523
Treasury stock		—		—		63			(63	)		—			—			—			—		0		0			0			0			0			0
Other comprehensive income		—		—		—			—			—			70			70			—		0		0			0			0			71			71
Net loss		—		—		—			—			(680,048	)		—			(680,048	)		—		0		0			0			(156,472	)		0			(156,472	)
Balance as of September 30, 2020		256,232	$	2,562	$	(30,131	)	$	5,679,197		$	(3,988,550	)	$	(574	)	$	1,662,504

Balance as of June 30, 2021																					259,778	$	2,598	$	(30,085	)	$	5,699,240		$	(4,148,154	)	$	(338	)	$	1,523,261

Fiscal Year 2019					Common									Accumulated
					stock			Additional						other
	Common stock				held in			paid-in			Retained			comprehensive
	Shares		Par value		treasury			capital			deficit			loss			Total
Balance as of December 31, 2018		249,520	$	2,495	$	(391	)	$	5,628,447		$	(1,570,462	)	$	(658	)	$	4,059,431
Issuance of common stock		1,628		17		—			(2,396	)		—			—			(2,379	)
Issuance of common stock upon vesting of PSUs		—		—		—			4			(4	)		—			—
Stock-based compensation expense		—		—		—			9,155			—			—			9,155
Cash dividends paid ($0.02 per share)		—		—		—			—			(5,023	)		—			(5,023	)
Other comprehensive income		—		—		—			—			—			60			60
Net income		—		—		—			—			1,419			—			1,419
Balance as of March 31, 2019		251,148		2,512		(391	)		5,635,210			(1,574,070	)		(598	)		4,062,663
Issuance of common stock		206		2		—			1,547			—			—			1,549
Issuance of common stock upon vesting of PSUs		—		—		—			1			(1	)		—			—
Stock-based compensation expense		—		—		—			7,822			—			—			7,822
Cash dividends paid ($0.02 per share)		—		—		—			—			(5,026	)		—			(5,026	)
Other comprehensive income		—		—		—			—			—			60			60
Net income		—		—		—			—			115,185			—			115,185
Balance as of June 30, 2019		251,354		2,514		(391	)		5,644,580			(1,463,912	)		(538	)		4,182,253
Issuance of common stock		71		—		—			1,170			—			—			1,170
Stock-based compensation expense		—		—		—			7,318			—			—			7,318
Cash dividends paid ($0.02 per share)		—		—		—			—			(5,028	)		—			(5,028	)
Treasury stock issuance		—		—		63			(63	)		—			—			—
Other comprehensive income		—		—		—			—			—			60			60
Net loss		—		—		—			—			(27,581	)		—			(27,581	)
Balance as of September 30, 2019		251,425	$	2,514	$	(328	)	$	5,653,005		$	(1,496,521	)	$	(478	)	$	4,158,192

	September 30, 2020			December 31, 2019
	(in thousands)
Natural gas properties:
Properties subject to depletion	$	8,784,788		$	9,345,557
Unproved properties		862,113			868,180
Total		9,646,901			10,213,737
Accumulated depletion and depreciation		(3,975,930	)		(4,172,702	)
Net capitalized costs	$	5,670,971		$	6,041,035


	June 30, 2021			December 31, 2020
	(in thousands)
Natural gas properties:
Properties subject to depletion	$	9,109,425		$	8,891,348
Unproved properties		863,687			859,766
Total		9,973,112			9,751,114
Accumulated depletion and depreciation		(4,239,713	)		(4,064,305	)
Net capitalized costs	$	5,733,399		$	5,686,809


		September 30, 2020			December 31, 2019
Bank debt (2.2%)	$	706,000		$	477,000
Senior notes:
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		532,335			741,531
5.00% senior notes due 2022		169,589			511,886
5.75% senior notes due 2021		25,496			374,139
5.875% senior notes due 2022		48,528			297,617
9.25% senior notes due 2026		850,000			0
Other senior notes due 2022		490			590
Total senior notes		2,376,438			2,675,763
Senior subordinated notes:
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		9,730			19,054
5.75% senior subordinated notes due 2021		19,896			22,214
Total senior subordinated notes		37,338			48,980
Total debt		3,119,776			3,201,743
Unamortized premium		525			3,013
Unamortized debt issuance costs		(32,835	)		(31,819	)
Total debt net of debt issuance costs		3,087,466			3,172,937
Less current maturities of long-term debt ^(a)		(45,334	)		0
Total long-term debt	$	3,042,132		$	3,172,937


	Outstanding Principal Amount
5.75% senior notes due 2021	$	25,496
5.875% senior notes due 2022	$	490
5.75% senior subordinated notes 2021	$	19,896
5.00% senior subordinated notes 2022	$	9,730
5.00% senior subordinated notes 2023	$	7,712


			~~Emerging Growth Company~~		☐

	Nine Months Ended September 30, 2020			Year Ended December 31, 2019
Beginning of period	$	251,076		$	312,754
Liabilities incurred		1,890			4,063
Acquisitions		123			0
Liabilities settled		(3,068	)		(5,953	)
Disposition of wells		(176,747	)		(82,576	)
Accretion expense		6,207			15,658
Change in estimate		2,573			7,130
End of period		82,054			251,076
Less current portion		(2,103	)		(2,393	)
Long-term asset retirement obligations	$	79,951		$	248,683

		September 30, 2020
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	10,083	$	(9,159	)	$	924
	–three-way collars		680		(680	)		0
	–basis swaps		6,620		(3,263	)		3,357
Crude oil	–swaps		14,065		(13,566	)		499
NGLs	–C3 propane spread swaps		2,974		(2,974	)		0
	–C3 propane swaps		101		0			101
	–NC4 normal butane swaps		17		(17	)		0
	−C5 natural gasoline swaps		25		0			25
Freight	−swaps		19		(19	)		0
Divestiture contingent consideration			15,420		0			15,420
		$	50,004	$	(29,678	)	$	20,326

		December 31, 2019
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	134,364	$	(2,913	)	$	131,451
	–swaptions		0		(1,325	)		(1,325	)
	–basis swaps		10,766		(1,092	)		9,674
Crude oil	–swaps		3,893		(4,794	)		(901	)
	–swaptions		0		(1,597	)		(1,597	)
	–calls		0		(349	)		(349	)
NGLs	–C3 propane spread swaps		1,913		(1,913	)		0
	–NC4 normal butane swaps		167		0			167
	–C5 natural gasoline swaps		60		(127	)		(67	)
Freight	–swaps		1,529		(1,028	)		501
		$	152,692	$	(15,138	)	$	137,554

		December 31, 2019
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(1,657	)	$	2,913	$	1,256
	–swaptions		(2,594	)		1,325		(1,269	)
	–basis swaps		(1,371	)		1,092		(279	)
Crude oil	–swaps		(4,814	)		4,794		(20	)
	–swaptions		(2,254	)		1,597		(657	)
	–calls		(349	)		349		0
NGLs	–C3 propane spread swaps		(16,040	)		1,913		(14,127	)
	–C5 natural gasoline swaps		(127	)		127		0
Freight	–swaps		0			1,028		1,028
		$	(29,206	)	$	15,138	$	(14,068	)

	As of September 30, 2020
Balance at December 31, 2019	$	(4,848	)
Total losses:
Included in earnings		(19,124	)
Settlements, net		2,769
Transfers in and/or out of Level 3		835
Balance at September 30, 2020	$	(20,368	)

	Year Ended December 31, 2019
	Fair Value	Impairment
North Louisiana	$ 370,500	$ 1,093,531


	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2019	881,573		$	11.70
Units granted ^(a)	777,847			2.33
Vested ^(b)	(101,150	)		15.32
Forfeited ^(c)	(259,711	)		2.33
Outstanding at September 30, 2020	1,298,559		$	5.37

	Nine Months Ended September 30,
	2020			2019
Risk-free interest rate		1.4	%		2.4	%
Expected annual volatility		65	%		46	%
Grant date fair value per unit	$	3.85		$	11.34


	Exit Costs			Termination Costs
Balance at December 31, 2019	$	0		$	4,692
Accrued severance costs		0			5,638
Accrued contract obligations		490,115			0
Accretion of discount		7,252			0
Payments		(959	)		(6,170	)
Balance at September 30, 2020	$	496,408		$	4,160

	Three Months Ended September 30, 2020			Nine Months Ended September 30, 2020
Beginning balance		10,007,327			1,808,133
Rabbi trust shares distributed/sold		(1,532	)		(2,338	)
Shares repurchased		0			8,200,000
Ending balance		10,005,795			10,005,795


Remainder 2020	$	212,604
2021		849,807
2022		812,176
2023		779,226
2024		763,965
Thereafter		4,817,605
Total commitments	$	8,235,383
Accrued obligations (see also Note 14)	$	496,408

	Nine Months Ended September 30, 2020		Year Ended December 31, 2019
	(in thousands)
Acquisitions:
Acreage purchases	$	11,864	$	57,324
Development		283,354		666,984
Exploration:
Expense		22,296		35,117
Stock-based compensation expense		895		1,566
Gas gathering facilities:
Development		2,764		3,583
Subtotal		321,173		764,574
Asset retirement obligations		4,587		11,193
Total costs incurred	$	325,760	$	775,767

		Three Months Ended September 30,						Nine Months Ended September 30,
		2020			2019			2020			2019
Average natural gas differentials below NYMEX	$	(0.47	)	$	(0.25	)	$	(0.33	)	$	(0.18	)
Realized gains (losses) on basis hedging	$	0.05		$	(0.01	)	$	0.04		$	0.03

				Hypothetical Change in Fair Value						Hypothetical Change in Fair Value
				Increase in Commodity Price of						Decrease in Commodity Price of
	Fair Value			10%			25%			10%			25%
Swaps	$	(9,068	)	$	(85,281	)	$	(213,200	)	$	85,281		$	213,203
Collars		(14,169	)		(23,530	)		(62,083	)		22,437			56,852
Three-way collars		(39,883	)		(22,017	)		(57,582	)		19,770			44,403
Swaptions		(20,368	)		(23,315	)		(72,837	)		13,104			19,374
Basis swaps		4,871			2,587			6,469			(2,587	)		(6,469	)
Freight swaps		(1,388	)		664			1,659			(664	)		(1,659	)
Divestiture contingent consideration		15,420			4,480			11,570			(3,950	)		(8,890	)