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).

~~259,778,494~~269,797,334 Common Shares were outstanding on ~~July 23,~~April 22, ~~2021~~2022

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 ~~2020~~2021 Annual Report on Form 10-K.

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

~~Pennsylvania. In first six months 2020, we completed the sale of our shallow legacy assets in northwestern Pennsylvania for proceeds of $1.0~~ ~~million. Based upon the receipt of approval from state governmental authorities of a change in operatorship during first quarter, we recognized a pretax gain of $122.5million primarily due to the elimination of the asset retirement obligation associated with these properties.~~

Weighted average common shares outstanding-basic for ~~second~~first quarter ~~2021~~2022 excludes ~~7.1~~6.2 million shares of restricted stock held in our deferred compensation plan compared to ~~6.4~~6.2 million shares in ~~second~~first quarter ~~2020~~2021 (although all awards are issued and outstanding upon grant). ~~Weighted average common shares outstanding-basic for first six months 2021 excludes~~ ~~6.6~~ ~~million shares of restricted stock compared to~~ ~~4.8~~ ~~million for first six months 2020.~~ Due to our ~~net~~ loss ~~for second~~in first quarter ~~and first six months 2021 and 2020,~~2022, we excluded all ~~equity-grants~~outstanding equity grants from the computation of diluted loss per share because the effect would have been anti-dilutive to the computations. For first quarter 2021, equity grants of 88,000 were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of our common shares and would be anti-dilutive to the computation. Non-vested restricted stock and performance based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

~~(a)~~ ~~Includes capitalized asset retirement costs and the associated accumulated amortization.~~

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,~~Through March 31, 2022, we ~~are~~were 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. 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 ~~June 30, 2021.~~March 31, 2022.

~~(11)~~(10) 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) for natural gas and crude oil or Mont Belvieu for NGLs, approximated a net loss of $~~287.7~~989.8 million at ~~June 30, 2021.~~March 31, 2022. These contracts expire monthly through December ~~2022.~~2024. The following table sets forth our commodity-based derivative

volumes by year as of ~~June 30, 2021,~~March 31, 2022, 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)

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


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
			Swap			Sold Put	Floor		Ceiling
Natural Gas (1)
2022	Swaps	496,655 Mmbtu/day	$	3.10
2022	Collars	278,073 Mmbtu/day					$	3.31	$	3.72
2022	Three-way Collars	217,745 Mmbtu/day			$	2.30	$	2.84	$	3.45
2023	Swaps	260,000 Mmbtu/day	$	3.41
2023	Collars	234,932 Mmbtu/day					$	3.28	$	4.31
2023	Three-way Collars	149,863 Mmbtu/day			$	2.28	$	3.30	$	4.28
2024	Collars	200,000 Mmbtu/day					$	3.00	$	4.26

Crude Oil
2022	Swaps	6,833 bbls/day	$	61.90
2023	Swaps	5,123 bbls/day	$	71.39

NGLs (C2-Ethane)
April-June 2022	Swaps	2,681 bbls/day	$	0.41/gallon

NGLs (C3-Propane)
April-June 2022	Swaps	3,989 bbls/day	$	1.24/gallon

NGLs (NC4-Butane)
April-June 2022	Swaps	3,000 bbls/day	$	1.50/gallon

NGLs (C5-Natural Gasoline)
2022	Swaps	2,331 bbls/day	$	1.78/gallon
2022	Collars	1,530 bbls/day					$	1.77/gallon	$	1.88/gallon


(1)	We also sold natural gas call swaptions of 100,000 Mmbtu/day for 2023 at a weighted average price of $3.21 Mmbtu/day.

~~(1)~~ 13~~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~~.

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 ~~June 30, 2021,~~March 31, 2022, 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 ~~229,880,000~~187,405,000 Mmbtu. The fair value of these contracts was a gain of $~~25.7~~22.5 million at ~~June 30, 2021.~~

~~At June 30, 2021, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. The contracts settle monthly through~~March 31, 2022. ~~The fair value of these contracts was a gain of $376,000~~ ~~at June 30, 2021.~~

~~Freight Swap Contracts~~

In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at June 30, 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 and cover ~~10,000~~ ~~metric tons per month in third quarter 2021 and~~ ~~12,000~~ ~~metric tons for the remainder of 2021. The fair value of these contracts equal to a gain of $37,000~~ ~~at June 30, 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 $~~75.0~~45.5 million is based on future achievement of natural gas and oil prices based on published indexes and realized NGLs prices of the buyer 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~~three months ~~2021,~~2022, this fair value has increased $~~21.4~~8.1 ~~million.~~million for a fair value of $34.8 million as of March 31, 2022.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 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):


		June 30, 2021									March 31, 2022
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet				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	)	–basis swaps	$	27,129	$	(23,113	)	$	4,016
	–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	Divestiture contingent consideration		37,350		0			37,350		Divestiture contingent consideration		34,760		0			34,760
		$	80,636	$	(33,288	)	$	47,348			$	61,889	$	(23,113	)	$	38,776

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
)


		March 31, 2022
		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	$	(447,051	)	$	0	$	(447,051	)
	–swaptions		(45,871	)		0		(45,871	)
	–collars		(220,908	)		0		(220,908	)
	–three-way collars		(174,458	)		0		(174,458	)
	–basis swaps		(4,677	)		23,113		18,436
Crude oil	–swaps		(80,270	)		0		(80,270	)
NGLs	–C2 ethane swaps		(202	)		0		(202	)
	–C3 propane swaps		(2,048	)		0		(2,048	)
	–NC4 butane swaps		(1,640	)		0		(1,640	)
	–C5 natural gasoline swaps		(11,849	)		0		(11,849	)
	–C5 natural gasoline collars		(5,481	)		0		(5,481	)
		$	(994,455	)	$	23,113	$	(971,342	)

1514


		December 31, 2020									December 31, 2021
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet				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		–swaps	$	22,491	$	(18,111	)	$	4,380
	–collars		7,016		(2,329	)		4,687		–collars		12,378		(8,600	)		3,778
	–three-way collars		535		(6,139	)		(5,604	)	–three-way collars		12,234		(8,449	)		3,785
	–basis swaps		7,894		(3,502	)		4,392		–basis swaps		18,092		(10,487	)		7,605
Crude oil	–swaps		2,465		(829	)		1,636		–swaps		368		(2,153	)		(1,785	)
NGLs	–C3 propane spread swaps		4,863		(4,863	)		0		–C3 propane spread		4,153		(4,153	)		0
	–C3 propane collars		0		(107	)		(107	)	–C5 natural gasoline swaps		266		(363	)		(97	)
										–C5 natural gasoline collars		221		(221	)		0
Freight	–swaps		2,310		0			2,310		–swaps		114		(81	)		33
Divestiture contingent consideration	Divestiture contingent consideration		15,960		0			15,960		Divestiture contingent consideration		26,640		0			26,640
		$	74,602	$	(34,590	)	$	40,012			$	96,957	$	(52,618	)	$	44,339

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
)


		December 31, 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	$	(121,759	)	$	18,111	$	(103,648	)
	–swaptions		(11,149	)		0		(11,149	)
	–collars		(16,579	)		8,600		(7,979	)
	–three-way collars		(37,166	)		8,449		(28,717	)
	–calls		(61	)		0		(61	)
	–basis swaps		(2,064	)		10,487		8,423
Crude oil	–swaps		(27,252	)		2,153		(25,099	)
NGLs	–C3 propane spread		(4,030	)		4,153		123
	–C5 natural gasoline swaps		(2,048	)		363		(1,685	)
	–C5 natural gasoline collars		(1,493	)		221		(1,272	)
Freight	–swaps		0			81		81
		$	(223,601	)	$	52,618	$	(170,983	)

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


	Derivative Fair Value (Loss) Income												Derivative Fair Value (Loss) Income
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2021			2020			2021			2020			2022			2021
Commodity swaps	$	(172,566	)	$	5,484		$	(225,330	)	$	233,838		$	(521,355	)	$	(52,764	)
Swaptions		(19,268	)		(2,019	)		(16,612	)		(1,353	)		(34,723	)		2,657
Three-way collars		(53,705	)		(6,200	)		(52,832	)		(17,562	)		(179,926	)		873
Collars		(38,934	)		2,557			(52,222	)		2,557			(232,292	)		(13,288	)
Calls		0			(33	)		(775	)		242			(1,363	)		(775	)
Basis swaps		17,368			(5,180	)		19,523			16,163			22,515			2,155
Freight swaps		(38	)		(912	)		(704	)		(7,013	)		(33	)		(667	)
Divestiture contingent consideration		17,460			0			21,390			0			8,120			3,930
Total	$	(249,683	)	$	(6,303	)	$	(307,562	)	$	226,872		$	(939,057	)	$	(57,879	)

1615

~~(12)~~(11) 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.

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.

1716

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 June 30, 2021 using:												Fair Value Measurements at March 31, 2022 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				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 March 31, 2022
Trading securities held in the deferred compensation plans	Trading securities held in the deferred compensation plans	$	66,804	$	0		$	0		$	66,804		Trading securities held in the deferred compensation plans	$	71,184	$	0		$	0		$	71,184

Commodity price derivatives	–swaps		0		(161,808	)		0			(161,808	)	–swaps		0		(543,060	)		0			(543,060	)
	–collars		0		(31,128	)		(5,814	)		(36,942	)	–collars		0		(220,908	)		(5,481	)		(226,389	)
	–three-way collars		0		(62,582	)		0			(62,582	)	–three-way collars		0		(174,458	)		0			(174,458	)
	–basis swaps		0		26,063			0			26,063		–basis swaps		0		22,452			0			22,452
	–swaptions		0		0			(26,414	)		(26,414	)	–swaptions		0		0			(45,871	)		(45,871	)
Derivatives–freight swaps			0		37			0			37
Divestiture contingent consideration	Divestiture contingent consideration		0		37,350			0			37,350		Divestiture contingent consideration		0		34,760			0			34,760

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, 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 December 31, 2021
Trading securities held in the deferred compensation plans		$	69,606	$	0		$	0		$	69,606

Commodity price derivatives	–swaps		0		(127,934	)		0			(127,934	)
	–calls		0		(61	)		0			(61	)
	–collars		0		(4,201	)		(1,272	)		(5,473	)
	–three-way collars		0		(24,932	)		0			(24,932	)
	–basis swaps		0		16,151			0			16,151
	–swaptions		0		0			(11,149	)		(11,149	)
Derivatives	–freight swaps		0		114			0			114
Divesture contingent consideration			0		26,640			0			26,640

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 ~~June 30, 2021,~~March 31, 2022, 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. If exercised, the swaption contract becomes a swap treated consistently with our fixed-price swaps. In addition to our swaptions in Level 3 at ~~June 30, 2021,~~March 31, 2022, 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. However, the subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our derivatives in Level 3 and is considered a significant unobservable input. ~~For~~At March 31, 2022, for our swaptions, we used a weighted average implied volatility of 2336% for natural ~~gas and~~ 31~~% for crude oil.~~gas. We also utilized a range of implied volatilities from 2944% to 5077% for our NGLs collars with a weighted average implied volatility of 3656%. 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):

1817


	As of ~~June 30,~~March 31, ~~2021~~2022
Balance at December 31, ~~2020~~2021	$	(~~13,836~~12,420	)
Total losses:
Included in earnings		(~~7,627~~28,105	)
Additions		(~~20,515~~12,320	)
Settlements		~~5,176~~1,493
Transfers out of Level 3		~~4,574~~0
Balance at ~~June 30, 2021~~March 31, 2022	$	(~~32,228~~51,352	)

Divestiture Contingent Consideration. In August 2020, we completed the sale of our North Louisiana assets where we are entitled to receive contingent consideration 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.

Trading securities.Our trading securities held in the deferred compensation plan are accounted for using the ~~mark-to-market~~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 ~~second~~first quarter ~~2021,~~2022, interest and dividends were $~~118,000~~115,000 and the mark-to-market adjustment was a ~~gain of $2.3~~ ~~million compared to interest and dividends of $124,000~~ ~~and a mark-to-market gain of $7.6~~ ~~million in second quarter 2020. For first six months 2021, interest and dividends were $227,000~~ ~~and the mark-to-market adjustment was a gain~~loss of $4.3 million compared to interest and dividends of $~~227,000~~109,000 and a mark-to-market ~~adjustment of a loss~~gain of $~~3.0~~2.0 million in first ~~six months 2020.~~quarter 2021.

~~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. In first quarter 2020, we recognized impairment charges of $~~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. These assets were sold in third quarter 2020. There were 0 ~~proved property impairment charges in second quarter or first six months 2021.~~

Fair Values – Reported

The following presents the carrying amounts and the fair values of our financial instruments as of ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 (in thousands):

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
)


	March 31, 2022						December 31, 2021
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and basis swaps	$	4,016		$	4,016		$	17,699		$	17,699
Divestiture contingent consideration		34,760			34,760			26,640			26,640
Marketable securities (a)		71,184			71,184			69,606			69,606
(Liabilities):
Commodity swaps, collars and basis swaps		(971,342	)		(971,342	)		(170,983	)		(170,983	)
Bank credit facility (b)		0			0			0			0
5.00% senior notes due 2022 (b)		(169,589	)		(169,628	)		(169,589	)		(171,488	)
5.875% senior notes due 2022 (b)		(48,528	)		(48,528	)		(48,528	)		(48,955	)
5.00% senior notes due 2023 (b)		(532,335	)		(536,769	)		(532,335	)		(543,471	)
4.875% senior notes due 2025 (b)		(750,000	)		(759,735	)		(750,000	)		(776,153	)
9.25% senior notes due 2026 (b)		0			0			(850,000	)		(916,929	)
8.25% senior notes due 2029 (b)		(600,000	)		(657,480	)		(600,000	)		(669,648	)
4.75% senior notes due 2030 (b)		(500,000	)		(496,795	)		0			0
Deferred compensation plan (c)		(237,657	)		(237,657	)		(165,395	)		(165,395	)


(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 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 that we incurred in conjunction with the sale of our North Louisiana assets.

Concentrations of Credit Risk

As of ~~June 30, 2021,~~March 31, 2022, 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 assurances are obtained as deemed necessary to limit our risk of loss. Our allowance for uncollectable receivables was $~~393,000~~568,000 at ~~June 30, 2021 compared to $3.0~~ ~~million at~~both March 31, 2022 and December 31, ~~2020.~~2021. 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 ~~June~~March ~~30,~~31, ~~2021,~~2022, our derivative counterparties include 1915 financial institutions, of which all but 5 are secured lenders in our bank credit facility. At ~~June 30, 2021,~~March 31, 2022, our net derivative ~~asset~~liability includes a net receivable of $~~9.7~~3.6 million from ~~four~~three of these counterparties that are not participants in our bank credit facility and an aggregate net payable of $~~5.6~~1.6 million to ~~one~~two 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.

~~(13)~~(12) STOCK-BASED COMPENSATION PLANS

Stock-Based Awards

We have 2 active equity-based stock plans: our Amended and Restated 2005 Equity-Based Incentive Compensation Plan and our Amended and Restated 2019 Equity-Based Compensation 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 June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2021		2020		2021		2020		2022		2021
Direct operating expense	$	340	$	434	$	667	$	884	$	349	$	327
Brokered natural gas and marketing expense		443		168		893		581		519		450
Exploration expense		362		372		748		702		452		386
General and administrative expense		9,382		9,179		18,787		17,208		11,573		9,405
Total stock-based compensation expense	$	10,527	$	10,153	$	21,095	$	19,375	$	12,893	$	10,568

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 one year vesting for non-employee directors. 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%~~-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~~are measured against internal ~~debt-adjusted~~ performance metrics ~~(Production Per Share Awards or PS-PSUs and Reserves Per Share Awards or RS-PSUs)~~ and 1 based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Awards or 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~~In first quarter ~~2021.~~2022, the performance conditions will be measured against internal metrics of net debt (total debt less cash on hand) and emission intensity performance.

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 range from 0 to 200% based on performance achieved, which is determined by the Compensation Committee and (2) the value of our common stock on the vesting date. Dividend equivalents may accrue during the performance period and are paid in stock at the end of the performance period. The performance period is for ~~the TSR-PSUs is~~ three years. Prior to 2021, the performance period for the ~~PS/RS-PSUs~~internal performance metrics was based on annual performance targets earned over a three-year period.

Restricted Stock – Equity Awards

In first ~~six~~three months ~~2021,~~2022, we granted ~~2.3~~1.4 million restricted stock Equity Awards to employees at an average grant date fair value of $~~10.20~~18.47 which generally vest over a three-year period compared to ~~4.5~~2.3 million at an average grant date fair value of $~~3.42~~10.20 in first ~~six~~three months ~~2020.~~2021. We recorded compensation expense for these outstanding awards of $~~10.3~~5.9 million in first ~~six~~three months ~~2021~~2022 compared to $~~10.0~~5.2 million in the same period of ~~2020.~~2021. Restricted stock Equity Awards are not issued to employees until such time as they are vested. Employees do not have the option to receive cash.

Restricted Stock – Liability Awards

In first ~~six~~three months 2022, we granted 602,000 shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $20.42 which generally vest at the end of a three-year period. In first three months 2021, we granted 1.2 million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $~~9.30~~9.29 ~~which~~with vesting generally ~~vest~~ at the end of a three-year ~~period and~~ ~~97,000~~ ~~shares were granted to non-employee directors at an average price of $11.99~~ ~~with vesting at the end of a~~ ~~one-year~~ ~~period. In first six months 2020, we granted~~ ~~3.3~~ ~~million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $3.03~~ ~~with vesting generally over a~~ ~~three-year~~ ~~period and~~ ~~217,000~~ ~~were granted to non-employee directors at an average price of $5.38~~ ~~with vesting at the end of a~~ ~~one-year~~ period. We recorded compensation expense for these Liability Awards of $~~5.7~~3.6 million in first ~~six~~three months ~~2021~~2022 compared to $~~5.4~~2.9 million in first ~~six~~three months ~~2020.~~2021. 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 ~~June 30, 2021:~~March 31, 2022:

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, 2021		2,674,777		$	7.39		796,629		$	6.49
Granted		1,380,660			18.47		601,983			20.42
Vested		(600,158	)		9.00		(299,862	)		10.62
Forfeited		(15,379	)		9.63		0			0
Outstanding at March 31, 2022		3,439,900		$	11.55		1,098,750		$	13.00

Stock-Based Performance Units

Internal Performance Metric Awards. These awards vest at the end of the three-year performance period. The performance metrics are set by the Compensation 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.~~2021 and 2022. The following is a summary of our non-vested internal performance awards outstanding at ~~June 30,~~March 31, ~~2021:~~2022:


	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2020		1,099,102		$	5.92
Outstanding at December 31, 2021							1,095,355		$	7.80
Units granted (a)		303,231			9.81		153,089			20.38
Vested and issued (b)		(306,978	)		12.20		(243,482	)		9.64
Forfeited		0			0		0			0
Outstanding at June 30, 2021		1,095,355		$	7.80
Outstanding at March 31, 2022							1,004,962		$	9.27

~~(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.~~

~~(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~~
(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 2022 were to our CEO, CFO and COO only.
(b)
For the awards issued during 2019, the aggregate payout was approximately 116% of target with a positive performance adjustment of 158,793 shares.

We recorded compensation expense of $~~1.8~~1.7 million in first ~~six~~three months ~~2021~~2022 compared to expense of $~~1.8~~ ~~million~~740,000 in first ~~six~~three months ~~2020.~~2021.

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 ~~six~~three months ~~2021~~2022 and ~~2020:~~2021:


	Six Months Ended June 30,						Three Months Ended March 31,
	2021			2020			2022			2021
Risk-free interest rate		0.2	%		1.4	%		1.4	%		0.2	%
Expected annual volatility		75	%		65	%		68	%		75	%
Grant date fair value per unit	$	12.58		$	3.85		$	27.90		$	12.58

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


	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2020		1,249,524		$	9.55
Outstanding at December 31, 2021							1,147,994		$	7.60
Units granted (a)		223,687			12.58		111,828			27.90
Vested and issued (b)		(325,217	)		18.51		(314,152	)		11.34
Forfeited		0			0		0			0
Outstanding at June 30, 2021		1,147,994		$	7.60
Outstanding at March 31, 2022							945,670		$	8.76


(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 granted in 2019 where the return on our common stock was 127% and therefore, the performance multiple and actual payout was 183%.

~~(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.~~21

~~(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~~%.

We recorded TSR-PSUs compensation expense of $~~1.2~~773,000 ~~million~~ in first ~~six~~three months ~~2021~~2022 compared to $~~1.5~~595,000 ~~million~~ in the same period of ~~2020.~~2021. Fair value is amortized over the performance period with no adjustment to the expense recorded for actual targets achieved.

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~~70,000 of estimated prior service costs amortized from accumulated other comprehensive income into general and administrative expense in ~~both the three months ended June 30, 2021 and 2020 and~~first quarter 2022 compared to approximately $~~185,000~~90,000 ~~amortized~~ in ~~both the six months ended June 30, 2021 and 2020.~~first quarter 2021. Those employees that qualify for this retirement health care plan are required to provide reasonable notice of retirement and provide one year of service after an equity grant date to be fully vested in the grant.

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. 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 $~~35.5~~73.3 million in ~~second~~first quarter ~~2021~~2022 compared to a mark-to-market loss of $~~12.6~~ ~~million in second quarter 2020. We recorded mark-to-market loss of $55.3~~19.8 million in first ~~six months 2021 compared to a loss of $4.1~~ ~~million in first six months 2020.~~quarter 2021. The Rabbi Trust held ~~6.5~~6.7 million shares (~~5.0~~5.6 million of which were vested) of Range stock at ~~June 30, 2021~~March 31, 2022 compared to ~~6.1~~6.2 million shares (~~5.0~~5.4 million of which were vested) at December 31, ~~2020.~~2021.

~~(14)~~(13) 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 sheets. In first ~~six~~three months ~~2021,~~2022, we recorded accretion expense of $~~25.0~~ ~~million. In second quarter 2021, we recorded a net favorable adjustment of $28.2~~11.0 million ~~to reduce this obligation due to a reduction of certain contractual payments~~ compared to ~~those originally estimated and a change to our estimated drilling plans~~$13.0 million in the same period of the ~~buyer.~~prior year. The estimated discounted divestiture contract obligation was $~~436.1~~398.9 million at ~~June 30, 2021.~~March 31, 2022.

In second quarter 2020, we negotiated capacity releases on certain transportation pipelines in Pennsylvania effective May 31, 2020 and extending through the remainder of the contract. ~~We recorded termination costs of $10.4~~ ~~million which represented the discounted present value of our remaining obligation to the third-party.~~ The estimated remaining discounted obligation for these transportation capacity releases as of ~~June 30, 2021~~March 31, 2022 was $~~8.4~~6.8 million.

Termination Costs

~~In first quarter 2020, we completed the sale of our shallow legacy assets in northwestern Pennsylvania and we recorded $1.6~~ ~~million of severance costs which is primarily related to the sale of these assets.~~The following summarizes our exit and termination costs for the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ (in thousands):

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


	Three Months Ended March 31,
	2022		2021
Severance costs	$	0	$	509
Transportation contract capacity releases (accretion of discount)		161		210
Divestiture contract obligation (accretion of discount)		10,954		12,995
	$	11,115	$	13,714

The following details the accrued exit and termination cost liability activity for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 (in thousands):


	Exit Costs (1)			Termination Costs		��
Balance at December 31, 2021	$	423,742		$	10
Accretion of discount		11,115			0
Payments		(29,115	)		0
Balance at March 31, 2022	$	405,742		$	10

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.~~	Includes the divestiture contract obligation and the transportation contract capacity release obligation.

~~(15)~~(14) 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 ~~2020:~~2021:


	Six Months Ended June 30, 2021		Year Ended December 31, 2020			Three Months Ended March 31, 2022			Year Ended December 31, 2021
Beginning balance		246,348,092		249,630,803			249,792,908			246,348,092
Restricted stock grants		1,286,737		3,390,358			601,983			1,293,892
Restricted stock units vested		1,483,436		1,226,473			1,787,286			1,493,341
Performance stock units issued		640,468		279,420			590,940			640,468
Performance stock dividends		13,966		18,700			1,843			13,966
Treasury shares		1,112		(8,197,662	)		(598,889	)		3,149
Ending balance		249,773,811		246,348,092			252,176,071			249,792,908

Stock Repurchase Program

In ~~October~~ 2019, ~~our Board~~the board of ~~Directors authorized~~directors approved a stock purchase program to acquire up to $100.0 million of our outstanding stock. In early 2022, board authorized an additional repurchase of up to $430.0 million of our outstanding common stock ~~repurchase program.~~for an aggregate available amount at that time of $500.0 million. 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. In first quarter 2022, we repurchased 600,000 shares at an aggregate cost of $16.2 million. The following is a schedule of the change in treasury shares for the three ~~and six~~ months ended ~~June 30, 2021:~~March 31, 2022:

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


	Three Months Ended March 31, 2022
Beginning balance		10,002,646
Rabbi trust shares distributed/sold		(1,111	)
Shares repurchased		600,000
Ending balance		10,601,535

(15) SUPPLEMENTAL CASH FLOW INFORMATION


	Three Months Ended March 31,
	2022			2021
	(in thousands)
Net cash provided from operating activities included:
Income taxes paid to taxing authorities	$	(2,307	)	$	0
Interest paid		(86,615	)		(64,100	)
Non-cash investing and financing activities included:
Increase in asset retirement costs capitalized		1,377			761
(Increase) decrease in accrued capital expenditures		12,606			(5,850	)

(16) ~~SUPPLEMENTAL CASH FLOW INFORMATION~~

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 or investigations 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 ~~June 30, 2021,~~March 31, 2022, liabilities for remediation were not material. We are not aware of any environmental claims existing as of ~~June 30, 2021~~March 31, 2022 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.

On March 4, 2021 a ~~punitive~~putative 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~~sought to represent a class of Range stockholders who purchased or acquired stock from April 29, 2016 to February 10, 2021. This lawsuit ~~has~~had been transferred to the U.S. District Court for the Northern District of Texas (Fort Worth Division)~~. The lawsuit claims~~ and claimed that Range misclassified certain wells as inactive rather than having plugged the wells and that such alleged misclassification affected the determination of our asset retirement obligation accrual. ~~The lawsuit claims that~~On March 31, 2022, the ~~disclosure~~court granted our motion to dismiss and each claim was dismissed with prejudice. Plaintiffs have until May 2 to file an appeal of the March 31 ruling and dismissal. Additionally, on January 20, 2022, a $~~294,000~~ ~~agreed penalty that we paid~~derivative action styled as Lewis v. Ventura et al. was filed under seal in the Northern District of Texas (Case No. 4-22CV-051-0) asserting similar allegations as the Jacobowitz matter. We maintain the same views as to the Pennsylvania Department of Environmental Protection (DEP) in connection with the DEP’s investigation of our 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’ discoverymerits of the ~~alleged misrepresentations. We maintain that~~Lewis matter as the ~~factual allegations~~Jacobowitz matter 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.~~this matter and seek its dismissal.

(~~18) SUSPENDED EXPLORATORY WELL COSTS~~

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in 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 following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2021 (in thousands):~~

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

~~(19)~~(17) Costs Incurred for Property Acquisition, Exploration and Development (a)

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


	Three Months Ended March 31, 2022		Year Ended December 31, 2021
	(in thousands)
Acquisitions:
Acreage purchases	$	8,574	$	21,942
Development		107,987		381,753
Exploration:
Drilling		0		6,329
Expense		4,247		22,048
Stock-based compensation expense		452		1,507
Gas gathering facilities:
Development		7		3,402
Subtotal		121,267		436,981
Asset retirement obligations		1,377		18,634
Total costs incurred	$	122,644	$	455,615


(a)	Includes costs incurred whether capitalized or expensed.

~~(a)~~ ~~Includes costs incurred whether capitalized or expensed.~~

2724

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

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (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 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, NGLs and ~~NGLs~~oil and on our ability to economically find, develop, acquire, produce and market ~~natural gas and NGLs~~these reserves. Commodity prices have been and are expected to remain volatile. Our primary near-term focus includes the following:

•

operate safely and efficiently;

•

target ~~limiting~~ capital spending at or below operating cash flow;

•

reduce ~~direct~~ emissions and target ~~net zero direct~~net-zero Scope 1 and Scope 2 greenhouse gas emissions by year-end 2025;

•

achieve competitive returns on investments;

•

~~preserve~~manage liquidity and further improve financial strength;

•

focus on organic opportunities through disciplined capital investments;

•

improve operational efficiencies and economic returns;

•

attract and retain quality employees; and

•

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

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 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;~~reinvestment; 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.

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 and are affected by many factors outside of our control.~~ Natural gas, NGLs and oil benchmarks increased in ~~second~~first quarter ~~2021~~2022 when compared to the same period ~~in 2020~~of 2021 and, ~~also in the first six months 2021 when compared to the same period in 2020. As~~as a result, we experienced ~~increased~~a significant increase in price realizations. 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 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 balanced oil supply and demand environment. Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions to combat the virus are expected to directly impact the

~~recovery of world economic growth and the demand for oil.~~ As we continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and gas and the uncertainty associated with recovering oil demand, future monetary policy and governmental policies aimed at ~~redirecting fossil fuel consumption~~transitioning towards lower carbon energy, we expect prices for some or all of the commodities we produce to remain volatile. NYMEX natural gas futures have shown strong improvements based on market expectations that associated gas-related activity in oil basins and dry gas basin activity will show modest rates of growth compared with the past due to capital discipline, core inventory exhaustion and infrastructure constraints. In addition, the global energy crisis further highlighted the low cost and low emissions shale gas resource base in North America, supporting continued strong structural demand growth for U.S. LNG exports and domestic industrial gas demand. Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions

~~Throughout~~25

or other medical advances to combat the ~~COVID-19 pandemic, we leveraged our emergency response protocols~~virus may impact the recovery of world economic growth and ~~business continuity plan to help manage our operations~~the demand for oil, natural gas and workforce. Much of our workforce worked remotely for a significant period of time since the pandemic began. During June 2021, the majority of our corporate workforce returned to the office. Working remotely did not negatively impact our ability to maintain operations and did not cause us to incur significant additional expenses.NGLs.

The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2021		2020		2021		2020		2022		2021
Benchmarks:
Average NYMEX prices (a)
Natural gas (per mcf)	$	2.84	$	1.72	$	2.76	$	1.83	$	4.89	$	2.69
Oil (per bbl)		65.96		27.09		62.06		38.03		94.93		58.06
Mont Belvieu NGLs composite (per gallon) (b)		0.63		0.30		0.62		0.32		0.97		0.61

~~(a)~~


(a)	Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange (“NYMEX”).
(b)	~~(b)~~Based on our estimated NGLs product composition per barrel.

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

Consolidated Results of Operations

Overview of ~~Second~~First Quarter ~~2021~~2022 Results

~~Our financial results are significantly impacted by commodity prices.~~ For ~~second~~first quarter ~~2021,~~2022, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a ~~75%~~108% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) somewhat offset by slightly lower production volumes when compared to the same quarter of ~~2020.~~2021. Daily production averaged 2.1 Bcfe in ~~second~~both the first quarter ~~2021~~2022 and 2021.Given the significant increase in commodity prices, our derivative fair value loss, which includes the non-cash fair value adjustment related to our derivatives, was $939.1 million compared to ~~2.3 Bcfe~~$57.9 million in the same ~~period~~quarter of the prior ~~year due to the sale of~~year. For additional information on our ~~North Louisiana properties in third quarter 2020. In addition, net operating costs were lower when compared to the same period of 2020.~~derivative fair value loss, see page 30.

During ~~second~~first quarter ~~2021,~~2022, we recognized a net loss of ~~$156.5~~$456.8 million, or ~~$0.65~~$1.86 per diluted common share compared to a net ~~loss~~income of ~~$167.6~~$27.2 million, or ~~$0.70~~$0.11 per diluted common share during ~~second~~first quarter ~~2020.~~2021. The ~~improvement~~lower net income in ~~our net loss for second~~first quarter ~~2021~~2022 compared to ~~the second~~first quarter ~~2020~~2021 includes significantly higher ~~realized prices, lower net operating costs and a favorable divestiture contract obligation adjustment offset by reduced~~ derivative fair value ~~income~~loss (or the non-cash fair value adjustment related to our derivatives) due to higher commodity prices, ~~and~~ higher deferred compensation ~~expense.~~expense and a loss on early extinguishment of debt partially offset by higher natural gas, NGLs and oil sales also due to higher commodity prices.

Our ~~second~~first quarter ~~2021~~2022 financial and operating performance included the following results:

•

reduced total debt by $350.0 million with cash on hand and cash flow;

•

reduced future interest expense through debt reduction combined with refinancing a portion of 9.25% senior notes due 2026 with 4.75% senior notes due 2030;

•

cash flow from operating activities increased $297.2 million from first quarter 2021;

•

ended the first quarter 2022 with $112.9 million of cash on hand;

•

revenue from the sale of natural gas, NGLs and oil increased ~~78%~~71% from the same period of ~~2020~~2021 with a ~~99%~~72% increase in average realized prices (before cash settlements on our derivatives) partially offset by slightly lower production volumes;

•

revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased ~~24%~~59% from the same period of ~~2020;~~2021;

•

direct operating expense per mcfe was ~~9% lower than~~$0.11 in first quarter 2022 compared to $0.09 in the same period of ~~2020 (see discussion on page 34);~~2021 due to higher water handling and higher contract labor and service costs;

•

general and administrative expense per mcfe increased 15% from same quarter 2021 primarily due to higher stock-based compensation and higher salaries and benefits; and

•

reduced ~~our~~ depletion, depreciation and amortization (“DD&A”) rate per mcfe by 4%2% from the same period of ~~2020; and~~



~~reduced debt by $66.3 million with cash flow from operations.~~2021.

Our cash flow from operating activities in second quarter 2021 was $174.2 million, an increase of $95.4 million from second quarter 2020. Second quarter 2021 cash flow from operating activities included significantly higher realized prices and lower net operating costs compared to second quarter 2020.

2926

~~Overview of First Six months 2021 Results~~

For first six months 2021, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 50% increase in net realized prices (average prices including all derivatives settlements and third-party transportation costs paid by us) somewhat offset by lower production volumes when compared to the same period of 2020. Daily production average 2.1 Bcfe in first six months 2021 compared to 2.3 Bcfe in the same period of 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 2020.

During first six months 2021, we recognized a net loss of $129.3 million, or $0.53 per diluted common share compared to a net loss of $1.4 million, or $0.01 per diluted common share, during the same period of 2020. The increase in our net loss for first six months 2021 from first six months 2020 is primarily due to reduced derivative fair value income (or the non-cash fair value adjustment related to our derivatives), a lower gain on asset sales and higher deferred compensation plan expense partially offset by significantly higher realized prices, lower net operating costs, lower proved property impairment and lower DD&A expense.

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



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;



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



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



~~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);~~



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



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



~~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 ~~six months 2021~~quarter 2022 was ~~$283.4~~$406.4 million, an increase of ~~$80.2~~$297.2 million from first ~~six months 2020. First six months~~quarter 2021 ~~cash flow from operating activities included~~with significantly higher realized prices ~~and lower net operating costs~~when compared to first quarter 2021 partially offset by ~~the impact of negative working capital due to higher commodity prices.~~slightly lower production volumes.

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 ~~second~~first quarter ~~2021,~~2022, natural gas, NGLs and oil sales increased ~~78%~~71% compared to ~~second~~first quarter ~~2020~~2021 with a ~~99%~~72% increase in average realized prices (before cash settlements on our derivatives) partially offset by a 10% reduction in production volumes. In first six months 2021, natural gas, NGLs and oil sales increased 57% compared to first six months 2020 with a 75% increase in average realized prices partially offset by a 10%1% reduction in production volumes. The following table illustrates the primary components of natural gas, NGLs ~~oil~~ and ~~condensate~~oil sales for the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ (in thousands):


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended March 31,
	2021		2020		Change		%			2021		2020		Change		%			2022		2021		Change		%
Natural gas, NGLs and oil sales
Natural gas	$	321,565	$	214,207	$	107,358		50	%	$	657,366	$	467,456	$	189,910		41	%	$	629,923	$	335,801	$	294,122		88	%
NGLs		255,533		124,383		131,150		105	%		485,941		267,622		218,319		82	%		338,369		230,408		107,961		47	%
Oil		44,757		10,668		34,089		320	%		81,895		46,276		35,619		77	%		64,059		37,138		26,921		72	%
Total natural gas, NGLs and oil sales	$	621,855	$	349,258	$	272,597		78	%	$	1,225,202	$	781,354	$	443,848		57	%	$	1,032,351	$	603,347	$	429,004		71	%

Our production is determined by drilling success which offsets the natural decline of our natural gas and oil reserves through ~~production and asset sales. Second quarter 2020 production volumes from our North Louisiana properties were~~

~~approximately 179.2 Mmcfe per day and were 172.6 mcfe per day for first six months 2020. These assets were sold in third quarter 2020.~~production. Our production for the three ~~and six~~ months ended ~~June 30,~~March 31, ~~2021~~2022 and ~~2020~~2021 is set forth in the following table:


	Three Months Ended June 30,										Six Months Ended June 30,										Three Months Ended March 31,
	2021		2020		Change			%			2021		2020		Change			%			2022		2021		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	)%		131,250,337		130,328,741		921,596			1	%
NGLs (bbls)		9,153,411		9,716,261		(562,850	)		(6	)%		17,896,355		19,349,296		(1,452,941	)		(8	)%		8,453,445		8,742,944		(289,499	)		(3	)%
Crude oil (bbls)		777,067		720,125		56,942			8	%		1,535,058		1,588,422		(53,364	)		(3	)%		730,462		757,991		(27,529	)		(4	)%
Total (mcfe) (b)		191,469,799		213,745,898		(22,276,099	)		(10	)%		378,804,150		422,514,482		(43,710,332	)		(10	)%		186,353,779		187,334,351		(980,572	)		(1	)%

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	)%		1,458,337		1,448,097		10,240			1	%
NGLs (bbls)		100,587		106,772		(6,185	)		(6	)%		98,875		106,315		(7,440	)		(7	)%		93,927		97,144		(3,217	)		(3	)%
Crude oil (bbls)		8,539		7,913		626			8	%		8,481		8,728		(247	)		(3	)%		8,116		8,422		(306	)		(4	)%
Total (mcfe) (b)		2,104,064		2,348,856		(244,792	)		(10	)%		2,092,841		2,321,508		(228,667	)		(10	)%		2,070,598		2,081,493		(10,895	)		(1	)%

~~(a)~~


(a)	Represents volumes sold regardless of when produced.
(b)	~~(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 ~~second~~first quarter ~~2021~~2022 was ~~$1.56~~$3.23 per mcfe compared to ~~$0.89 per mcfe in second quarter 2020. Our average realized price received (including all derivative settlements and third-party transportation costs) during first six months 2020 was~~ $1.55 ~~per mcfe compared to $1.03~~ per mcfe in first ~~six months 2020.~~quarter 2021. 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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ are shown below:

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
%


	Three Months Ended March 31,
	2022		2021		Change		%
Average Prices
Average realized prices (excluding derivative settlements):
Natural gas (per mcf)	$	4.80	$	2.58	$	2.22		86	%
NGLs (per bbl)		40.03		26.35		13.68		52	%
Crude oil and condensate (per bbl)		87.70		49.00		38.70		79	%
Total (per mcfe) (a)		5.54		3.22		2.32		72	%
Average realized prices (including all derivative settlements):
Natural gas (per mcf)	$	4.04	$	2.57	$	1.47		57	%
NGLs (per bbl)		38.57		22.82		15.75		69	%
Crude oil and condensate (per bbl)		58.46		39.59		18.87		48	%
Total (per mcfe) (a)		4.83		3.01		1.82		60	%
Average realized prices (including all derivative settlements and third-party transportation costs paid by Range):
Natural gas (per mcf)	$	2.82	$	1.33	$	1.49		112	%
NGLs (per bbl)		22.32		9.93		12.39		125	%
Crude oil and condensate (per bbl)		58.44		39.59		18.85		48	%
Total (per mcfe) (a)		3.23		1.55		1.68		108	%

~~(a)~~
(1)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.
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 June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2021			2020			2021			2020			2022			2021
Average natural gas differentials below NYMEX	$	(0.39	)	$	(0.30	)	$	(0.25	)	$	(0.26	)	$	(0.09	)	$	(0.11	)
Realized gains (losses) on basis hedging	$	0.01		$	(0.01	)	$	(0.01	)	$	0.04		$	0.12		$	(0.03	)

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
June 30,

Six Months Ended
June 30,

2020

Price
Variance

Volume
Variance

2021

2020

Price
Variance

Volume
Variance

2021

Natural gas

Price (per mcf)

$
1.42

$
1.02

$
—

$
2.44

$
1.57

$
0.94

$
—

$
2.51

Production (Mmcf)

151,127

—

(19,240
)

131,887

296,888

—

(34,672
)

262,216

Natural gas sales

$
214,207

$
134,630

$
(27,272
)

$
321,565

$
467,456

$
244,502

$
(54,592
)

$
657,366

Three Months Ended
June 30,

Six Months Ended
June 30,

2020

Price
Variance

Volume
Variance

2021

2020

Price
Variance

Volume
Variance

2021

NGLs

Price (per bbl)

$
12.80

$
15.12

$
—

$
27.92

$
13.83

$
13.32

$
—

$
27.15

Production (Mbbls)

9,716

—

(563
)

9,153

19,349

—

(1,453
)

17,896

NGLs sales

$
124,383

$
138,355

$
(7,205
)

$
255,533

$
267,622

$
238,415

$
(20,096
)

$
485,941

Three Months Ended
June 30,

Six Months Ended
June 30,

2020

Price
Variance

Volume
Variance

2021

2020

Price
Variance

Volume
Variance

2021

Crude oil

Price (per bbl)

$
14.81

$
42.79

$
—

$
57.60

$
29.13

$
24.22

$
—

$
53.35

Production (Mbbls)

720

—

57

777

1,588

—

(53
)

1,535

Crude oil sales

$
10,668

$
33,246

$
843

$
44,757

$
46,276

$
37,174

$
(1,555
)

$
81,895

Three Months Ended
June 30,

Six Months Ended
June 30,

2020

Price
Variance

Volume
Variance

2021

2020

Price
Variance

Volume
Variance

2021

Consolidated

Price (per mcfe)

$
1.63

$
1.62

$
—

$
3.25

$
1.85

$
1.38

$
—

$
3.23

Production (Mmcfe)

213,746

—

(22,276
)

191,470

422,514

—

(43,710
)

378,804

Total natural gas, NGLs and oil
sales

$
349,258

$
308,996

$
(36,399
)

$
621,855

$
781,354

$
524,681

$
(80,833
)

$
1,225,202


	Three Months Ended March 31,
	2021		Price Variance		Volume Variance		2022
Natural gas
Price (per mcf)	$	2.58	$	2.22	$	—	$	4.80
Production (Mmcf)		130,329		—		921		131,250
Natural gas sales	$	335,801	$	291,748	$	2,374	$	629,923

3228


	Three Months Ended March 31,
	2021		Price Variance		Volume Variance			2022
NGLs
Price (per bbl)	$	26.35	$	13.68	$	—		$	40.03
Production (Mbbls)		8,743		—		(290	)		8,453
NGLs sales	$	230,408	$	115,590	$	(7,629	)	$	338,369


	Three Months Ended March 31,
	2021		Price Variance		Volume Variance			2022
Crude oil
Price (per bbl)	$	49.00	$	38.70	$	—		$	87.70
Production (Mbbls)		758		—		(28	)		730
Crude oil sales	$	37,138	$	28,269	$	(1,348	)	$	64,059


	Three Months Ended March 31,
	2021		Price Variance		Volume Variance			2022
Consolidated
Price (per mcfe)	$	3.22	$	2.32	$	—		$	5.54
Production (Mmcfe)		187,334		—		(980	)		186,354
Total natural gas, NGLs and oil sales	$	603,347	$	432,162	$	(3,158	)	$	1,032,351

Transportation, gathering, processing and compression expense was ~~$282.8~~$297.8 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$278.9~~$274.3 million in ~~second~~first quarter ~~2020.~~2021. These third-party costs are higher in ~~second~~first quarter ~~2021~~2022 when compared to ~~second~~first quarter ~~2020~~2021 due to the impact of higher NGLs prices which ~~result~~results in 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 third quarter 2020.~~

Transportation, gathering, processing and compression expense was $557.2 million in first six months 2021 compared to $563.6 million in first six months 2020. These third-party costs are lower when compared to the same period of the prior year due to transportation capacity released in Pennsylvania and the impact of the sale of our North Louisiana 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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ on a per mcf and per barrel basis (in thousands, except for costs per unit):

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
)%


	Three Months Ended March 31,
	2022		2021		Change			%
Transportation, gathering, processing and compression
Natural gas	$	160,436	$	161,660	$	(1,224	)		(1	)%
NGLs		137,340		112,670		24,670			22	%
Oil		11		—		11			100	%
Total	$	297,787	$	274,330	$	23,457			9	%

Natural gas (per mcf)	$	1.22	$	1.24	$	(0.02	)		(2	)%
NGLs (per bbl)	$	16.25	$	12.89	$	3.36			26	%
Oil (per bbl)	$	0.02	$	—	$	0.02			100	%

Derivative fair value ~~(loss) income~~loss was ~~a loss of $249.7 million in second quarter 2021 compared to a loss of $6.3million in second quarter 2020. Derivative fair value loss was $307.6~~$939.1 million in first ~~six months 2021~~quarter 2022 compared to ~~income of $226.9~~$57.9 million in first ~~six months 2020.~~quarter 2021. 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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ (in thousands):

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


	Three Months Ended March 31,
	2022			2021
Derivative fair value loss per consolidated statements of operations	$	(939,057	)	$	(57,879	)

Non-cash fair value (loss) gain: (1)
Natural gas derivatives	$	(742,253	)	$	(12,120	)
Oil derivatives		(53,385	)		(8,069	)
NGLs derivatives		(18,290	)		(1,247	)
Freight derivatives		(114	)		(978	)
Divestiture contingent consideration		8,120			3,930
Total non-cash fair value (loss) gain (1)	$	(805,922	)	$	(18,484	)

Net cash payment on derivative settlements:
Natural gas derivatives	$	(99,458	)	$	(1,348	)
Oil derivatives		(21,359	)		(7,128	)
NGLs derivatives		(12,318	)		(30,919	)
Total net cash payment	$	(133,135	)	$	(39,395	)

(1)

~~(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.

Brokered natural gas, marketing and other revenue in ~~second~~first quarter ~~2021~~2022 was ~~$62.6~~$87.4 million compared to ~~$33.6~~$80.6 million in ~~second~~first quarter ~~2020~~2021 which is the result of significantly higher broker sales prices somewhat offset by lower broker sales volumes (volumes not related to our production). ~~Brokered natural gas, marketing and other revenue in first six months~~First quarter 2021 ~~was $143.1 million compared to $62.2 million in first six months 2020 which is the result of significantly higher broker sales volumes, higher broker sales prices and~~also includes $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 six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


	Three Months Ended June 30,										Six Months Ended June 30,										Three Months Ended March 31,
	2021		2020		Change			%			2021		2020		Change			%			2022		2021		Change			%
Direct operating expense	$	0.10	$	0.11	$	(0.01	)		(9	)%	$	0.10	$	0.13	$	(0.03	)		(23	)%	$	0.11	$	0.09	$	0.02			22	%
Production and ad valorem tax expense		0.04		0.03		0.01			33	%		0.03		0.03		—			—	%		0.04		0.02		0.02			100	%
General and administrative expense		0.21		0.18		0.03			17	%		0.21		0.19		0.02			11	%		0.23		0.20		0.03			15	%
Interest expense		0.30		0.23		0.07			30	%		0.30		0.23		0.07			30	%		0.25		0.30		(0.05	)		(17	)%
Depletion, depreciation and amortization expense		0.47		0.49		(0.02	)		(4	)%		0.47		0.49		(0.02	)		(4	)%		0.46		0.47		(0.01	)		(2	)%

Direct operatingexpense was ~~$19.8~~$20.3 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$24.4~~$17.7 million in ~~second~~first quarter ~~2020.~~2021. 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~~increased in ~~second~~first quarter ~~2021~~2022 primarily due to ~~the impact of the sale of our~~ higher ~~cost North Louisiana properties in third quarter 2020.~~water handling/hauling costs, higher contract labor and services and higher workover costs. Our production volumes decreased ~~10%~~1% in ~~second~~first quarter ~~2021.~~2022. We incurred ~~$1.7 million~~$881,000 of workover costs in ~~second~~first quarter ~~2021~~2022 compared to ~~$1.1million~~$659,000 in ~~second~~first quarter ~~2020.~~2021. On a per mcfe basis, direct operating expense was $0.11 in ~~second~~first quarter ~~2021 decreased 9%~~2022 compared to ~~$0.10 from $0.11~~$0.09 in the same ~~period of 2020 with the decrease primarily due to the impact of the sale of our North Louisiana properties.~~

Direct operating expense was $37.4 million in first six months 2021 compared to $56.4 million in the same period 2020. Our direct operating expenses decreased in first six months 2021 compared to the same periodquarter of the prior year due to ~~the impact of the sale of our~~ higher ~~cost North Louisiana properties in third quarter 2020~~water handling/hauling costs and lower workover costs. Our production volumes decreased 10% in first six months 2021. We incurred $2.4 million of workover costs in first six months 2021 compared to $5.6 million in first six months 2020. On a per mcfe basis, direct operating costs decreased 23% from $0.13 to $0.10 with the decrease due to the impact of the sale of our higher ~~cost North Louisiana properties.~~contract labor and services. The following table summarizes direct operating expense per mcfe for the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


	Three Months Ended June 30,										Six Months Ended June 30,										Three Months Ended March 31,
	2021		2020		Change			%			2021		2020		Change			%			2022		2021		Change		%
Direct operating
Lease operating expense	$	0.09	$	0.10	$	(0.01	)		(10	)%	$	0.09	$	0.12	$	(0.03	)		(25	)%	$	0.11	$	0.09	$	0.02		22	%
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	)%	$	0.11	$	0.09	$	0.02		22	%

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 ~~$8.4~~$6.6 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$2.7~~$4.6 million in ~~second~~first quarter ~~2020~~2021 due to 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, 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 $12,000 in second quarter 2021 compared to $2.8 million in second quarter 2020 with the decrease due to 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. Production and ad valorem taxes (excluding the impact fee) were $19,000 in first six months 2021 compared to $5.8 million in first six months 2020 with the decrease due to 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 six~~ months ended ~~June 30,~~March 31, ~~2021~~2022 and ~~2020:~~2021:


	Three Months Ended June 30,										Six Months Ended June 30,										Three Months Ended March 31,
	2021		2020		Change			%			2021		2020		Change			%			2022		2021		Change		%
Production and ad valorem taxes
Impact fee	$	0.04	$	0.02	$	0.02			100	%	$	0.03	$	0.02	$	0.01			50	%	$	0.04	$	0.02	$	0.02		100	%
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	$	—			—	%	$	0.04	$	0.02	$	0.02		100	%

General and administrative(G&A) expense was ~~$40.2~~$43.0 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$38.3~~$38.0 million in ~~second~~first quarter ~~2020.~~2021. The ~~second~~first quarter ~~2021~~2022 increase of ~~$1.9~~$5.0 million when compared to the same period of ~~2020~~2021 is primarily due to higher ~~legal and general office expenses including technology costs~~stock-based compensation expense of ~~$1.9~~$2.2 million, ~~and~~ higher employee benefit costs, including healthcare, of $1.1 million partially offset by lower legal settlements. At June 30, 2021, the number of G&A employees decreased 12% when compared to June 30, 2020. On a per mcfe basis, 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 $2.3 million when compared to the same period 2020 due to lower travel and~~ general office expenses including technology costs and ~~lower legal settlements partially offset by~~ higher ~~legal expenses.~~salaries and benefits. At March 31, 2022, the number of G&A employees decreased 1% when compared to March 31, 2021. On a per mcfe basis, first ~~six months 2021~~quarter 2022 G&A expense ~~increased 11% from~~was 15% higher than first ~~six months 2020~~quarter 2021 due to higher ~~legal~~stock-based compensation expense, higher general office expenses and ~~the impact of lower production volumes.~~higher salaries and benefits. The following table summarizes G&A expenses on a per mcfe basis for the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended March 31,
	2021		2020		Change		%			2021		2020		Change		%			2022		2021		Change		%
General and administrative
General and administrative	$	0.16	$	0.14	$	0.02		14	%	$	0.16	$	0.15	$	0.01		7	%	$	0.17	$	0.15	$	0.02		13	%
Stock-based compensation		0.05		0.04		0.01		25	%		0.05		0.04		0.01		25	%		0.06		0.05		0.01		20	%
Total general and administrative expense	$	0.21	$	0.18	$	0.03		17	%	$	0.21	$	0.19	$	0.02		11	%	$	0.23	$	0.20	$	0.03		15	%

Interest expensewas ~~$57.3~~$47.2 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$48.6~~$56.9 million in ~~second~~first quarter ~~2020. Interest expense was $114.2 million for first six months 2021 compared to $96.1 million for first six months 2020.~~2021. The following table presents information about interest expense per mcfe for the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


	Three Months Ended June 30,												Six Months Ended June 30,												Three Months Ended March 31,
	2021			2020			Change			%			2021			2020			Change			%			2022			2021			Change			%
Bank credit facility	$	0.02		$	0.04		$	(0.02	)		(50	)%	$	0.02		$	0.04		$	(0.02	)		(50	)%	$	0.02		$	0.02		$	—			—	%
Senior notes		0.27			0.18			0.09			50	%		0.27			0.18			0.09			50	%		0.22			0.27			(0.05	)		(19	)%
Amortization of deferred financing costs and other		0.01			0.01			—			—	%		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	%	$	0.25		$	0.30		$	(0.05	)		(17	)%
Average debt outstanding ($000’s)	$	3,146,680		$	3,306,517		$	(159,837	)		(5	)%	$	3,167,858		$	3,286,611		$	(118,753	)		(4	)%	$	2,782,406		$	3,189,035		$	(406,629	)		(13	)%
Average interest rate (a)		7.0	%		5.6	%		1.4	%		25	%		6.9	%		5.6	%		1.3	%		23	%		6.5	%		6.8	%		(0.3	)%		(4	)%


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

On an absolute basis, the ~~increase~~decrease in interest expense for ~~second~~first quarter ~~2021~~2022 from the same period of ~~2020~~2021 was primarily due to ~~higher~~lower overall average interest rates ~~partially offset by slightly~~and lower ~~overall~~ average outstanding debt balances. Average debt outstanding on the bank credit facility for ~~second~~first quarter ~~2021~~2022 was ~~$195.5~~$65.3 million compared to ~~$681.3~~$220.4 million in ~~second~~first quarter ~~2020~~2021 and the weighted average interest rate on the bank credit facility was ~~2.0%~~2.5% in ~~second~~first quarter ~~2021~~2022 compared to ~~2.7% in second quarter 2020.~~

On an absolute basis, the increase in interest expense for first six months 2021 from the same period 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 was $208.0 million for first six months 2021 compared to $600.6 million for first six months 2020 and the weighted average interest rates were 2.1%2.2% in first ~~six months 2021 compared to 2.9% in first six months 2020.~~quarter 2021.

Depletion, depreciation and amortization expense was ~~$90.6~~$85.6 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$104.6~~$88.4 million in ~~second~~first quarter ~~2020.~~2021. This decrease is due to a 4%2% decrease in depletion rates and a ~~10%~~1% decrease in production volumes. Depletion expense, the largest component of DD&A expense, was $0.45 per mcfe in first quarter 2022 compared to $0.46 per mcfe in ~~second~~first quarter ~~2021 compared to $0.48 per mcfe in second quarter 2020.~~2021. 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.~~

DD&A expense was $179.0 million in first six months 2021 compared to $207.6 million in the same period of 2020. This is due to a 4% decrease in depletion rates and a 10% decrease in production volumes. Depletion expense per mcfe was $0.46 per mcfe in first six months 2021 compared to $0.48 per mcfe in the same period of 2020. The following table summarizes DD&A expense per mcfe for the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:


	Three Months Ended June 30,										Six Months Ended June 30,										Three Months Ended March 31,
	2021		2020		Change			%			2021		2020		Change			%			2022		2021		Change			%
DD&A
Depletion and amortization	$	0.46	$	0.48	$	(0.02	)		(4	)%	$	0.46	$	0.48	$	(0.02	)		(4	)%	$	0.45	$	0.46	$	(0.01	)		(2	)%
Depreciation		—		—		—			—	%		—		—		—			—	%		—		—		—			—	%
Accretion and other		0.01		0.01		—			—	%		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	)%	$	0.46	$	0.47	$	(0.01	)		(2	)%

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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2021		2020		2021		2020		2022		2021
Direct operating expense	$	340	$	434	$	667	$	884	$	349	$	327
Brokered natural gas and marketing expense		443		168		893		581		519		450
Exploration expense		362		372		748		702		452		386
General and administrative expense		9,382		9,179		18,787		17,208		11,573		9,405
Total stock-based compensation	$	10,527	$	10,153	$	21,095	$	19,375	$	12,893	$	10,568

3632

Brokered natural gas and marketing expense was ~~$69.0~~$93.1 million in ~~second~~first quarter 2022 compared to $72.3 million in first quarter 2021 ~~compared to $38.2 million in second quarter 2020~~ due to higher commodity prices somewhat offset by lower broker purchase volumes (volumes not related to our production) and significantly higher commodity prices. Brokered natural gas and marketing was $141.3 million in first six months 2021 compared to $70.8 million in first six months 2020 due to significantly higher broker purchase volumes and significantly higher commodity prices.. The following table details our brokered natural gas, marketing and other net margin for the three ~~and six~~ months ended ~~June 30,~~March 31, ~~2021~~2022 and ~~2020~~2021 (in thousands):


	Three Months Ended June 30,												Six Months Ended June 30,												Three Months Ended March 31,
	2021			2020			Change			%			2021			2020			Change			%			2022			2021			Change			%
Brokered natural gas and marketing
Brokered natural gas sales	$	60,778		$	30,309		$	30,469			101	%	$	130,240		$	55,184		$	75,056			136	%	$	84,062		$	69,462		$	14,600			21	%
Brokered NGLs sales		722			1,006			(284	)		(28	)%		1,148			2,146			(998	)		(47	)%		1,640			426			1,214			285	%
Other marketing revenue(1)		1,050			2,276			(1,226	)		(54	)%		11,726			4,910			6,816			139	%		1,740			10,676			(8,936	)		(84	)%
Brokered natural gas purchases ~~(1)~~(2)		(65,668	)		(34,485	)		(31,183	)		(90	)%		(135,631	)		(63,372	)		(72,259	)		(114	)%		(89,194	)		(69,962	)		(19,232	)		(27	)%
Brokered NGLs purchases		(660	)		(1,721	)		1,061			62	%		(1,057	)		(2,812	)		1,755			62	%		(1,647	)		(398	)		(1,249	)		(314	)%
Other marketing expense		(2,676	)		(1,955	)		(721	)		(37	)%		(4,651	)		(4,601	)		(50	)		(1	)%		(2,282	)		(1,975	)		(307	)		(16	)%
Net brokered natural gas and marketing margin	$	(6,454	)	$	(4,570	)	$	(1,884	)		(41	)%	$	1,775		$	(8,545	)	$	10,320			121	%	$	(5,681	)	$	8,229		$	(13,910	)		(169	)%

~~(1)~~

(1)

(2)

The three months ended March 31, 2021 includes $8.8 million received as part of a capacity release agreement.

Includes transportation costs.

Exploration expense was ~~$5.0~~$4.7 million in ~~second~~first quarter ~~2021~~2022 compared to ~~$8.0~~$5.5 million in ~~second~~first quarter ~~2020~~2021 due to lower delay rentals and other expenses and lower personnel costs. Exploration expense was $10.6 million in first six months 2021 compared to $15.1 million in first six months 2020 due to lower delay rentals and other expenses and lower personnel costs.expense. The following table details our exploration expense for the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ (in thousands):


	Three Months Ended June 30,										Six Months Ended June 30,											Three Months Ended March 31,
	2021		2020		Change			%			2021			2020		Change			%			2022			2021			Change			%
Exploration
Delay rentals and other	$	3,516	$	5,762	$	(2,246	)		(39	)%	$	7,501		$	10,974	$	(3,473	)		(32	)%	$	2,943		$	3,985		$	(1,042	)		(26	)%
Personnel expense		1,120		1,893		(773	)		(41	)%		2,399			3,428		(1,029	)		(30	)%		1,305			1,279			26			2	%
Stock-based compensation expense		362		372		(10	)		(3	)%		749			702		47			7	%		452			386			66			17	%
Seismic		30		—		30			100	%		(83	)		—		(83	)		(100	)%		(1	)		(112	)		111			99	%
Total exploration expense	$	5,028	$	8,027	$	(2,999	)		(37	)%	$	10,566		$	15,104	$	(4,538	)		(30	)%	$	4,699		$	5,538		$	(839	)		(15	)%

Abandonment and impairment of unproved properties was ~~$2.2 million in second quarter 2021 compared to $5.5million in second quarter 2020. Abandonment and impairment of unproved properties was $5.2~~$2.0 million in first ~~six months 2021~~quarter 2022 compared to ~~$10.9~~$3.0 million in first ~~six months 2020.~~quarter 2021. Abandonment and impairment of unproved properties for ~~second~~first quarter ~~and first six months 2021~~ declined when compared to the same periods of ~~2020~~2021 due to lower estimated expirations in Pennsylvania.

Exit and termination costswas ~~a gain of $15.9~~$11.1 million in ~~second~~first quarter ~~2021~~2022 compared to ~~an expense of $10.3~~$13.7 million in ~~second~~first quarter ~~2020.~~2021. In ~~second~~first quarter ~~2021,~~2022, we recorded ~~$12.0~~$11.1 million accretion expense primarily related to retained liabilities for certain gathering, transportation and processing obligations extending until ~~2030. In addition, we recorded a gain~~2030 compared to accretion expense of ~~$28.2~~$13.2 million ~~to reduce our original estimate of these obligations due to payments being lower than our forecast and a change~~ in ~~our forecasted drilling plans~~the same quarter of 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.

prior year.

Deferred compensation plan expense was a loss of ~~$35.5~~$73.3 million in ~~second~~first quarter ~~2021~~2022 compared to a loss of ~~$12.6~~$19.8 million in ~~second~~first quarter ~~2020.~~2021. 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 ~~$10.33~~$17.83 at December 31, 2021 to $30.38 at March 31, ~~2021 to $16.76 at June 30, 2021.~~2022. In the same period of the prior year, our stock price increased from $2.28 at March 31, 2020 to $5.63 at June 30, 2020. During first six months 2021, deferred compensation was a loss of $55.3 million compared to a loss of $4.1 million in the same period of 2020. Our stock price increased from $6.70 at December 31, 2020 to ~~$16.76~~$10.33 at ~~June 30,~~March 31, 2021. ~~In the same period of the prior year, our stock price increased from $4.85 at December 31, 2019 to $5.63 at June 30, 2020.~~

Loss ~~(gain)~~ on early extinguishment of debt was a loss of ~~$63,000~~$69.2 million in ~~second~~first quarter ~~2021~~2022 compared to a ~~gain~~loss of ~~$9.0 million in second quarter 2020. In second quarter 2020, we repurchased~~$35,000 in the ~~open market certain~~same period of the prior year. In first quarter 2022, we announced a call for the redemption of $850.0 million of our ~~senior and senior subordinated notes at a discount and recognized a gain of $9.0 million. In January 2020, we purchased for cash $500.0 million aggregate principal amount of our 5.75%~~outstanding 9.25% senior notes due ~~2021~~2026. The redemption price equaled 106.938% of par plus accrued and ~~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.~~unpaid interest. We ~~recorded~~recognized a loss on early extinguishment of debt in first quarter ~~2020~~2022 of $17.5 million, net of transaction call premium costs and the expenses of the remaining deferred financing costs on the repurchased debt. The cash tender offer and early cash tender premium were financed from the issuance of our 9.25% senior notes. Also in first quarter 2020, we purchased in the open market $48.5 million principal amount of 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 $30.4$69.2 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 $77.0 million in first six months 2020. There were no proved property impairments in first six months 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 gain of $646,000 in first six months 2021 compared to a gain of $121.7 million in the same period of 2020. In second quarter 2021, we recorded an additional gain on the sale of our North Louisiana assets of $2.4 million primarily related to final closing adjustments. In first quarter 2021, we recorded an additional loss on the sale of our North Louisiana assets of $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) expensewas a benefit of ~~$1.3 million in second quarter 2021 compared to a benefit $22.3million in second quarter 2020. Income tax expense was $1.4~~$116.1 million in first ~~six months 2021~~quarter 2022 compared to ~~$6.7~~expense of $2.7 million in first ~~six months 2020.~~quarter 2021. The ~~2021~~2022 and ~~2020~~2021 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.~~facility and/or cash on hand. 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.~~prices and capital requirements. 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 ~~June 30, 2021,~~March 31, 2022, we have entered into derivative agreements covering ~~244.6~~295.9 Bcfe for the remainder of ~~2021 and 168.0~~2022, 246.6 Bcfe for ~~2022,~~2023 and 73.2 Bcfe for 2024, not including our basis swaps.

The following table presents sources and uses of cash and cash equivalents for the ~~six~~three months ended ~~June 30,~~March 31, 2022 and 2021 ~~and 2020~~ (in thousands):


	Six Months Ended June 30,						Three Months Ended March 31,
	2021			2020			2022			2021
Sources of cash and cash equivalents
Operating activities	$	283,435		$	203,268		$	406,414		$	109,252
Disposal of assets		195			1,071			349			8
Issuance of senior notes		600,000			550,000			500,000			600,000
Borrowing on credit facility		883,000			1,045,000			282,000			478,000
Other		30,572			17,288			10,033			2,774
Total sources of cash and cash equivalents	$	1,797,202		$	1,816,627		$	1,198,796		$	1,190,034

Uses of cash and cash equivalents
Additions to natural gas and oil properties	$	(205,923	)	$	(254,073	)	$	(90,104	)	$	(99,233	)
Repayment on credit facility		(1,464,000	)		(883,000	)		(282,000	)		(1,056,000	)
Acreage purchases		(15,917	)		(14,486	)		(12,599	)		(11,849	)
Additions to field service assets		(652	)		(1,851	)		(37	)		(487	)
Repayment of senior and senior subordinated notes		(63,324	)		(617,982	)		(850,000	)		—
Treasury stock purchases		—			(22,992	)		(16,199	)		—
Debt issuance costs		(8,591	)		(8,360	)		(6,817	)		(8,559	)
Other		(38,789	)		(13,861	)		(42,531	)		(13,915	)
Total uses of cash and cash equivalents	$	(1,797,196	)	$	(1,816,605	)	$	(1,300,287	)	$	(1,190,043	)

Sources of Cash and Cash Equivalents

Cash flows provided from operating activities in first ~~six~~three months ~~2021~~2022 was ~~$283.4~~$406.4 million compared to ~~$203.3~~$109.3 million in first ~~six~~three months ~~2020.~~2021. 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 increase in cash provided from operating activities from first ~~six~~three months ~~2020~~2021 to first ~~six~~three months ~~2021~~2022 reflects higher realized prices ~~and lower operating expenses~~ partially offset by ~~working capital cash outflow and~~ lower production volumes. As of ~~June 30, 2021,~~March 31, 2022, we have hedged more than ~~65%~~55% of our projected total production for the remainder of ~~2021,~~2022, with more than ~~75%~~65% of our projected natural gas production hedged. Net cash provided from operating activities was affected by a ~~10%~~1% 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 ~~six~~three months ~~2021~~2022 were negative ~~$73.7~~$77.4 million compared to a ~~positive $26.1~~negative $77.3 million for first ~~quarter 2020.~~three months 2021.

Issuance of senior notes in first three months 2022 includes the issuance of $500.0 million new 4.75% senior notes due 2030.

Uses of Cash and Cash Equivalents

Additions to natural gas and oil properties for first ~~six~~three months ~~2021~~2022 were consistent with expectations relative to our ~~$425.0 million 2021~~2022 capital budget.

Repayment of senior ~~and senior subordinated~~ notes for first ~~six~~three months ~~2021~~2022 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 $48.5 million of~~ our 5.00% senior subordinated 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. In addition, in conjunction with the issuance of our $550.0$850.0 million aggregate principal amount 9.25% senior notes due ~~2026, we used the proceeds from this issuance to redeem $324.1 million of our 5.75% senior notes due 2021 and $175.9 million of our 5.875% senior notes due 2022.~~2026. 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~~Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources ~~are internally~~to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion commitments in order to maintain flexibility with regard to our activity level and capital expenditures. As of March 31, 2022, we had cash on hand in the amount of $112.9 million.

Sources of Cash

We currently expect our 2022 capital program to be funded by cash flows from operations. During the quarter ended March 31, 2022, we generated $406.4 million of cash flows from operating ~~activities, a~~activities. As of March 31, 2022, the remaining available borrowing capacity under our bank credit facility was $2.1 billion and we had $112.9 million cash on hand. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties or financing activities. We may draw on our bank credit facility to meet short-term cash requirements. In early January 2022, we issued $500.0 million aggregate principal amount of new 4.75% senior notes due 2030, with ~~uncommitted~~the proceeds along with cash on hand and ~~committed availability, access~~our credit facility to fully redeem our 9.25% senior notes due 2026 in February 2022.

Although we expect cash flows and capacity under the ~~debt and equity capital markets and asset sales. We must develop~~ existing ~~reserves~~credit facility to maintain 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 liquiditybe sufficient to fund our expected 2022 capital ~~expenditure program. In second quarter 2021,~~program, we ~~entered into~~may also elect to raise funds through new debt or equity offerings or from other sources of financing. Any downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be affected by the general conditions of the broader economy, the global pandemic, force majeure events and fluctuations in commodity prices, operating costs and volumes produced, all of which affect us and our industry. We have no control over market prices for natural gas, NGLs or oil, although we may be able to influence the amount of realized revenues through the use of derivative contracts ~~for 2021 through 2024 to protect future cash flows.~~as part of our commodity price risk management.

~~During first six months 2021,~~Bank Credit Facility

Our bank credit facility is secured by substantially all of our ~~net cash provided from operating activities~~assets. As of ~~$283.4 million and~~March 31, 2022, we had no outstanding borrowings under our bank credit facility ~~were used to fund approximately $222.5 million of capital expenditures (including acreage acquisitions). At June 30, 2021,~~and we ~~had $464,000 in cash and total assets of $6.2 billion.~~

Long-term debt at June 30, 2021 totaled $3.0 billion, including $121.0 million outstanding on our bank credit facility and $2.9 billion of senior and senior subordinated notes. Our available committed borrowing capacity at June 30, 2021 was $1.9 billion 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 reserves and production will be highly dependent on capital resources 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 2021 capital budget was announced in early February at $425.0 million.

Commodity prices have remained highly volatile and have increased during first six months 2021 compared to fourth quarter 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 margin enhancements. We plan to continue to work towards 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.~~

~~Credit Arrangements~~

~~As of June 30, 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~~billion. We also have undrawn letters of credit of $338.0 million 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. Availability~~March 31, 2022. We were in compliance with applicable covenants under the bank credit facility as of March 31, 2022.

The borrowing base is subject to regular, semi-annual redeterminations and is dependent on a number of factors but primarily the lender’s assessment of future cash flows. Our scheduled borrowing base redetermination was completed in the spring of 2022. On April 14, 2022 we entered into an amended and restated revolving bank credit facility. The new facility has a maximum facility amount of $4.0 billion, a borrowing base ~~set by~~of $3.0 billion and aggregate lender commitments of $1.5 billion. The maturity of the ~~lenders. As of June 30, 2021, the outstanding balance under our~~new bank credit facility is April 14, 2027. See Note 8 for additional information.

Our daily weighted-average bank credit facility debt balance was ~~$121.0 million. Additionally, we had $334.6~~$65.3 million for the three months ended March 31, 2022 compared to $220.4 million for the same period of ~~undrawn letters~~the prior year. As of ~~credit leaving $1.9 billion of committed borrowing capacity available~~April 14, 2022, borrowings under the amended and restated revolving bank facility can either be at the alternate base rate (“ABR,” as defined in the bank credit facility agreement) plus a spread ranging from 0.75% to 1.75% or at the ~~end of second quarter 2021.~~

~~Our~~Term Benchmark Rate (as defined in the bank credit facility ~~imposes limitations on~~agreement) plus a spread ranging from 1.75% to 2.75%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our Term Benchmark loans to base rate loans or to convert all or any of the base rate loans to Term Benchmark loans.

Uses of Cash

We use cash for the development, exploration and acquisition of natural gas and oil properties and for the payment of ~~dividends~~gathering, transportation and processing costs, operating, general and administrative costs, taxes and debt obligations, including interest. Expenditures for the development, exploration and acquisition of natural gas and oil properties are the primary use of our capital resources. During first quarter 2022, we funded $102.7 million on capital expenditures as reported in our consolidated statement of cash flows. The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operating, investing and financing activities, infrastructure availability, supply and demand

fundamentals and our ability to execute our development program. In addition, the impact of commodity prices on investment opportunities, the availability of capital and the timing and results of our development activities may lead to changes in funding requirements for future development. We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other ~~restricted payments (as defined under~~factors.

We may from time to time repurchase or redeem all or portions of our ~~bank credit facility).~~outstanding debt securities for cash, through exchanges for other securities or a combination of both. Such repurchases or redemptions may be made in open market transactions and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The ~~bank credit facility also contains customary covenants relating~~amounts involved may be material. As part of our strategy for 2022, we will continue to focus on improving our debt ~~incurrence, liens, investments~~metrics.

We expect our quarterly cash dividend to be reinstated in the second half of 2022 at a quarterly dividend rate of $0.08 per share or an $0.32 per share annual distribution. Details regarding the record and ~~financial ratios. We were in compliance with all covenants~~payment dates will be announced at ~~June 30, 2021. See Note 9~~such time the dividend is declared by our Board of Directors. In early 2022, the board approved an increase to our ~~unaudited consolidated financial statements~~share repurchase program, where we are now authorized to repurchase an additional $430.0 million of our outstanding shares of common stock for ~~additional information regarding our bank debt.~~an aggregate available at the time of $500.0 million.

Shelf 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 cash flow, capital expenditures, debt covenants and various other factors. We expect our quarterly cash dividend will be reinstated in the second half of 2022.

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

~~June 30, 2021,~~ March 31, 2022, 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 ~~June 30, 2021,~~March 31, 2022, we had a total of ~~$334.6~~$338.0 million of undrawn letters of credit under our bank credit facility.

Since December 31, ~~2020,~~2021, 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 divestiture contract obligation as discussed in Note 14.~~8.

Interest Rates

At ~~June 30, 2021,~~March 31, 2022, we had approximately ~~$3.0~~$2.6 billion of debt ~~outstanding. Of this amount, $2.9 billion~~outstanding which bore interest at fixed rates averaging ~~6.9%~~5.7%. Bank debt totaling $121.0 million bears interest at a floating rate, which was 2.2% at June 30, 2021. The 30-day LIBOR Rate on June 30, 2021 was approximately 0.1%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on June 30, 2021 would result in approximately $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~~.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~~Certain of our costs and expenses are affected by general inflation ~~inflation does not normally have a significant effect on our business. We~~and we expect costs for the remainder of ~~2021~~2022 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, ~~2020,~~2021, as filed with the SEC on February ~~23, 2021.~~22, 2022.

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 can 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~~regional index prices for North American natural gas production. However, natural gas and NGLs prices are becoming global commodities similar to oil. 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 ~~65%~~64% of our December 31, ~~2020~~2021 proved reserves are natural gas and 2% of proved reserves are oil and condensate. In addition, a portion of our NGLs, which are ~~33%~~34% 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, ~~2020~~2021 to ~~June 30, 2021.~~March 31, 2022.

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 ~~June 30, 2021,~~March 31, 2022, 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 ~~June 30, 2021,~~March 31, 2022, approximated a net unrealized pretax loss of ~~$287.7~~

$989.8 million. These contracts expire monthly through December ~~2022.~~2024. At ~~June 30, 2021,~~March 31, 2022, 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)

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.


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price								Fair Market Value
			Swap		Sold Put		Floor		Ceiling
Natural Gas (1)											(in thousands)
2022	Swaps	496,655 Mmbtu/day	$	3.10							$	(352,807	)
2022	Collars	278,073 Mmbtu/day					$	3.31	$	3.72	$	(150,345	)
2022	Three-way Collars	217,745 Mmbtu/day			$	2.30	$	2.84	$	3.45	$	(135,480	)
2023	Swaps	260,000 Mmbtu/day	$	3.41							$	(94,244	)
2023	Collars	234,932 Mmbtu/day					$	3.28	$	4.31	$	(53,693	)
2023	Three-way Collars	149,863 Mmbtu/day			$	2.28	$	3.30	$	4.28	$	(38,978	)
2024	Collars	200,000 Mmbtu/day					$	3.00	$	4.26	$	(16,870	)

Crude Oil
2022	Swaps	6,833 bbls/day	$	61.90							$	(58,500	)
2023	Swaps	5,123 bbls/day	$	71.39							$	(21,770	)

NLGs (C2-Ethane)
April-June 2022	Swaps	2,681 bbls/day	$0.41/gallon								$	(202	)

NGLs (C3-Propane)
April-June 2022	Swaps	3,989 bbls/day	$1.24/gallon								$	(2,048	)

NGLs (NC4-Butane)
April-June 2022	Swaps	3,000 bbls/day	$1.50/gallon								$	(1,640	)

NGLs (C5-Natural Gasoline)
2022	Swaps	2,331 bbls/day	$1.78/gallon								$	(11,849	)
2022	Collars	1,530 bbls/day					$1.77/gallon		$1.88/gallon		$	(5,481	)


(1)	We also sold natural gas call swaptions of 100,000 Mmbtu/day for 2023 at a weighted average price of $3.21. The fair market value of these swaptions at March 31, 2022 was a net derivative liability of $45.9 million.

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.

4238

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 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 ~~$25.7~~$22.5 million ~~June 30, 2021~~March 31, 2022 and they settle monthly through December 2024.

At June 30, 2021, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. These contracts settle monthly through 2021. The fair value of these contracts was a gain of $376,000 at June 30, 2021.

~~At June 30, 2021,~~March 31, 2022, we are entitled to receive contingent consideration associated with the sale of our North Louisiana assets, annually through 2023, of up to ~~$75.0~~$45.5 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 ~~June 30, 2021~~March 31, 2022 was a gain of ~~$37.4~~$34.8 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 ~~June 30, 2021.~~March 31, 2022. 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									Hypothetical Change in Fair Value						Hypothetical Change in Fair Value
				Increase in Commodity Price of						Decrease in Commodity Price of									Increase in Commodity Price of						Decrease in Commodity Price of
	Fair Value			10%			25%			10%			25%			Fair Value			10%			25%			10%			25%
Swaps	$	(161,808	)	$	(91,130	)	$	(227,825	)	$	91,130		$	227,825		$	(543,060	)	$	(159,687	)	$	(399,217	)	$	159,687		$	399,217
Collars		(36,942	)		(28,066	)		(72,480	)		25,844			57,780			(226,389	)		(91,538	)		(234,097	)		89,230			220,970
Three-way collars		(62,582	)		(33,999	)		(90,105	)		30,994			72,773			(174,458	)		(51,134	)		(130,589	)		48,890			118,936
Swaptions		(26,414	)		(21,880	)		(56,376	)		17,073			25,740			(45,871	)		(15,790	)		(39,942	)		14,966			33,295
Basis swaps		26,063			11,208			28,029			(11,194	)		(27,890	)		22,452			9,026			22,565			(9,026	)		(22,565	)
Freight swaps		37			346			866			(346	)		(866	)
Divestiture contingent consideration		37,350			6,810			15,380			(7,570	)		(18,770	)		34,760			1,170			2,550			(1,520	)		(4,940	)

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 ~~June 30, 2021,~~March 31, 2022, our derivative counterparties include ~~nineteen~~fifteen 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. Through March 31, 2021, our propane and butane sales from the Marcus Hook facility near Philadelphia were short-term and to a single purchaser and our ethane sales 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 ~~June 30, 2021,~~March 31, 2022, we had ~~$3.0~~$2.6 billion of debt ~~outstanding. Of this amount, $2.9 billion~~outstanding which bears interest at fixed rates averaging ~~6.9%~~5.7%. Bank debt totaling $121.0 million bears interest at floating rates, which was 2.2% on June 30, 2021. On June 30, 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 June 30, 2021 would result in approximately $1.2~~million in additional annual interest expense.~~

4339

ITEM 4. CONTROLS ~~AND~~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 ~~June 30, 2021~~March 31, 2022 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 ~~Exchange Act~~ Rule 13a-15(f) under the Exchange Act) during the three months ended ~~June 30, 2021~~March 31, 2022 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

See Note 1716 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 notified by the DEP that it intends to assess a civil penalty under the Clean Streams Law and the 2012 Oil and Gas Act in connection with one well in Lycoming County and ordered us to conduct certain remedial 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 area and DEP did not assess any fines at that time. Thereafter, on January 13, 2020, DEP issued a new order regarding the 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 investigation that this one well has not been nor is currently the source of methane in the environment nor any water supplies, but rather the methane existed in the environment before the commencement of our operations. We appealed the January 2020 order and intend to vigorously defend against the allegations asserted by DEP; however, a resolution of this matter may nonetheless result in monetary sanctions of more than $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 $250,000.

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, ~~2020.~~2021.

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

~~During second quarter 2021, we did not purchase any shares. Through June 30, 2021, we have repurchased 10.0 million shares~~Purchases of our common stock ~~at a cost of approximately $29.9 million, excluding fees and commissions,~~during the quarter is as ~~part of a $100.0 million share repurchase program announced in October 2019. Shares repurchased as of June 30, 2021 are held as treasury stock.~~follows:


	Three Months Ended March 31, 2022
Period	Total Number of Shares Purchased		Average Price Paid Per Share (a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (b)		Approximate Dollar Amount of Shares that May Yet Be Purchased Under Plans or Programs
January 2022		—	$	—		—	$	70,099,593
February 2022		—	$	—		—	$	70,099,593
March 2022		600,000	$	27.00		600,000	$	483,899,772
		600,000				600,000

(a)

(b)

Includes any fees, commissions or other expenses associated with the share repurchases.

In October 2019, our board of directors authorized a $100 million common stock repurchase program. In February 2022, our Board of Directors subsequently increased the authorization for repurchases under the program for a cumulative approval of $530.0 million which includes fees, commissions and expenses. The share repurchase authority does not obligate us to acquire any specific number of shares. The program may be changed based upon our financial condition and is subject to termination by the Board of Directors prior to completion. Shares repurchased as of March 31, 2022 were held as treasury stock.

4441

ITEM 6. EXHIBITS

Exhibit index


Exhibit Number		Exhibit Description
	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 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)

	31.1*
	4.1	Form of 4.75% Senior Note due 2030 (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on February 1, 2022)

	4.2	Indenture dated February 1, 2022, among Range Resources Corporation, as issuer, the subsidiary guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on February 1, 2022)

	10.1	Purchase Agreement, dated January 13, 2022, by name and among Range Resources Corporation, Range Production Company, LLC, Range Resources―Appalachia, LLC, Range Resources―Louisiana, Inc., Range Resources―Midcontinent, LLC, Range Resources Pine Mountain, Inc. and Wells Fargo Securities, LLC, as representative of the Initial Purchasers, (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on January 14, 2022)

	10.2	Seventh Amended and Restated Credit Agreement, dated April 14, 2022, among Range Resources Corporation, as borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Letter of Credit Issuer, and each other Letter of Credit Issuer or Lender from time to time party thereto (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as field with the SEC on April 18, 2022)

	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

	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

4542

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: ~~July~~April 26, ~~2021~~2022


RANGE RESOURCES CORPORATION

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

Date: ~~July~~April 26, ~~2021~~2022


RANGE RESOURCES CORPORATION

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

4643


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 Filer		Smaller Reporting Company	☐
		Emerging Growth Company	☐


		Page
PART I – FINANCIAL INFORMATION
ITEM 1.	Financial Statements:
	~~Consolidated Balance Sheets (Unaudited)~~	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations (Unaudited)	4
	Consolidated Statements of Comprehensive ~~Loss~~(Loss) Income (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	2825
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	4137
ITEM 4.	Controls and Procedures	4440
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings	4440
ITEM 1A.	Risk Factors	4440
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4441
ITEM 6.	Exhibits	4542
	SIGNATURES	4643


	June 30,			December 31,			March 31,			December 31,
	2021			2020			2022			2021
Assets	(Unaudited)						(Unaudited)
Current assets:
Cash and cash equivalents	$	464		$	458		$	112,931		$	214,422
Accounts receivable, less allowance for doubtful accounts of $393 and $3,004		299,590			252,642
Accounts receivable, less allowance for doubtful accounts of $568 and $568								413,026			471,775
Contingent consideration receivable								29,500			29,500
Derivative assets		25,865			23,332			2,176			5,738
Other current assets		13,793			13,408			18,162			15,230
Total current assets		339,712			289,840			575,795			736,665
Derivative assets		21,483			16,680			36,600			38,601
Natural gas properties, successful efforts method		9,973,112			9,751,114			10,291,519			10,175,570
Accumulated depletion and depreciation		(4,239,713	)		(4,064,305	)		(4,504,554	)		(4,420,914	)
		5,733,399			5,686,809			5,786,965			5,754,656
Other property and equipment		80,503			79,878			74,715			74,678
Accumulated depreciation and amortization		(76,677	)		(75,717	)		(71,615	)		(71,184	)
		3,826			4,161			3,100			3,494
Operating lease right-of-use assets		52,291			63,581			35,906			40,832
Deferred tax assets								35,436			—
Other assets		78,722			75,865			86,483			86,259
Total assets	$	6,229,433		$	6,136,936		$	6,560,285		$	6,660,507

Liabilities
Current liabilities:
Accounts payable	$	144,454		$	132,421		$	234,253		$	178,413
Asset retirement obligations		6,689			6,689			5,310			5,310
Accrued liabilities		358,640			348,333			381,110			420,898
Accrued interest		76,909			54,742			34,317			75,940
Derivative liabilities		249,277			26,707			845,312			162,767
Divestiture contract obligation		89,950			92,593			87,499			91,120
Current maturities of long-term debt		0			45,356			749,483			218,017
Total current liabilities		925,919			706,841			2,337,284			1,152,465
Bank debt		114,025			693,123			0			0
Senior notes		2,922,632			2,329,745			1,829,734			2,707,770
Senior subordinated notes		0			17,384
Deferred tax liabilities		134,000			135,267			32,243			117,642
Derivative liabilities		22,367			9,746			126,030			8,216
Deferred compensation liabilities		121,010			81,481			197,494			137,102
Operating lease liabilities		32,770			43,155			23,913			24,861
Asset retirement obligations and other liabilities		87,336			91,157			102,040			101,509
Divestiture contract obligation		346,113			391,502			311,443			325,279
Total liabilities		4,706,172			4,499,401			4,960,181			4,574,844
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	)
Preferred stock, $1 par, 10,000,000 shares authorized, NaN issued and outstanding								—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 262,777,606 issued at March 31, 2022 and 259,795,554 issued at December 31, 2021								2,627			2,598
Common stock held in treasury, 10,601,535 shares at March 31, 2022 and 10,002,646 shares at December 31, 2021								(46,159	)		(30,007	)
Additional paid-in capital		5,699,240			5,684,268			5,707,652			5,720,277
Accumulated other comprehensive loss		(338	)		(479	)		(75	)		(150	)
Retained deficit		(4,148,154	)		(4,018,685	)		(4,063,941	)		(3,607,055	)
Total stockholders’ equity		1,523,261			1,637,535			1,600,104			2,085,663
Total liabilities and stockholders’ equity	$	6,229,433		$	6,136,936		$	6,560,285		$	6,660,507


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2021			2020			2021			2020			2022			2021

Revenues and other income:
Natural gas, NGLs and oil sales	$	621,855		$	349,258		$	1,225,202		$	781,354		$	1,032,351		$	603,347
Derivative fair value (loss) income		(249,683	)		(6,303	)		(307,562	)		226,872
Derivative fair value loss														(939,057	)		(57,879	)
Brokered natural gas, marketing and other		62,550			33,591			143,114			62,240			87,442			80,564
Total revenues and other income		434,722			376,546			1,060,754			1,070,466			180,736			626,032
Costs and expenses:
Direct operating		19,758			24,394			37,408			56,429			20,288			17,650
Transportation, gathering, processing and compression		282,844			278,875			557,174			563,640			297,787			274,330
Production and ad valorem taxes		8,414			5,557			13,039			14,576			6,590			4,625
Brokered natural gas and marketing		69,004			38,161			141,339			70,785			93,123			72,335
Exploration		5,028			8,027			10,566			15,104			4,699			5,538
Abandonment and impairment of unproved properties		2,177			5,524			5,206			10,937			1,996			3,029
General and administrative		40,242			38,288			78,246			80,542			43,026			38,004
Exit and termination costs		(15,946	)		10,297			(2,232	)		11,892			11,115			13,714
Deferred compensation plan		35,462			12,587			55,273			4,050			73,343			19,811
Interest		57,287			48,624			114,165			96,142			47,175			56,878
Loss (gain) on early extinguishment of debt		63			(8,991	)		98			(21,914	)
Loss on early extinguishment of debt														69,210			35
Depletion, depreciation and amortization		90,629			104,626			179,012			207,612			85,604			88,383
Impairment of proved properties		0			0			0			77,000
(Gain) loss on the sale of assets		(2,506	)		426			(646	)		(121,673	)		(331	)		1,860
Total costs and expenses		592,456			566,395			1,188,648			1,065,122			753,625			596,192
(Loss) income before income taxes		(157,734	)		(189,849	)		(127,894	)		5,344			(572,889	)		29,840
Income tax expense (benefit):
Current		2,569			(3	)		2,737			(366	)		4,751			168
Deferred		(3,831	)		(22,263	)		(1,310	)		7,098			(120,832	)		2,521
		(1,262	)		(22,266	)		1,427			6,732			(116,081	)		2,689
Net loss	$	(156,472	)	$	(167,583	)	$	(129,321	)	$	(1,388	)
Net loss per common share:
Net (loss) income													$	(456,808	)	$	27,151
Net (loss) income per common share:
Basic	$	(0.65	)	$	(0.70	)	$	(0.53	)	$	(0.01	)	$	(1.86	)	$	0.11
Diluted	$	(0.65	)	$	(0.70	)	$	(0.53	)	$	(0.01	)	$	(1.86	)	$	0.11
Weighted average common shares outstanding:
Basic		242,592			239,472			242,377			242,717			245,350			242,159
Diluted		242,592			239,472			242,377			242,717			245,350			247,527


☑	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


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


Fiscal Year 2021					Common									Accumulated
Fiscal Year 2022																								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, 2020		256,354	$	2,563	$	(30,132	)	$	5,684,268		$	(4,018,685	)	$	(479	)	$	1,637,535
Balance as of December 31, 2021																					259,796	$	2,598	$	(30,007	)	$	5,720,277		$	(3,607,055	)	$	(150	)	$	2,085,663
Issuance of common stock		3,218		33		0			(7,654	)		0			0			(7,621	)		2,980		29		0			(21,276	)		0			0			(21,247	)
Issuance of common stock upon vesting of PSUs		—		0		0			148			(148	)		0			0			2		0		0			78			(78	)		0			0
Stock-based compensation expense		—		0		0			6,713			0			0			6,713			—		0		0			8,619			0			0			8,619
Treasury stock		—		0		47			(47	)		0			0			0			—		0		(16,152	)		(46	)		0			0			(16,198	)
Other comprehensive income		—		0		0			0			0			70			70			—		0		0			0			0			75			75
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		206		2		0			9,289			0			0			9,291
Stock-based compensation expense		—		0		0			6,523			0			0			6,523
Treasury stock		—		0		0			0			0			0			0
Other comprehensive income		—		0		0			0			0			71			71
Net loss		—		0		0			0			(156,472	)		0			(156,472	)		—		0		0			0			(456,808	)		0			(456,808	)
Balance as of June 30, 2021		259,778	$	2,598	$	(30,085	)	$	5,699,240		$	(4,148,154	)	$	(338	)	$	1,523,261
Balance as of March 31, 2022																					262,778	$	2,627	$	(46,159	)	$	5,707,652		$	(4,063,941	)	$	(75	)	$	1,600,104


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		0			(1,406	)		0			0			(1,364	)
Stock-based compensation expense		—		0		0			5,963			0			0			5,963
Treasury stock		—		0		(22,514	)		(33	)		0			0			(22,547	)
Other comprehensive income		—		0		0			0			0			73			73
Net income		—		0		0			0			166,195			0			166,195
Balance as of March 31, 2020		255,685		2,556		(29,750	)		5,664,356			(3,140,639	)		(715	)		2,495,808
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		0			854			0			0			858			3,205		33		0			(7,654	)		0			0			(7,621	)
Issuance of common stock upon vesting of PSUs		19		0		0			74			(74	)		0			0			13		0		0			148			(148	)		0			0
Stock-based compensation expense		—		0		0			7,312			0			0			7,312			—		0		0			6,713			0			0			6,713
Treasury stock		—		0		(444	)		0			0			0			(444	)		—		0		47			(47	)		0			0			0
Other comprehensive income		—		0		0			0			0			71			71			—		0		0			0			0			70			70
Net loss		—		0		0			0			(167,583	)		0			(167,583	)
Balance as of June 30, 2020		256,080	$	2,560	$	(30,194	)	$	5,672,596		$	(3,308,296	)	$	(644	)	$	2,336,022
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


(a)	~~(a)~~ Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.


	March 31, 2022			December 31, 2021
	(in thousands)
Natural gas properties:
Properties subject to depletion	$	9,447,907		$	9,338,236
Unproved properties		843,612			837,334
Total		10,291,519			10,175,570
Accumulated depletion and depreciation		(4,504,554	)		(4,420,914	)
Net capitalized costs	$	5,786,965		$	5,754,656


	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


(a)	Includes capitalized asset retirement costs and the associated accumulated amortization.


	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


(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 2022 were to our CEO, CFO and COO only.
(b)	For the awards issued during 2019, the aggregate payout was approximately 116% of target with a positive performance adjustment of 158,793 shares.


	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


	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


	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