0000950170-24-018046 | 10-K | XBRL Viewer

Percentage of proved resources reviewed by consultants

96.00%

Proved reserve and pretax present value of reserve discounted

10.00%

Variance in reserve estimates

approximately 5%

Scheduled to be drilling period maximum for undeveloped reserves

scheduled to be drilled within five years

Reserve additions attributable to natural gas

77.00%

72.00%

Proved undeveloped reserves dropped

370,600

1,400,000

1,300,000

Revisions of positive pricing

22,600

Cost spent on undeveloped reserves transferred to developed reserves | $

$ 495.1

Estimated future development costs over years | $

$ 2,600.0

Proved undeveloped reserves reported for more than five years | Bcfe

90,200

Crude Oil and NGL

Benchmark price used for calculating average realized prices | $ / bbl

78.1

94.13

66.34

Crude Oil and Condensate

Estimate reserve information average realized prices | $ / bbl

68.32

87.14

59.35

NGLs

Estimate reserve information average realized prices | $ / bbl

24.91

38.35

28.41

Natural Gas

Estimate reserve information average realized prices | $ / Mcf

2.2

6.08

3.3

Natural Gas, Per Thousand Cubic Feet

Benchmark price used for calculating average realized prices | $ / MMBTU

2.62

6.36

3.6

Natural Gas Equivalents

Proved reserves from drilling activities and evaluations of proved areas

^[1]

207,260

1,668,244

1,602,769

Revisions of previous estimates

^[1]

608,784

(591,983)

(252,876)

Revision of positive performance

701,400

72,800

1,000,000

Additional undeveloped properties reclassified

280,200

716,200

Maximum

Statement that reserve estimates differ from auditors

0.10

[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.

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Senior notes	$ 1,788,388	$ 1,850,000
Total debt	1,788,388	1,869,000
Unamortized debt issuance costs	(14,159)	(27,040)
Total debt (net of debt issuance costs)	1,774,229	1,841,960
Notes Payable to Banks
Debt Instrument [Line Items]
Bank debt	0	19,000
4.875% Senior Notes Due 2025 \| Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	688,388	750,000
8.25% Senior Notes Due 2029 \| Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	600,000	600,000
4.75% Senior Notes Due 2030 \| Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	$ 500,000	$ 500,000

Summary of Organization and Nature of Business	12 Months Ended
Summary of Organization and Nature of Business	Dec. 31, 2023
Industry-Specific Policies [Abstract]
Summary of Organization and Nature of Business	(1) Summary of Organization and Nature of Business Range Resources Corporation ("Range," "we," "us," or "our") is a Fort Worth, Texas-based independent natural gas, natural gas liquids ("NGLs"), crude oil and condensate company engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian region of the United States. Our objective is to build stockholder value through returns-focused development of natural gas properties. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol "RRC".

Net Income Per Common Share - Computations of Basic and Diluted Income (Loss) Per Common Share (Detail) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Earnings Per Share Reconciliation [Abstract]

Net Income (Loss)

$ 871,142

$ 1,183,370

$ 411,778

Participating basic earnings

^[1]

(14,971)

(28,578)

(10,795)

Basic net income attributed to common stockholders

856,171

1,154,792

400,983

Reallocation of participating earnings

^[1]

159

614

272

Diluted net income attributed to common stockholders

$ 856,330

$ 1,155,406

$ 401,255

Net income per common share:

Basic

$ 3.61

$ 4.79

$ 1.65

Diluted

$ 3.57

$ 4.69

$ 1.61

[1]

Restricted stock Liability 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.

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

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-Section 45
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Reference 36: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 2
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-Paragraph 1
-Subparagraph (SX 210.9-04(22))
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Amount, after deduction of tax, noncontrolling interests, dividends on preferred stock and participating securities; of income (loss) available to common shareholders.

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Amount, after deduction of tax, noncontrolling interests, dividends on preferred stock and participating securities, and addition from assumption of issuance of common shares for dilutive potential common shares; of income (loss) available to common shareholders.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Detail)

12 Months Ended

Dec. 31, 2023

MMcfe

Beginning proved undeveloped reserves at December 31, 2022

7,144,476

Undeveloped reserves transferred to developed

(937,906)

Revisions

191,920

^[1]

Extension and discoveries

178,783

Ending proved undeveloped reserves at December 31, 2023

6,577,273

[1]

Includes 280.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into our five year development plan along with positive revisions for longer laterals offset by 370.6 Bcfe of proved undeveloped reserves removed and deferred due to the five-year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan.

Commitments and Contingencies - Schedule of Estimated Settlement of Divestiture Contract Obligation Based on Discounted Value (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Disclosure Commitments And Contingencies Schedule Of Estimated Settlement Of Divestiture Contract Obligation [Abstract]
2024	$ 86,762
2025	77,418
2026	61,805
2027	52,622
2028	48,116
Thereafter	70,727
Divestiture Contract Obligation	$ 397,450

Net Income Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	4,100,000	6,100,000	6,500,000
Equity Grants
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	3,000	5,000	18,000

Commitments and Contingencies - Supplemental Cash Flow Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 71,669	$ 37,457
ROU assets added in exchange for lease obligations	$ 7,421	$ 78,574

Exit Costs - Exit and Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet - (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Exit costs included in accrued liabilities in consolidated balance sheet
Accrued severance costs	$ 0	$ 0	$ 567
Exit Costs
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	395,680	423,742
Accrued contract obligations-changes in estimate	57,735	26,183
Accretion of discount	42,205	44,154
Payments	(95,631)	(98,399)
Ending balance	399,989	395,680	423,742
Termination Costs
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	0	10
Accrued contract obligations-changes in estimate	0	0
Accretion of discount	0	0
Payments	0	(10)
Ending balance	$ 0	$ 0	$ 10

Stock-Based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 USD ($) Plans	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Active equity-based stock plans \| Plans	2
Income tax expense (benefit)	$ 229,201,000	$ 230,460,000	$ (9,743,000)
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax expense (benefit)	$ (10,600,000)	$ (7,200,000)	$ (340,000)

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Restructuring and Related Activities [Abstract]

Exit Costs

12 Months Ended

Dec. 31, 2023

Exit Costs

(14) Exit 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 the twelve months ended December 31, 2023, we recorded accretion expense of $41.9 million compared to $43.6 million in 2022 and $47.9 million in 2021. In second quarter 2023, we recorded a net adjustment of $37.8 million to increase this obligation primarily for higher rates due to inflation. In fourth quarter 2023, we recorded an additional $18.0 million adjustment to increase the obligation for a change to our forecasted drilling plans of the buyer along with adjusting for the difference between estimated and actual payments. In 2022, we recorded a net adjustment of $26.2 million to increase this obligation for a change in our forecasted drilling plans of the buyer along with adjusting the difference between estimated and actual payments. The present value of our estimated obligations related to these assets was initially recorded in 2020 as an exit cost at a total of $479.8 million. The estimated discounted value for this divestiture contract obligation was $397.4 million at December 31, 2023.

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. As a result of these releases, we recorded exit costs of $10.4 million which represented the discounted present value of our remaining obligations to the third party. The remaining carrying value for these transportation capacity releases as of December 31, 2023 was $2.5 million.

The following summarizes our exit costs for the three years ended December 31, 2023, 2022 and 2021 (in thousands):


	Year Ended December 31,
	2023		2022		2021
Severance costs	$	—	$	—	$	567
Transportation contract capacity releases (including accretion of discount)		345		579		754
Divestiture contract obligation (including accretion of discount)		99,595		69,758		20,340
Total exit costs	$	99,940	$	70,337	$	21,661

The following details the accrued exit cost liability activity for the years ended December 31, 2023 and 2022 (in thousands):


	Exit Costs			Termination Costs
Balance at December 31, 2021	$	423,742		$	10
Accrued contract obligations-changes in estimate		26,183			—
Accretion of discount		44,154			—
Payments		(98,399	)		(10	)
Balance at December 31, 2022		395,680		$	—
Accrued contract obligations-changes in estimate		57,735			—
Accretion of discount		42,205			—
Payments		(95,631	)		—
Balance at December 31, 2023	$	399,989		$	—

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail)	Dec. 31, 2023 BarrelsPerDay MmbtuPerDay $ / MMBTU $ / bbl
Naturals Gas [Member] \| 2024 Commodity Contract \| Swaps
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	304,973
Weighted Average Hedge Price, Swap	4.01
Naturals Gas [Member] \| 2024 Commodity Contract \| Collars
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	436,694
Weighted average price of hedge, Floor	3.5
Weighted average price of hedge, Ceiling	5.63
Naturals Gas [Member] \| 2024 Commodity Contract \| Three Way Collars
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	93,511
Weighted Average Hedge Price, Sold Put	2.5
Weighted average price of hedge, Floor	3.4
Weighted average price of hedge, Ceiling	4.15
Naturals Gas [Member] \| 2025 Commodity Contract \| Swaps
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	400,000
Weighted Average Hedge Price, Swap	4.12
Naturals Gas [Member] \| 2025 Commodity Contract \| Three Way Collars
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	30,000
Weighted Average Hedge Price, Sold Put	2.7
Weighted average price of hedge, Floor	4
Weighted average price of hedge, Ceiling	5
Naturals Gas [Member] \| 2026 Commodity Contract \| Swaps
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	60,000
Weighted Average Hedge Price, Swap	4.15
Crude Oil \| January-September 2024 \| Swaps
Derivative [Line Items]
Volume hedged \| BarrelsPerDay	4,000
Weighted Average Hedge Price, Swap \| $ / bbl	80.25
Crude Oil \| January-September 2024 \| Collars
Derivative [Line Items]
Volume hedged \| BarrelsPerDay	832
Weighted average price of hedge, Floor \| $ / bbl	80
Weighted average price of hedge, Ceiling \| $ / bbl	90.12

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Parenthetical) (Detail)	Dec. 31, 2023	Dec. 31, 2022
4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	4.875%	4.875%
8.25% Senior Notes Due 2029
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	8.25%	8.25%
4.75% Senior Notes Due 2030
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	4.75%	4.75%

Exit Costs - Summary of Exit and Termination Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restructuring Cost And Reserve [Line Items]
Severance costs	$ 0	$ 0	$ 567
Total exit costs	99,940	70,337	21,661
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost	345	579	754
North Louisiana Contract Release
Restructuring Cost And Reserve [Line Items]
Exit cost	$ 99,595	$ 69,758	$ 20,340

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Cash and cash equivalents

Indebtedness - Bank Debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 USD ($) Commercialbank	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 30, 2023 USD ($)
Debt Instrument [Line Items]
Undrawn letters of credit	$ 173,400,000
Borrowing capacity available under the commitment amount	1,300,000,000
Loss (gain) on early extinguishment of debt	(438,000)	$ 69,493,000	$ 98,000
Bank Credit Facility [Member]
Debt Instrument [Line Items]
Bank credit facility, maximum amount	4,000,000,000
Bank credit facility, borrowing base	3,000,000,000			$ 3,000,000,000
Bank commitments	1,500,000,000			$ 1,500,000,000
Outstanding amount	$ 0
Number of commercial banks included in current bank group \| Commercialbank	17
Maturity date of loan	Apr. 14, 2027
Weighted average interest rate on the bank credit facility	8.40%	4.10%	2.10%
Annual rate of commitment fee paid on the undrawn balance	0.375%
Bank Credit Facility [Member] \| Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin	0.75%
Bank Credit Facility [Member] \| SOFR Rate
Debt Instrument [Line Items]
Interest rate margin	1.75%
Bank Credit Facility [Member] \| Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Bank Credit Facility [Member] \| Minimum \| Alternate Base Rate
Debt Instrument [Line Items]
Interest rate on notes	0.75%
Bank Credit Facility [Member] \| Minimum \| SOFR Rate
Debt Instrument [Line Items]
Interest rate on notes	1.75%
Bank Credit Facility [Member] \| Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.50%
Bank Credit Facility [Member] \| Maximum \| Alternate Base Rate
Debt Instrument [Line Items]
Interest rate on notes	1.75%
Bank Credit Facility [Member] \| Maximum \| SOFR Rate
Debt Instrument [Line Items]
Interest rate on notes	2.75%

CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands

Dec. 31, 2023

Dec. 31, 2022

Current assets:

$ 211,974

$ 207

Accounts receivable, less allowance for doubtful accounts of $308 and $314

274,669

481,050

Contingent consideration receivable

8,000

24,500

Derivative assets

341,330

925

Prepaid assets

18,159

20,795

Other current assets

15,992

12,110

Total current assets

870,124

539,587

Derivative assets

101,641

40,990

Natural gas and oil properties, successful efforts method

^[1]

11,225,482

10,655,879

Accumulated depletion and depreciation

^[1]

(5,107,801)

(4,765,475)

Natural gas and oil properties, successful efforts method, net

^[1]

6,117,681

5,890,404

Other property and equipment

72,639

74,638

Accumulated depreciation and amortization

(70,943)

(72,204)

Other property and equipment, net

1,696

2,434

Operating lease right-of-use assets

23,821

84,070

Other assets

88,922

68,077

Total assets

7,203,885

6,625,562

Current liabilities:

Accounts payable

110,134

206,738

Asset retirement obligations

2,395

4,570

Accrued liabilities

302,163

442,922

Deferred compensation liabilities

44,149

89,334

Accrued interest

37,261

39,138

Derivative liabilities

222

151,417

Divestiture contract obligation

86,762

86,546

Total current liabilities

583,086

1,020,665

Bank debt

9,509

Deferred compensation liabilities

1,774,229

1,832,451

Deferred tax liabilities

561,288

333,571

Derivative liabilities

107

15,495

72,976

99,907

Operating lease liabilities

16,064

20,903

Asset retirement obligations and other liabilities

119,896

112,981

Divestiture contract obligation

310,688

304,074

Total liabilities

3,438,334

3,749,556

Commitments and contingencies

Stockholders' Equity

Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding

Common stock, $0.01 par 475,000,000 shares authorized, 265,756,369 issued at December 31, 2023 and 262,887,265 issued at December 31, 2022

2,658

2,629

Common stock held in treasury, at cost, 24,716,065 shares at December 31, 2023 and 24,001,535 shares at December 31, 2022

(448,681)

(429,659)

Additional paid-in capital

5,879,705

5,764,970

Accumulated other comprehensive gain

647

467

Retained deficit

(1,668,778)

(2,462,401)

Total stockholders' equity

3,765,551

2,876,006

Total liabilities and stockholders' equity

$ 7,203,885

$ 6,625,562

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Derivative Activities - Combined Fair Value of Derivatives, by Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 452,378	$ 126,464
Gross Amounts Offset in the Balance Sheet	(9,407)	(84,549)
Net Amounts of Assets Presented in the Balance Sheet	442,971	41,915
Gross Amounts of Recognized (Liabilities)	(9,736)	(251,461)
Gross Amounts Offset in the Balance Sheet	9,407	84,549
Net Amounts of (Liabilities) Presented in the Balance Sheet	(329)	(166,912)
Contingent Consideration
Derivative [Line Items]
Gross Amounts of Recognized Assets		13,080
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		13,080
Commodity \| Natural Gas \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	238,465	19,438
Gross Amounts Offset in the Balance Sheet	0	(6,236)
Net Amounts of Assets Presented in the Balance Sheet	238,465	13,202
Gross Amounts of Recognized (Liabilities)		(115,374)
Gross Amounts Offset in the Balance Sheet		6,236
Net Amounts of (Liabilities) Presented in the Balance Sheet		(109,138)
Commodity \| Natural Gas \| Swaptions
Derivative [Line Items]
Gross Amounts of Recognized Assets	0
Gross Amounts Offset in the Balance Sheet	(1,161)
Net Amounts of Assets Presented in the Balance Sheet	(1,161)
Gross Amounts of Recognized (Liabilities)	(1,161)
Gross Amounts Offset in the Balance Sheet	1,161
Net Amounts of (Liabilities) Presented in the Balance Sheet	0
Commodity \| Natural Gas \| Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	150,456	54,222
Gross Amounts Offset in the Balance Sheet	0	(45,452)
Net Amounts of Assets Presented in the Balance Sheet	150,456	8,770
Gross Amounts of Recognized (Liabilities)		(72,866)
Gross Amounts Offset in the Balance Sheet		45,452
Net Amounts of (Liabilities) Presented in the Balance Sheet		(27,414)
Commodity \| Natural Gas \| Three Way Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	25,406	12,424
Gross Amounts Offset in the Balance Sheet	0	(12,424)
Net Amounts of Assets Presented in the Balance Sheet	25,406	0
Gross Amounts of Recognized (Liabilities)		(24,341)
Gross Amounts Offset in the Balance Sheet		12,424
Net Amounts of (Liabilities) Presented in the Balance Sheet		(11,917)
Commodity \| Natural Gas \| Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	26,852	25,493
Gross Amounts Offset in the Balance Sheet	(8,246)	(20,437)
Net Amounts of Assets Presented in the Balance Sheet	18,606	5,056
Gross Amounts of Recognized (Liabilities)	(8,575)	(24,972)
Gross Amounts Offset in the Balance Sheet	8,246	20,437
Net Amounts of (Liabilities) Presented in the Balance Sheet	(329)	(4,535)
Commodity \| Crude Oil \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	9,115
Gross Amounts Offset in the Balance Sheet	0
Net Amounts of Assets Presented in the Balance Sheet	9,115
Gross Amounts of Recognized (Liabilities)		(13,908)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(13,908)
Commodity \| Crude Oil \| Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	2,084	1,807
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet	$ 2,084	$ 1,807

Summary of Significant Accounting Policies - Additional Information (Detail)

12 Months Ended

Dec. 31, 2023

USD ($)

Counterparties

Customer

Counterparty

Dec. 31, 2022

USD ($)

Customer

Dec. 31, 2021

USD ($)

Customer

Summary Of Significant Accounting Policies [Line Items]

Net brokered margin gain (loss)

$ 4,200,000

$ (5,400,000)

$ 1,100,000

Allowance for doubtful accounts on accounts receivable

308,000

314,000

Bad debt (income) expense

(250,000)

200,000

Net book value of unproved properties

^[1]

789,871,000

800,592,000

837,334,000

Abandonment and impairment of unproved properties

46,359,000

28,608,000

7,206,000

Depreciation expense

$ 1,500,000

2,200,000

$ 2,400,000

Lessee, operating lease, contract term

12 months

Marketable securities held in deferred compensation plans

$ 72,000,000

57,700,000

Deferred financing cost related to bank credit facility

7,300,000

Investments and other

$ 9,700,000

$ 10,400,000

Number of customers accounted more than 10% of total oil and gas revenues | Customer

Number of counterparties | Counterparty

Number of financial institutions included in counter parties | Counterparty

Number of counterparties amount payable | Counterparties

Number of counterparties amount receivable | Counterparties

Existing derivative contracts

We did not materially modify any existing derivative contracts in 2023, 2022 or 2021.

Total Revenue

$ 2,553,264,000

$ 5,335,309,000

$ 3,580,439,000

Reported Value Measurement

Summary Of Significant Accounting Policies [Line Items]

Marketable securities held in deferred compensation plans

^[2]

71,989,000

57,717,000

Brokered Natural Gas, Marketing and Other

Summary Of Significant Accounting Policies [Line Items]

Total Revenue

218,603,000

424,217,000

365,412,000

Interest Income | Brokered Natural Gas, Marketing and Other

Summary Of Significant Accounting Policies [Line Items]

Total Revenue

5,937,000

$ 2,538,000

$ 243,000

Counterparties in a Liability position

Summary Of Significant Accounting Policies [Line Items]

Net derivative liability

329,000

Counterparties in a Receivable position

Summary Of Significant Accounting Policies [Line Items]

Derivative amount receivable

$ 26,400,000

Other property and equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

3 years

Other property and equipment | Maximum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

10 years

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.
[2]	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are updated based on end of period closing prices which is a Level 1 input.

Commitments and Contingencies - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) McfD	Jan. 01, 2024 USD ($)
Commitments And Contingencies Disclosure [Line Items]
Total lease payments	$ 30,633
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
Subsequent Event
Commitments And Contingencies Disclosure [Line Items]
Total lease payments		$ 152,000
Divestiture Contract Obligation [Member]
Commitments And Contingencies Disclosure [Line Items]
Accrued obligations	$ 397,400
Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	12 years
Transportation and gathering commitments contingent upon pipeline construction or modification, expiration period	5 years
Transportation commitments contingent upon pipeline construction or modification declined amount \| McfD	300,000
Additional volume of revised agreement \| McfD	650,000

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2023
Debt Instrument [Line Items]
Debt instrument, covenant compliance	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. We are required to maintain a ratio of debt-to-EBITDAX (as defined in the credit agreement) of less than 3.75x and a minimum current ratio (as defined in the credit agreement) of 1.0x. We were in compliance with applicable covenants under the bank credit facility at December 31, 2023.
Minimum
Debt Instrument [Line Items]
Current ratio	100.00%
Maximum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	375.00%

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information


	Year Ended December 31,
	2023			2022			2021
				(in thousands)

Net cash provided from operating activities included:
Income taxes paid to taxing authorities	$	(2,200	)	$	(20,335	)	$	(7,061	)
Interest paid		(120,631	)		(193,732	)		(196,750	)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	4,616		$	18,096		$	18,634
Increase (decrease) in accrued capital expenditures		4,403			1,966			(4,505	)

Net Income Per Common Share - Basic Weighted Average Common Shares Outstanding and Diluted Weighted Average Common Shares Outstanding (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Denominator:
Weighted average common shares outstanding - basic	236,986	240,858	242,862
Effect of dilutive securities	2,851	5,521	6,452
Weighted average common shares outstanding - diluted	239,837	246,379	249,314

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Common stock held in treasury	Additional Paid-in Capital	Accumulated other comprehensive income (loss)	Retained deficit
Beginning balance at Dec. 31, 2020	$ 1,637,535	$ 2,563	$ (30,132)	$ 5,684,268	$ (479)	$ (4,018,685)
Beginning balance Shares at Dec. 31, 2020		256,354,000	10,006,000
Issuance of common stock	7,033	$ 35	$ 0	6,998	0	0
Issuance of common stock, shares		3,429,000
Issuance of common stock upon vesting of PSUs	0	$ 0	0	148	0	(148)
Issuance of common stock upon vesting of PSUs, shares		13,000
Stock-based compensation expense	28,988	$ 0	0	28,988	0	0
Treasury stock issuance	0	0	$ 125	(125)	0	0
Treasury stock issuance, shares			(3,000)
Other comprehensive income	329	0	$ 0	0	329	0
Net income	411,778	0	0	0	0	411,778
Ending balance at Dec. 31, 2021	2,085,663	$ 2,598	$ (30,007)	5,720,277	(150)	(3,607,055)
Ending balance Shares at Dec. 31, 2021		259,796,000	10,003,000
Issuance of common stock	13,560	$ 31	$ 0	13,529	0	0
Issuance of common stock, shares		3,089,000	0
Issuance of common stock upon vesting of PSUs	0	$ 0	$ 0	78	0	(78)
Issuance of common stock upon vesting of PSUs, shares		2,000	0
Stock-based compensation expense	31,133	$ 0	$ 0	31,133	0	0
Stock-based compensation expense, shares			0
Cash dividends paid	(38,638)					(38,638)
Treasury stock issuance	0	0	$ 47	(47)		0
Treasury stock issuance, shares			(1,000)
Treasury stock repurchased	(399,699)	0	$ (399,699)	0
Treasury stock repurchased, shares			14,000,000
Other comprehensive income	617	0	$ 0	0	617	0
Net income	1,183,370	0	0	0	0	1,183,370
Ending balance at Dec. 31, 2022	$ 2,876,006	$ 2,629	$ (429,659)	5,764,970	467	(2,462,401)
Ending balance Shares at Dec. 31, 2022	262,887,265	262,887,000	24,002,000
Issuance of common stock	$ 78,079	$ 29	$ 0	78,050	0	0
Issuance of common stock, shares		2,863,000
Issuance of common stock upon vesting of PSUs	0	$ 0	0	278	0	(278)
Issuance of common stock upon vesting of PSUs, shares		6,000
Stock-based compensation expense	36,427	$ 0	0	36,427	0	0
Cash dividends paid	(77,241)					(77,241)
Treasury stock issuance	0	0	$ 20	(20)	0	0
Treasury stock issuance, shares			(1,000)
Treasury stock repurchased	(19,042)	0	$ (19,042)	0	0	0
Treasury stock repurchased, shares			715,000
Other comprehensive income	180	0	$ 0	0	180	0
Net income	871,142	0	0	0	0	871,142
Ending balance at Dec. 31, 2023	$ 3,765,551	$ 2,658	$ (448,681)	$ 5,879,705	$ 647	$ (1,668,778)
Ending balance Shares at Dec. 31, 2023	265,756,369	265,756,000	24,716,000

Income Taxes - Income Tax Expense (Benefit) Attributable to Income Before Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current, Federal	$ 0	$ 0	$ 0
Current, State	1,547	14,688	7,984
Current	1,547	14,688	7,984
Deferred, Federal	230,563	245,839	6,297
Deferred, State	(2,909)	(30,067)	(24,024)
Deferred	227,654	215,772	(17,727)
Income tax expense (benefit)	$ 229,201	$ 230,460	$ (9,743)

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

Net cash provided from operating activities included:

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation The accompanying consolidated financial statements, including the notes, have been prepared in accordance with generally accepted accounting principles ("U.S. GAAP") and include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated.
Use of Estimates	Use of Estimates The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Estimated quantities of natural gas, NGLs, crude oil and condensate reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, NGLs, crude oil and condensate. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs, crude oil and condensate reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of natural gas, NGLs and crude oil and condensate that are ultimately recovered. See Note 15 for further detail. Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, valuation of certain derivative instruments, exit cost liabilities and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Business Segment Information	Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate producing activities. We 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 measure financial performance as a single enterprise and not on an area-by-area basis. All of our operating revenues, income from operations and assets are generated and located in the United States.
Revenue Recognition, Accounts Receivable and Gas Imbalances	Revenue Recognition and Accounts Receivable Natural gas, NGLs and oil sales revenues are recognized when control of the product is transferred to the customer and collectability is reasonably assured. See below for a more detailed summary of our product types. Natural Gas and NGLs Sales. Under some of our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer and we recognize revenue on a gross basis, with gathering, compression, processing and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity. In other natural gas processing agreements, we may elect to take our residue gas and/or NGLs in kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense. Oil Sales. Our oil sales contracts are generally structured in one of the following ways: • We sell oil production at the wellhead and collect an agreed-upon index price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received. • We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation, gathering, processing and compression expense. Brokered Natural Gas, Marketing and Other. We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties, and subsequently selling that natural gas or NGLs under our existing contracts to fill our contract commitments or use existing infrastructure contracts to economically utilize available capacity. In these arrangements, we take control of the natural gas purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Proceeds generated from the sale of excess firm transportation to third parties is also included here when we are determined to no longer be the primary obligor of such arrangement. Our net brokered margin was income of $4.2 million in 2023 compared to a loss of $5.4 million in 2022 and income of $1.1 million in 2021. Interest income included here was $5.9 million in 2023 compared to $2.5 million in 2022 and $243,000 in 2021. The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. We may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales or in limited cases may use them for contracts we intend to physically settle but that do not meet all of the criteria to be treated as normal sales. Accounts Receivable. Our accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties we operate. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. However, this concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. Each reporting period, we assess the recoverability of material receivables using historical data and current market conditions. The loss given default method is used when, based on management’s judgment, an allowance for expected credit losses is accrued on material receivables to reflect the net amount to be collected. In certain instances, we require purchasers to post stand-by letters of credit. For receivables from joint interest owners, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We regularly review collectability and establish or adjust our allowance as necessary. We have allowances for doubtful accounts relating to exploration and production receivables of $308,000 at December 31, 2023 compared to $314,000 at December 31, 2022. We recorded no bad debt expense in the year ended December 31, 2023 compared to a reduction of $250,000 in the year ended December 31, 2022 and expense of $200,000 in the year ended December 31, 2021.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows.
Natural Gas and Oil Properties	Natural Gas and Oil Properties Property Acquisition Costs. We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to acquire mineral interests in natural gas and oil properties, to drill exploratory wells that find proved reserves and to drill development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of proved properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have 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. Impairments. Our proved natural gas and oil properties are reviewed for impairment of value whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying value of the asset, an impairment loss is recognized based on the fair value of the asset. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. Natural gas and oil properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management which could impact the number of locations we intend to drill. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Information such as reservoir performance or future plans to develop acreage is also considered. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $789.9 million as of December 31, 2023 compared to $800.6 million in 2022. We have recorded abandonment and impairment expense related to unproved properties of $46.4 million in the year ended December 31, 2023 compared to $28.6 million in 2022 and $7.2 million in 2021. Dispositions. Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $1.5 million in the year ended December 31, 2023 compared to $2.2 million in the year ended December 31, 2022 and $2.4 million in the year ended December 31, 2021.
Leases	Leases We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling or completion equipment, office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. Certain of our lease agreements include lease and non-lease components. We account for these components as a single lease. Lease costs associated with drilling and completion equipment are capitalized as part of well costs. Lease right-of-use ("ROU") assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of our lease contracts do not provide an implicit discount rate, we use our incremental borrowing rate which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at our discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with a term of 12 months or less are not recorded as a right-of-use asset and liability. The majority of our leases are classified as either short-term or long-term operating leases. Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined and disclosed based on gross contractual obligations. Our lease costs are also presented on a gross contractual basis.
Other Assets	Other Assets Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets. Other assets at December 31, 2023 include $72.0 million of marketable securities held in our deferred compensation plan, $7.3 million of deferred financing costs related to our bank credit facility and $9.7 million of investments and other. Other assets at December 31, 2022 included $57.7 million of marketable securities held in our deferred compensation plan and $10.4 million of investments and other.
Stock-based Compensation Arrangements	Stock-based Compensation Arrangements We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 10.
Derivative Financial Instruments	Derivative Financial Instruments All of our commodity derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are important. Among these benefits are more consistent returns on invested capital and better access to bank and other capital markets, more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs. All unsettled commodity derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements, which in an event of default, allows us to offset payables to and receivables from the defaulting counterparty. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. All realized and unrealized gains and losses on derivative instruments are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of income. Certain of our commodity derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We have collars which establish a minimum floor price and a predetermined ceiling price. Our program may also include a three-way collar which is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price while the purchased put establishes the floor price until the market price for the commodity falls below the sold put stock price at which time the value of the purchased put is effectively capped. 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). We have entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location ("basis"), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. For additional information regarding our derivative instruments, see Note 8. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. We did not materially modify any existing derivative contracts in 2023, 2022 or 2021.
Concentrations of Credit Risk	Concentrations of Credit Risk As of December 31, 2023, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. The nature of our customers’ businesses may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. We may also limit the level of exposure with any single counterparty. We do not anticipate a material impact on our financial results due to non-performance by third parties. For the year ended December 31, 2023, we had one customer that accounted for 10% or more of natural gas, NGLs and oil sales compared to no such customers for the year ended December 31, 2022 and one customer for the year ended December 31, 2021. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production. We have executed International Swap Dealers Association Master Agreements ("ISDA Agreements") with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have a margin requirement or collateral provision that would require us to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2023, our derivative counterparties included fourteen financial institutions and commodity traders, of which all but six are secured lenders in our bank credit facility. At December 31, 2023, our net derivative asset includes a payable to one counterparty not included in our bank credit facility totaling $329,000 and a receivable from the remaining five counterparties of $26.4 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Historically, we have not experienced any issues of non-performance by derivative counterparties. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance.
Asset Retirement Obligations	Asset Retirement Obligations The fair value of asset retirement obligations ("ARO") is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing properties and include costs to dismantle and relocate or dispose of production platforms, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future, federal and state regulatory requirements, inflation rates and credit-adjusted-risk-free interest rates. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 7 for additional information.
Exit Costs	Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on future discounted cash outflows required to satisfy the obligation. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change utilizing the initial discount rate. These costs, including associated accretion expense, are included in exit costs in the accompanying consolidated statements of income. See Note 14 for additional information.
Contingencies	Contingencies We are subject to legal proceedings, claims, and liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 13 for a more detailed discussion regarding our contingencies.
Environmental Costs	Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.
Deferred Taxes	Deferred Taxes Deferred tax assets and liabilities, measured by the enacted tax rates, are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include whether we are in a cumulative loss position in recent years, our reversal of temporary differences and our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term in the accompanying consolidated balance sheets.
Treasury Stock	Treasury Stock Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Adoption of New Accounting Standards	Adoption of New Accounting Standards There have not been any new standards issued we consider material to our accounting or disclosures. There are no issued but pending standards expected to have a material impact on our consolidated financial statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]
Cash dividends paid per share	$ 0.32	$ 0.16

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues and other income:
Total Revenues from Contracts with Customers	$ 2,553,264	$ 5,335,309	$ 3,580,439
Derivative fair value income (loss)	821,154	(1,188,506)	(650,216)
Total revenues and other income	3,374,418	4,146,803	2,930,223
Costs and expenses:
Taxes other than income	23,726	35,367	30,648
Brokered natural gas and marketing	202,884	427,048	367,288
Exploration	26,530	26,772	23,555
Abandonment and impairment of unproved properties	46,359	28,608	7,206
General and administrative	164,740	168,085	168,435
Exit costs	99,940	70,337	21,661
Deferred compensation plan	26,593	61,880	68,351
Interest	124,004	165,145	227,336
(Gain) loss on early extinguishment of debt	(438)	69,493	98
Depletion, depreciation and amortization	350,165	353,420	364,555
Gain on the sale of assets	(454)	(409)	(701)
Total costs and expenses	2,274,075	2,732,973	2,528,188
Income before income taxes	1,100,343	1,413,830	402,035
Income tax expense (benefit) :
Current	1,547	14,688	7,984
Deferred	227,654	215,772	(17,727)
Income tax expense (benefit)	229,201	230,460	(9,743)
Net income	$ 871,142	$ 1,183,370	$ 411,778
Net income per common share:
Basic	$ 3.61	$ 4.79	$ 1.65
Diluted	$ 3.57	$ 4.69	$ 1.61
Weighted average common shares outstanding:
Basic	236,986	240,858	242,862
Diluted	239,837	246,379	249,314
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Total Revenues from Contracts with Customers	$ 2,334,661	$ 4,911,092	$ 3,215,027
Brokered Natural Gas, Marketing and Other
Revenues and other income:
Total Revenues from Contracts with Customers	218,603	424,217	365,412
Direct Operating
Costs and expenses:
Costs and expenses	96,085	84,286	75,287
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 1,113,941	$ 1,242,941	$ 1,174,469

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Income taxes paid to taxing authorities

$ (2,200)

$ (20,335)

$ (7,061)

Interest paid

(120,631)

(193,732)

(196,750)

Non-cash investing and financing activities included:

Asset retirement costs capitalized, net

^[1]

4,616

18,096

18,634

Increase (decrease) in accrued capital expenditures

$ 4,403

$ 1,966

$ (4,505)

[1]	Includes cost incurred whether capitalized or expensed.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax

Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2023				2022				2021
Federal statutory tax rate		21.0		%		21.0		%		21.0		%
State, net of federal benefit		(0.1	)			1.0				0.6
Equity compensation and executive compensation disallowance		(0.3	)			0.2				2.6
Valuation allowances		0.2				(5.5	)			(26.8	)
Permanent differences and other		—				(0.4	)			0.2
Consolidated effective tax rate		20.8		%		16.3		%		(2.4	)	%

Income Tax Expense (Benefit) Attributable to Income Before Income Taxes

Income tax expense (benefit) attributable to income before income taxes consists of the following (in thousands):


	Year Ended December 31,
	2023			2022			2021
Current
Federal	$	—		$	—		$	—
State		1,547			14,688			7,984
	$	1,547		$	14,688		$	7,984

Deferred
Federal	$	230,563		$	245,839		$	6,297
State		(2,909	)		(30,067	)		(24,024	)
		227,654			215,772			(17,727	)
Income tax expense (benefit)	$	229,201		$	230,460		$	(9,743	)

Significant Components of Deferred Tax Assets and Liabilities

Significant components of deferred tax assets and liabilities are as follows (in thousands):


	December 31,
	2023			2022
Deferred tax assets:
Net operating loss carryforward	$	538,340		$	581,349
Divestiture contract obligation		107,067			105,227
Deferred compensation		17,342			25,733
Equity compensation		6,767			4,813
Asset retirement obligations		25,614			24,113
Interest expense carryforward		19,861			16,118
Lease right-of-use liabilities		6,023			19,395
Unrealized mark-to-market loss		—			30,307
Other		16,396			16,922
Valuation allowances:
Federal		(23,396	)		(21,320	)
State, net of federal benefit		(172,001	)		(171,423	)
Total deferred tax assets		542,013			631,234
Deferred tax liabilities:
Depreciation and depletion		(998,886	)		(935,710	)
Unrealized mark-to-market gain		(96,545	)		—
Lease right-of-use assets		(5,184	)		(18,440	)
Other		(2,686	)		(10,655	)
Total deferred tax liabilities		(1,103,301	)		(964,805	)
Net deferred tax liability	$	(561,288	)	$	(333,571	)

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 871,142	$ 1,183,370	$ 411,778

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Net Income per Common Share

Derivative Activities - Effects of Derivatives on Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ 821,154	$ (1,188,506)	$ (650,216)
Contingent Consideration
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(5,080)	10,940	40,180
Swaptions
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(1,161)	11,149	(1,346)
Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)	260,630	(302,364)	(117,612)
Three Way Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)	88,096	(235,335)	(137,443)
Basis Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	43,833	41,622	33,691
Calls
Derivative [Line Items]
Derivative Fair Value Income (Loss)	0	(1,363)	(836)
Commodity \| Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	434,836	(713,122)	(466,203)
Freight \| Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ 0	$ (33)	$ (647)

Net Income Per Common Share

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

(5) Net Income per Common Share

Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income or loss per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts):


	Year Ended December 31,
	2023			2022			2021
Net income as reported	$	871,142		$	1,183,370		$	411,778
Participating basic earnings (a)		(14,971	)		(28,578	)		(10,795	)
Basic net income attributed to common stockholders		856,171			1,154,792			400,983
Reallocation of participating earnings (a)		159			614			272
Diluted net income attributed to common stockholders	$	856,330		$	1,155,406		$	401,255
Net income per common share:
Basic	$	3.61		$	4.79		$	1.65
Diluted	$	3.57		$	4.69		$	1.61


(a)	Restricted stock Liability 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.

The following table details basic weighted average common shares outstanding and diluted weighted average common shares outstanding (in thousands):


	Year Ended December 31,
	2023		2022		2021
Denominator:
Weighted average common shares outstanding – basic		236,986		240,858		242,862
Effect of dilutive securities		2,851		5,521		6,452
Weighted average common shares outstanding – diluted		239,837		246,379		249,314

Weighted average common shares outstanding – basic excludes 4.1 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for the period ended December 31, 2023 compared to 6.1 million shares for the period ended December 31, 2022 and 6.5 million shares for the period ended December 31, 2021. Equity grants of 3,000 for the year ended December 31, 2023 compared to 5,000 shares for the year ended December 31, 2022 and 18,000 shares for the year ended December 31, 2021 were outstanding but not included in the computation of diluted net income because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Acquisitions

Acreage purchases

^[1]

$ 40,067

$ 28,735

$ 21,942

Development

^[1]

568,484

460,668

381,753

Gas gathering facilities:

Development

^[1]

3,123

1,466

3,402

Subtotal

^[1]

638,204

517,641

436,981

Asset retirement obligations

^[1]

4,616

18,096

18,634

Total costs incurred

^[1]

642,820

535,737

455,615

Exploration Expense

Exploration:

Exploration drilling costs incurred

^[1]

6,329

Exploration costs incurred

^[1]

25,280

25,194

22,048

Stock-based compensation expense

^[1]

$ 1,250

$ 1,578

$ 1,507

[1]	Includes cost incurred whether capitalized or expensed.

Net Income Per Common Share (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Computations of Basic and Diluted Income (Loss) Per Common Share


	Year Ended December 31,
	2023			2022			2021
Net income as reported	$	871,142		$	1,183,370		$	411,778
Participating basic earnings (a)		(14,971	)		(28,578	)		(10,795	)
Basic net income attributed to common stockholders		856,171			1,154,792			400,983
Reallocation of participating earnings (a)		159			614			272
Diluted net income attributed to common stockholders	$	856,330		$	1,155,406		$	401,255
Net income per common share:
Basic	$	3.61		$	4.79		$	1.65
Diluted	$	3.57		$	4.69		$	1.61


(a)	Restricted stock Liability 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.

Basic Weighted Average Common Shares Outstanding and Diluted Weighted Average Common Shares Outstanding

The following table details basic weighted average common shares outstanding and diluted weighted average common shares outstanding (in thousands):


	Year Ended December 31,
	2023		2022		2021
Denominator:
Weighted average common shares outstanding – basic		236,986		240,858		242,862
Effect of dilutive securities		2,851		5,521		6,452
Weighted average common shares outstanding – diluted		239,837		246,379		249,314

Stock-Based Compensation Plans - Additional Information 3 (Detail) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Award $ / shares	Dec. 31, 2022 USD ($) Award $ / shares	Dec. 31, 2021 USD ($) Award $ / shares
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation related to Awards	$ 1.7
Weighted average period	1 year 10 months 24 days
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares granted \| Award	64,000	112,000	224,000
Vesting period	3 years
Stock-based compensation expense	$ 1.7	$ 3.2	$ 2.6
Unrecognized compensation related to Awards	$ 1.7
Weighted average period	1 year 10 months 24 days
Performance-based PS-PSUs and RS-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares granted \| Award	81,000	153,000	303,000
Granted, weighted average grant date fair value \| $ / shares	$ 24.08	$ 20.38	$ 9.81
Vesting period	3 years
Stock-based compensation expense	$ 2.2	$ 6.2	$ 6.6

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Changes in Number of Common Shares Outstanding

The following is a schedule of changes in the number of common shares outstanding since the beginning of 2022:


	Year Ended December 31,
	2023			2022
Beginning balance		238,885,730			249,792,908
Restricted stock grants		50,238			671,303
Restricted stock units vested		1,755,345			1,827,625
Performance stock units vested		1,057,245			590,940
Performance stock dividends		6,276			1,843
Treasury shares		(714,530	)		(13,998,889	)
Ending balance		241,040,304			238,885,730

Schedule of Change in Treasury Shares

The following is a schedule of the change in treasury shares since the beginning of 2022:


	Year Ended December 31,
	2023			2022
Beginning balance		24,001,535			10,002,646
Rabbi trust shares distributed and/or sold		(470	)		(1,111	)


Shares repurchased	715,000	14,000,000
Ending balance	24,716,065	24,001,535

Capital Stock - Schedule of Changes in Number of Common Shares Outstanding (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Class Of Stock [Line Items]
Beginning balance	238,885,730	249,792,908
Treasury shares	(714,530)	(13,998,889)
Ending balance	241,040,304	238,885,730
Restricted Stock
Class Of Stock [Line Items]
Restricted stock grants	50,238	671,303
Restricted stock units vested	1,755,345	1,827,625
Performance Share
Class Of Stock [Line Items]
Performance stock units vested	1,057,245	590,940
Performance stock dividends	6,276	1,843

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Activities

12 Months Ended

Dec. 31, 2023

Derivative Activities

(8) 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 do not utilize complex derivatives as we typically utilize commodity swaps or collar contracts 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. Every derivative instrument is required to be recorded on our consolidated balance sheets as either an asset or a liability measured at its fair value. Their fair value, which is represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price (generally NYMEX for natural gas and crude oil), approximated a net derivative asset of $424.4 million at December 31, 2023. These contracts expire monthly through December 2026. The following table sets forth the derivative volumes by year as of December 31, 2023, excluding our basis swaps which are discussed separately below:


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
			Swap		Sold Put		Floor		Ceiling
Natural Gas (a)
2024	Swaps	304,973 Mmbtu/day	$	4.01
2024	Collars	436,694 Mmbtu/day					$	3.50	$	5.63
2024	Three-way Collars	93,511 Mmbtu/day			$	2.50	$	3.40	$	4.15
2025	Swaps	400,000 Mmbtu/day	$	4.12
2025	Three-way Collars	30,000 Mmbtu/day			$	2.70	$	4.00	$	5.00
2026	Swaps	60,000 Mmbtu/day	$	4.15

Crude Oil
January-September 2024	Swaps	4,000 bbls/day	$	80.25
January-September 2024	Collars	832 bbls/day					$	80.00	$	90.12


(a)	We also sold natural gas swaptions of 40,000 Mmbtu/day for calendar year 2026 at a weighted average price of $4.11/Mmbtu that expire June 2024.

Basis Swap Contracts

In addition to the commodity derivatives described above, at December 31, 2023, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through December 2026 and include a total volume of 313,453,000 Mmbtu. The fair value of these contracts was a net derivative asset of $18.3 million on December 31, 2023.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2023 and 2022 is summarized below (in thousands). As of December 31, 2023, we are conducting derivative activities with fourteen counterparties, of which all but six are secured lenders in our bank credit facility. We believe all of these counterparties are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. 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.


		December 31, 2023
		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	$	238,465	$	—		$	238,465
	–swaptions		—		(1,161	)		(1,161	)
	–collars		150,456		—			150,456
	–three-way collars		25,406		—			25,406
	–basis swaps		26,852		(8,246	)		18,606
Crude oil	–swaps		9,115		—			9,115
	–collars		2,084		—			2,084
		$	452,378	$	(9,407	)	$	442,971


		December 31, 2023
		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	–swaptions	$	(1,161	)	$	1,161	$	—
	–basis swaps		(8,575	)		8,246		(329	)
		$	(9,736	)	$	9,407	$	(329	)


		December 31, 2022
		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	$	19,438	$	(6,236	)	$	13,202
	–collars		54,222		(45,452	)		8,770
	–three-way collars		12,424		(12,424	)		—
	–basis swaps		25,493		(20,437	)		5,056
Crude oil	–collars		1,807		—			1,807
Divestiture contingent consideration			13,080		—			13,080
		$	126,464	$	(84,549	)	$	41,915


		December 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	$	(115,374	)	$	6,236	$	(109,138	)
	–collars		(72,866	)		45,452		(27,414	)
	–three-way collars		(24,341	)		12,424		(11,917	)
	–basis swaps		(24,972	)		20,437		(4,535	)
Crude oil	–swaps		(13,908	)		—		(13,908	)
		$	(251,461	)	$	84,549	$	(166,912	)

The effects of our derivatives on our consolidated statements of income for the last three years are summarized below (in thousands).


	Year Ended December 31,
Derivative Fair Value Income (Loss)	2023			2022			2021
Commodity swaps	$	434,836		$	(713,122	)	$	(466,203	)
Swaptions		(1,161	)		11,149			(1,346	)
Collars		260,630			(302,364	)		(117,612	)
Three-way collars		88,096			(235,335	)		(137,443	)
Basis swaps		43,833			41,622			33,691
Calls		—			(1,363	)		(836	)
Freight swaps		—			(33	)		(647	)
Divestiture contingent consideration		(5,080	)		10,940			40,180
Total	$	821,154		$	(1,188,506	)	$	(650,216	)

Revenues from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue by Identified Revenue Stream

Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):


	Year Ended December 31,
	2023		2022		2021
Natural gas sales	$	1,234,308	$	3,364,111	$	1,896,231
NGLs sales		933,791		1,308,574		1,135,826
Oil and condensate sales		166,562		238,407		182,970
Total natural gas, NGLs and oil sales		2,334,661		4,911,092		3,215,027
Sales of purchased natural gas		195,656		408,584		342,431
Sales of purchased NGLs		1,834		2,783		6,925
Interest income		5,937		2,538		243
Other marketing revenue and other income		15,176		10,312		15,813
Total	$	2,553,264	$	5,335,309	$	3,580,439

Commitments and Contingencies - Supplemental Balance Sheet Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Loss Contingencies [Line Items]
Operating lease ROU assets	$ 23,821	$ 84,070
Accrued liabilities – current	$ (11,584)	$ (67,493)
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued Liabilities, Current	Accrued Liabilities, Current
Operating lease liabilities – long-term	$ (16,064)	$ (20,903)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Operating lease liabilities – long-term	Operating lease liabilities – long-term

Fair Value Measurements - Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy (Detail) - Fair Value, Inputs, Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at December 31, 2022	$ 0
Additions	(1,161)
Settlements	0
Transfers out of Level 3	0
Balance at December 31, 2023	$ (1,161)

Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(13) 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 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 December 31, 2023 and 2022, liabilities for remediation were not material. We are not aware of any environmental claims existing as of December 31, 2023 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. We believe that substantially all of our competitors must comply with similar environmental laws and regulations.

Obligations Following Divestitures

Certain contractual obligations were retained by us after our divestiture of our North Louisiana assets in 2020. These obligations are primarily related to gathering, processing and transportation agreements including certain minimum volume commitments. For additional information see Note 14.

Lease Commitments

The components of our total lease expense for the two years ended December 31, 2023, the majority of which is included as part of natural gas and oil properties on our consolidated balance sheets, are as follows (in thousands):


	Year Ended December 31,
	2023		2022
Operating lease cost	$	70,781	$	37,873
Variable lease expense (1)		25,529		22,082
Short-term lease expense (2)		708		1,807
Sublease income		—		(137	)
Total lease expense	$	97,018	$	61,625

Short-term lease costs (3)	$	14,032	$	17,285


(1)	Variable lease payments that are not dependent on an index or rate and are not included in the lease liability or ROU assets.
(2)	Short-term lease expense represents expense related to leases with a contract term of one year or less and are not included in our ROU assets or lease liability in our consolidated balance sheets.


(3)	These short-term lease costs are related to leases with a contract term of one year or less, the majority of which are related to drilling rigs which are capitalized as part of natural gas and oil properties on our consolidated balance sheets and may fluctuate based on the number of drilling rigs being utilized.

Supplemental cash flow information related to our operating leases is included in the table below (in thousands):


	Year Ended December 31,
	2023		2022
Cash paid for amounts included in the measurement of lease liabilities	$	71,669	$	37,457
ROU assets added in exchange for lease obligations	$	7,421	$	78,574

Supplemental balance sheet information related to our operating leases is included in the table below (in thousands):


	Year Ended December 31,
	2023			2022
Operating lease ROU assets	$	23,821		$	84,070
Accrued liabilities – current	$	(11,584	)	$	(67,493	)
Operating lease liabilities – long-term	$	(16,064	)	$	(20,903	)

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:


	Year Ended December 31,
	2023	2022
Weighted average remaining lease term	2.9 years	2.0 years
Weighted average discount rate	7%	6%

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):


	Operating Leases
2024	$	13,119
2025		7,921
2026		6,866
2027		2,698
2028		29
Total lease payments		30,633
Less effects of discounting		(2,985	)
Total lease liability	$	27,648

In late 2023, we entered into two-year commitments for drilling and completions equipment with gross lease payments of approximately $152.0 million. These leases are effective January 1, 2024 and will be recognized on our balance sheet as a lease in 2024.

Transportation, Gathering and Processing Contracts

We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania. Under these contracts, we are obligated to transport or gather minimum daily natural gas volumes or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is currently expected to exceed the minimum daily volumes provided in the contracts. However, if in the future we fail to deliver the committed volumes, we would recognize a deficiency payment in the period in which the under-delivery takes place and the related liability has been incurred. As of December 31, 2023, future minimum transportation and gathering fees under our commitments are as follows (in thousands):


	Transportation and Gathering Contracts (a)
2024	$	801,694
2025		730,907
2026		670,692
2027		616,260
2028		565,707


Thereafter		2,504,906
	$	5,890,166


(a)	The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

In addition to the amounts included in the above table, we have entered into an additional agreement which modifies existing contracts that are included in the table above but are contingent on additional facility construction. This agreement is expected to begin in 2024 with a twelve-year term and adds to our ability to efficiently flow production volumes. The revised agreement covers 650,000 mcf per day but declines in the last five years of the contract ending at 300,000 mcf per day.

Not included in the table above is our estimate of accrued contractual obligations retained by us after our divestiture of our North Louisiana assets. These contractual obligations are related to gathering, processing and transportation agreements including certain minimum volume commitments. There are inherent uncertainties surrounding the retained obligation and, as a result, the determination of the accrued obligation required significant judgment and estimation. The actual settlement amount and timing may differ from our estimates. See also Note 14 for more information. As of December 31, 2023, the carrying value of this obligation was $397.4 million and is included in divestiture contract obligation in our consolidated balance sheets. As of December 31, 2023, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands):


	Divestiture Contract Obligation
2024	$	86,762
2025		77,418
2026		61,805
2027		52,622
2028		48,116
Thereafter		70,727
	$	397,450

Delivery Commitments

We have various volume delivery commitments that are related to our Marcellus Shale properties. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2023, our delivery commitments through 2037 were as follows:


Year Ending December 31,	Natural Gas (mmbtu per day)	Ethane and Propane (bbls per day)
2024	302,404	70,000
2025	282,493	54,932
2026	200,548	50,000
2027	100,000	46,233
2028	100,000	45,000
2029	100,000	33,444
2030	—	30,000
2031	—	16,575
2032-2037	—	10,000 (each year)

Other

We have lease acreage that is generally subject to expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs. We also regularly provide letters of credit in the normal course of business under certain contracts that may be drawn if we fail to perform under those contracts.

Stock-Based Compensation Plans - Restricted Stock and Restricted Stock Units and Performance Awards Outstanding (Detail) - $ / shares

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Restricted Stock Equity Awards

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Outstanding, Beginning Balance

1,736,688

Granted

1,629,816

1,400,000

2,300,000

Vested

(1,863,153)

Forfeited

(29,546)

Outstanding, Ending Balance

1,473,805

1,736,688

Outstanding, Beginning Balance, weighted average grant date fair value

$ 14.44

$ 7.39

Granted, weighted average grant date fair value

25.11

Vested and issued, weighted average grant date fair value

17.1

Forfeited, weighted average grant date fair value

17.73

Outstanding, Ending Balance, weighted average grant date fair value

$ 22.82

$ 14.44

$ 7.39

Restricted Stock Liability Awards

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Outstanding, Beginning Balance

379,633

Granted

21,170

Vested

(307,687)

Forfeited

Outstanding, Ending Balance

93,116

379,633

Outstanding, Beginning Balance, weighted average grant date fair value

$ 14.71

$ 6.49

Granted, weighted average grant date fair value

25.41

Vested and issued, weighted average grant date fair value

14.01

Forfeited, weighted average grant date fair value

Outstanding, Ending Balance, weighted average grant date fair value

$ 19.44

$ 14.71

$ 6.49

Stock Based Performance Awards

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Outstanding, Beginning Balance

^[1]

1,950,632

Granted

^[1]

145,747

Vested

^[1]

(1,158,797)

Forfeited

^[1]

Outstanding, Ending Balance

^[1]

937,582

1,950,632

Outstanding, Beginning Balance, weighted average grant date fair value

$ 9.02

Granted, weighted average grant date fair value

26.86

Vested and issued, weighted average grant date fair value

4.8

Forfeited, weighted average grant date fair value

Outstanding, Ending Balance, weighted average grant date fair value

$ 17.01

$ 9.02

[1]


(a)	Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200% depending on achievement of either total stockholder return ranking compared to our peers at the vesting date or on the achievement of internal performance targets.

Indebtedness

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Indebtedness

(6) Indebtedness

We had the following debt outstanding as of the dates shown below. The expenses of issuing debt are generally capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. For December 31, 2023, deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized in the three-year period ended December 31, 2023. The components of our debt outstanding, including the effects of debt issuance costs, is as follows (in thousands):


	December 31,
	2023			2022
Bank debt	$	—		$	19,000
Senior notes
4.875% senior notes due 2025		688,388			750,000
8.25% senior notes due 2029		600,000			600,000
4.75% senior notes due 2030		500,000			500,000
Total senior notes		1,788,388			1,850,000
Total debt		1,788,388			1,869,000
Unamortized debt issuance costs		(14,159	)		(27,040	)
Total debt (net of debt issuance costs)	$	1,774,229		$	1,841,960

Bank Debt

In April 2022, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, and is secured by substantially all of our assets and has a maturity date of April 14, 2027. The bank credit facility provides for a maximum facility amount of $4.0 billion and an initial borrowing base of $3.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations and for event-driven unscheduled redeterminations. Our current bank group is composed of seventeen financial institutions. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. Borrowings under the bank facility can either be at the alternate base rate ("ABR," as defined in the bank credit agreement) plus a spread ranging from 0.75% to 1.75% or at the secured overnight financing rate ("SOFR", as defined in the bank credit 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 SOFR loans to ABR loans or to convert all or any part of our ABR loans to SOFR loans. The weighted average interest rate was 8.4% for the year ended December 31, 2023 compared to 4.1% for the year ended December 31, 2022 and 2.1% for the year ended December 31, 2021. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2023, the commitment fee was 0.375%, the interest rate margin was 0.75% on our ABR loans and 1.75% on our SOFR loans.

On December 31, 2023, bank commitments totaled $1.5 billion and we had no outstanding borrowings under our bank credit facility. Additionally, we had $173.4 million of undrawn letters of credit leaving $1.3 billion of committed borrowing capacity available under the facility. As part of our redetermination completed in September 2023, our borrowing base was reaffirmed for $3.0 billion and our bank commitment was also reaffirmed at $1.5 billion.

Senior Note Redemptions

If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior notes at 101% of the principal amount plus accrued and unpaid interest, if any. We currently intend to retire our outstanding long-term debt as it matures, is callable or when market conditions are favorable to repurchase in the open market.

In 2023, we repurchased in the open market $61.6 million principal amount of our 4.875% senior notes due 2025 at a discount. We recognized a gain on early extinguishment of debt of $438,000, net of the remaining deferred financing costs on the repurchased debt. Although we have no obligation to do so, we may continue, from time-to-time, to retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions or otherwise.

In January 2024, we repurchased in the open market $8.7 million aggregate to principal amount of our 4.875% senior notes due 2025 at a discount.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly-owned subsidiaries, which are directly or indirectly owned by Range, of our senior notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. The assets, liabilities and results of operations of Range and our guarantor subsidiaries are not materially different than our consolidated financial statements. A subsidiary guarantor may be released from its obligations under the guarantee:

•

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

•

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

Debt Covenants and Maturity

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. We are required to maintain a ratio of debt-to-EBITDAX (as defined in the credit agreement) of less than 3.75x and a minimum current ratio (as defined in the credit agreement) of 1.0x. We were in compliance with applicable covenants under the bank credit facility at December 31, 2023. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2023 (in thousands):


	Year Ended December 31,
2024	$	—
2025		688,388
2026		—
2027		—
2028		—
Thereafter		1,100,000
	$	1,788,388

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-Paragraph 1
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Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2023 bbl / d MmbtuPerDay
2024 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	302,404
2024 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	70,000
2025 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	282,493
2025 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	54,932
2026 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	200,548
2026 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	50,000
2027 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	100,000
2027 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	46,233
2028 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	100,000
2028 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	45,000
2029 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	100,000
2029 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	33,444
2030 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	0
2030 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	30,000
2031 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	0
2031 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	16,575
2032-2037 \| Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MmbtuPerDay	0
2032-2037 \| Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| bbl / d	10,000

Dispositions - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets	$ 454	$ 409	$ 701
Proceeds from disposal of assets	872	518	$ 303
Gross Amounts of Recognized Assets	$ 452,378	126,464
Contingent Consideration
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gross Amounts of Recognized Assets		$ 13,080

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities:
Net income	$ 871,142,000	$ 1,183,370,000	$ 411,778,000
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income tax expense (benefit)	227,654,000	215,772,000	(17,727,000)
Depletion, depreciation and amortization and impairment of proved properties	350,165,000	353,420,000	364,555,000
Abandonment and impairment of unproved properties	46,359,000	28,608,000	7,206,000
Derivative fair value (income) loss	(821,154,000)	1,188,506,000	650,216,000
Cash settlements on derivative financial instruments	253,514,000	(1,190,154,000)	(520,013,000)
Divestiture contract obligation	99,595,000	69,766,000	20,340,000
Allowance for bad debt	0	(250,000)	200,000
Amortization of deferred financing costs and other	4,735,000	7,959,000	8,347,000
Deferred and stock-based compensation	67,849,000	107,959,000	110,356,000
Gain on the sale of assets	(454,000)	(409,000)	(701,000)
(Gain) loss on early extinguishment of debt	(438,000)	69,493,000	98,000
Changes in working capital:
Accounts receivable	223,081,000	(3,286,000)	(250,538,000)
Prepaid and other	(1,285,000)	(18,438,000)	(1,140,000)
Accounts payable	(77,057,000)	17,077,000	39,231,000
Accrued liabilities and other	(265,814,000)	(164,649,000)	(29,260,000)
Net cash provided from operating activities	977,892,000	1,864,744,000	792,948,000
Investing activities:
Additions to natural gas and oil properties	(571,819,000)	(456,505,000)	(393,478,000)
Additions to field service assets	(701,000)	(682,000)	(1,231,000)
Acreage purchases	(34,410,000)	(30,885,000)	(23,962,000)
Proceeds from disposal of assets	872,000	518,000	303,000
Purchases of marketable securities held by the deferred compensation plan	(45,168,000)	(43,691,000)	(30,806,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	49,521,000	41,413,000	31,295,000
Net cash used in investing activities	(601,705,000)	(489,832,000)	(417,879,000)
Financing activities:
Borrowings on credit facilities	185,000,000	972,000,000	1,434,000,000
Repayments on credit facilities	(204,000,000)	(953,000,000)	(2,136,000,000)
Issuance of senior notes	0	500,000,000	600,000,000
Repayment of senior or senior subordinated notes	(60,934,000)	(1,659,422,000)	(63,324,000)
Dividends paid	(77,241,000)	(38,638,000)	0
Treasury stock purchases	(19,042,000)	(399,699,000)	0
Debt issuance costs	0	(16,176,000)	(8,854,000)
Taxes paid for shares withheld	(39,481,000)	(25,492,000)	(9,299,000)
Change in cash overdrafts	(23,923,000)	9,071,000	16,493,000
Proceeds from the sales of common stock held by the deferred compensation plan	75,201,000	22,229,000	5,879,000
Net cash used in financing activities	(164,420,000)	(1,589,127,000)	(161,105,000)
Increase (decrease) in cash and cash equivalents	211,767,000	(214,215,000)	213,964,000
Cash and cash equivalents at beginning of year	207,000	214,422,000	458,000
Cash and cash equivalents at end of year	$ 211,974,000	$ 207,000	$ 214,422,000

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 871,142	$ 1,183,370	$ 411,778
Postretirement benefits:
Actuarial (loss) gain	(12)	482	62
Prior service cost	296	0	0
Amortization of prior service costs	(41)	292	369
Income tax expense	(63)	(157)	(102)
Total comprehensive income	$ 871,322	$ 1,183,987	$ 412,107

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Indebtedness - Debt Outstanding (Parenthetical) (Detail)	Dec. 31, 2023	Dec. 31, 2022
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes	4.875%	4.875%
8.25% Senior Notes Due 2029
Debt Instrument [Line Items]
Interest rate on notes	8.25%	8.25%
4.75% Senior Notes Due 2030
Debt Instrument [Line Items]
Interest rate on notes	4.75%	4.75%

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Revenue from Contract with Customer [Abstract]

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 308,000	$ 314,000
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	265,756,369	262,887,265
Common stock held in treasury, shares	24,716,065	24,001,535

Revenues from Contracts with Customers

12 Months Ended

Dec. 31, 2023

Revenues from Contracts with Customers

(3) Revenues from Contracts with Customers

Disaggregation of Revenue

We have identified three material revenue streams in our business: natural gas sales, NGLs sales, crude oil and condensate sales. Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):


	Year Ended December 31,
	2023		2022		2021
Natural gas sales	$	1,234,308	$	3,364,111	$	1,896,231
NGLs sales		933,791		1,308,574		1,135,826
Oil and condensate sales		166,562		238,407		182,970
Total natural gas, NGLs and oil sales		2,334,661		4,911,092		3,215,027
Sales of purchased natural gas		195,656		408,584		342,431
Sales of purchased NGLs		1,834		2,783		6,925
Interest income		5,937		2,538		243
Other marketing revenue and other income		15,176		10,312		15,813
Total	$	2,553,264	$	5,335,309	$	3,580,439

Performance Obligations and Contract Balance

A significant number of our product sales are short-term in nature with a contract term of one year or less. We typically satisfy our performance obligation upon transfer of control and record revenue in the month production is delivered to the purchaser. Settlement statements for certain gas and NGLs sales may be received 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. We have internal controls in place for our estimation process and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three years ended December 31, 2023, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $263.9 million at December 31, 2023 compared to $463.3 million at December 31, 2022.

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

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Capital Stock

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Capital Stock

(11) 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. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2022:


	Year Ended December 31,
	2023			2022
Beginning balance		238,885,730			249,792,908
Restricted stock grants		50,238			671,303
Restricted stock units vested		1,755,345			1,827,625
Performance stock units vested		1,057,245			590,940
Performance stock dividends		6,276			1,843
Treasury shares		(714,530	)		(13,998,889	)
Ending balance		241,040,304			238,885,730

Common Stock Dividends

In January 2020, we announced that the board of directors had suspended our common stock dividend. The quarterly cash dividend was reinstated by our board of directors in third quarter 2022. 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 will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors deems relevant. Our bank credit facility allows for the payment of common dividends, with certain limitations, as described in the facility agreement.

Stock Repurchase Program

In October 2019, the board of directors approved a stock repurchase program which was increased in size in 2022. Under this program, we may repurchase shares of our common stock in open market transactions, from time to time, in accordance with applicable SEC rules and federal securities laws. In 2023, we repurchased 715,000 shares at an aggregate value of $19.0 million. As of December 31, 2023, we have approximately $1.1 billion of remaining authorization under this program. The following is a schedule of the change in treasury shares since the beginning of 2022:


	Year Ended December 31,
	2023			2022
Beginning balance		24,001,535			10,002,646
Rabbi trust shares distributed and/or sold		(470	)		(1,111	)


Shares repurchased	715,000	14,000,000
Ending balance	24,716,065	24,001,535

The entire disclosure for equity.

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Fair Value Measurements - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends	$ 1,600,000	$ 1,100,000	$ 951,000
Mark-to-market gain (loss)	$ 7,800,000	$ (14,200,000)	$ 3,000,000
Measurement Input, Price Volatility \| Weighted Average \| Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Implied volatilities	18.00%

Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2023	Feb. 19, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2023
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Registrant Name	RANGE RESOURCES CORPORATION
Entity Central Index Key	0000315852
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		242,119,571
Entity Public Float			$ 7,720,683,000
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity File Number	001-12209
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	34-1312571
Entity Address, Address Line One	100 Throckmorton Street
Entity Address, Address Line Two	Suite 1200
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	870-2601
Document Annual Report	true
Document Transition Report	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Interactive Data Current	Yes
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement to be furnished to stockholders in connection with its 2024 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are incorporated by reference in Part II, Item 5 and Part III, Items 10-14 of this report.
Title of 12(b) Security	Common Stock, $.01 par value
Trading Symbol	RRC
Security Exchange Name	NYSE
ICFR Auditor Attestation Flag	true
Auditor Name	Ernst & Young LLP
Auditor Firm ID	42
Auditor Location	Fort Worth, Texas
Document Financial Statement Error Correction [Flag]	false

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Parenthetical) (Detail) - MMcfe	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reserve Quantities [Line Items]
Proved undeveloped reserves removed and deferred	370,600
Natural Gas Equivalents
Reserve Quantities [Line Items]
Additional undeveloped properties reclassified	280,200	716,200

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Reported Value Measurement

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - 2026 Commodity Contract - Swaptions [Member]	12 Months Ended
	Dec. 31, 2023 MmbtuPerDay $ / MMBTU
Derivative [Line Items]
Volume hedged \| MmbtuPerDay	40,000
Weighted average price of hedge \| $ / MMBTU	4.11
Expiration of derivative non monetary notional amount	Jun. 30, 2024

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($)
$ in Thousands

Dec. 31, 2023

Dec. 31, 2022

Assets:

Marketable securities

$ 72,000

$ 57,700

Assets:

442,971

28,835

Marketable securities

^[1]

71,989

57,717

Deferred compensation plan

(329)

(166,912)

Bank credit facility

^[2]

(19,000)

^[3]

(117,125)

(189,241)

Reported Value Measurement | Contingent Consideration

Assets:

Divestiture contingent consideration

13,080

Estimate of Fair Value Measurement

Assets:

442,971

28,835

Marketable securities

^[1]

71,989

57,717

Deferred compensation plan

(329)

(166,912)

Bank credit facility

^[2]

(19,000)

^[3]

(117,125)

(189,241)

Estimate of Fair Value Measurement | Contingent Consideration

Assets:

Divestiture contingent consideration

13,080

4.875% Senior Notes Due 2025 | Reported Value Measurement

4.875% Senior Notes Due 2025 | Estimate of Fair Value Measurement

^[2]

(688,388)

(750,000)

8.25% Senior Notes Due 2029 | Reported Value Measurement

^[2]

(679,363)

(714,870)

8.25% Senior Notes Due 2029 | Estimate of Fair Value Measurement

^[2]

(600,000)

4.75% Senior Notes Due 2030 | Reported Value Measurement

^[2]

(624,816)

(618,312)

4.75% Senior Notes Due 2030 | Estimate of Fair Value Measurement

^[2]

(500,000)

^[2]

$ (463,085)

$ (442,350)

[1]	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are updated based on end of period closing prices which is a Level 1 input.
[2]	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.
[3]	The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Revenues from Contracts with Customers - Disaggregation of Revenue by Identified Revenue Stream (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Total Revenue	$ 2,553,264,000	$ 5,335,309,000	$ 3,580,439,000
Natural Gas, NGLs and Oil Sales
Disaggregation of Revenue [Line Items]
Total Revenue	2,334,661,000	4,911,092,000	3,215,027,000
Natural Gas, NGLs and Oil Sales \| Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,234,308,000	3,364,111,000	1,896,231,000
Natural Gas, NGLs and Oil Sales \| NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	933,791,000	1,308,574,000	1,135,826,000
Natural Gas, NGLs and Oil Sales \| Oil and condensate sales
Disaggregation of Revenue [Line Items]
Total Revenue	166,562,000	238,407,000	182,970,000
Brokered Natural Gas, Marketing and Other
Disaggregation of Revenue [Line Items]
Total Revenue	218,603,000	424,217,000	365,412,000
Brokered Natural Gas, Marketing and Other \| Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	195,656,000	408,584,000	342,431,000
Brokered Natural Gas, Marketing and Other \| NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,834,000	2,783,000	6,925,000
Brokered Natural Gas, Marketing and Other \| Interest Income
Disaggregation of Revenue [Line Items]
Total Revenue	5,937,000	2,538,000	243,000
Brokered Natural Gas, Marketing and Other \| Other Marketing Revenue And Other Income [Member]
Disaggregation of Revenue [Line Items]
Total Revenue	$ 15,176,000	$ 10,312,000	$ 15,813,000

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

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Capital Stock - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Class Of Stock Disclosures [Abstract]
Authorized capital stock	485,000,000
Common stock, shares authorized	475,000,000	475,000,000
Preferred stock, shares authorized	10,000,000	10,000,000
Share repurchase, aggregate cost	$ 19.0
Stock Repurchased During Period, Shares	715,000	14,000,000
Stock repurchase program, authorized amount	$ 1,100.0

Number of shares that have been repurchased during the period and have not been retired and are not held in treasury. Some state laws may govern the circumstances under which an entity may acquire its own stock and prescribe the accounting treatment therefore. This element is used when state law does not recognize treasury stock.

Schedule for Long-Term Debt Outstanding

Commitments and Contingencies - Schedule of Lease Liabilities with Enforceable Contract Terms are Greater Than One year Mature (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2024	$ 13,119
2025	7,921
2026	6,866
2027	2,698
2028	29
Total lease payments	30,633
Less effects of discounting	(2,985)
Total lease liability	$ 27,648

Indebtedness (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt Outstanding


	December 31,
	2023			2022
Bank debt	$	—		$	19,000
Senior notes
4.875% senior notes due 2025		688,388			750,000
8.25% senior notes due 2029		600,000			600,000
4.75% senior notes due 2030		500,000			500,000
Total senior notes		1,788,388			1,850,000
Total debt		1,788,388			1,869,000
Unamortized debt issuance costs		(14,159	)		(27,040	)
Total debt (net of debt issuance costs)	$	1,774,229		$	1,841,960

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2023 (in thousands):


	Year Ended December 31,
2024	$	—
2025		688,388
2026		—
2027		—
2028		—
Thereafter		1,100,000
	$	1,788,388

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

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-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2023

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)


	December 31,
	2023			2022			2021
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	10,435,611		$	9,855,287		$	9,338,236
Unproved properties		789,871			800,592			837,334
Total		11,225,482			10,655,879			10,175,570
Accumulated depreciation, depletion and amortization		(5,107,801	)		(4,765,475	)		(4,420,914	)
Net capitalized costs	$	6,117,681		$	5,890,404		$	5,754,656

(a)

Includes capitalized asset retirement costs and the associated accumulated amortization.

Costs Incurred for Property Acquisition, Exploration and Development

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


	December 31,
	2023		2022		2021
	(in thousands)
Acquisitions:
Acreage purchases	$	40,067	$	28,735	$	21,942
Development		568,484		460,668		381,753
Exploration:
Drilling		—		—		6,329
Expense		25,280		25,194		22,048
Stock-based compensation expense		1,250		1,578		1,507
Gas gathering facilities:
Development		3,123		1,466		3,402
Subtotal		638,204		517,641		436,981
Asset retirement obligations		4,616		18,096		18,634
Total costs incurred	$	642,820	$	535,737	$	455,615

(a)

Includes cost incurred whether capitalized or expensed.

Proved Developed and Undeveloped Reserves


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) (a)
Proved developed and undeveloped reserves:
Balance, December 31, 2020		11,148,560			951,466			57,626			17,203,114
Revisions		(311,410	)		16,845			(7,089	)		(252,876	)
Extensions, discoveries and additions		1,155,952			69,367			5,103			1,602,769
Production		(541,021	)		(36,373	)		(3,044	)		(777,523	)
Balance, December 31, 2021		11,452,081			1,001,305			52,596			17,775,484
Revisions		(393,165	)		(20,251	)		(12,885	)		(591,983	)
Extensions, discoveries and additions		1,278,499			59,296			5,661			1,668,244
Production		(539,443	)		(36,392	)		(2,716	)		(774,089	)
Balance, December 31, 2022		11,797,972			1,003,958			42,656			18,077,656
Revisions		326,783			44,515			2,485			608,784
Extensions, discoveries and additions		24,078			30,234			296			207,260
Production		(538,085	)		(37,940	)		(2,475	)		(780,575	)
Balance, December 31, 2023		11,610,748			1,040,767			42,962			18,113,125
Proved developed reserves:
December 31, 2021		6,809,849			577,506			23,833			10,417,887
December 31, 2022		7,230,313			594,931			22,213			10,933,180
December 31, 2023		7,631,202			629,379			21,396			11,535,852
Proved undeveloped reserves:
December 31, 2021		4,642,232			423,798			28,762			7,357,597
December 31, 2022		4,567,659			409,027			20,443			7,144,476
December 31, 2023		3,979,546			411,388			21,566			6,577,273

(a)

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

Changes in Proved Undeveloped Reserves

The following details the changes in proved undeveloped reserves for 2023 (Mmcfe):


Beginning proved undeveloped reserves at December 31, 2022	7,144,476
Undeveloped reserves transferred to developed	(937,906	)
Revisions (a)	191,920
Extension and discoveries	178,783
Ending proved undeveloped reserves at December 31, 2023	6,577,273

(a)

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third-party transportation, gathering and compression expense.


	As of December 31,
	2023			2022
	(in thousands)

Future cash inflows	$	54,389,915		$	113,954,835
Future costs:
Production		(29,663,691	)		(31,991,109	)
Development (a)		(2,978,183	)		(3,313,724	)
Future net cash flows before income taxes		21,748,041			78,650,002
Future income tax expense		(4,176,604	)		(16,651,625	)
Total future net cash flows before 10% discount		17,571,437			61,998,377
10% annual discount		(10,732,951	)		(37,453,094	)
Standardized measure of discounted future net cash flows	$	6,838,486		$	24,545,283

(a)

2023 includes $358.7 million of undiscounted future asset retirement costs as of December 31, 2023, using current estimates of future abandonment costs.

Changes in Discounted Future Net Cash Flows

The following table summarizes changes in the standardized measure of discounted future net cash flows.


	December 31,
	2023			2022			2021
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	(23,584,574	)	$	14,326,997		$	11,600,850
Revisions in quantities		(131,078	)		109,129			577,737
Changes in future development and abandonment costs		(123,529	)		(524,847	)		(53,818	)
Net change in income taxes		3,920,556			(2,625,699	)		(2,248,161	)
Accretion of discount		2,955,359			1,486,783			298,077
Additions to proved reserves from extensions, discoveries and improved recovery		103,116			2,842,173			1,423,510
Natural gas, NGLs and oil sales, net of production costs		(1,100,908	)		(3,550,632	)		(1,934,254	)
Actual development costs incurred during the period		574,646			471,877			399,681
Changes in timing and other		(320,385	)		(475,724	)		(424,718	)
Net change for the year		(17,706,797	)		12,060,057			9,638,904
Beginning of year		24,545,283			12,485,226			2,846,322
End of year	$	6,838,486		$	24,545,283		$	12,485,226

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Allocation of Stock-Based Compensation by Functional Category

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory tax rate	21.00%	21.00%	21.00%
State, net of federal benefit	(0.10%)	1.00%	0.60%
Equity compensation and executive compensation disallowance	(0.30%)	0.20%	2.60%
Valuation allowances	0.20%	(5.50%)	(26.80%)
Permanent differences and other	0.00%	(0.40%)	0.20%
Consolidated effective tax rate	20.80%	16.30%	(2.40%)

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Extractive Industries [Abstract]
Undiscounted future asset retirement costs estimation	$ 358.7

Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2023

The following details the allocation of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2023 (in thousands):


	2023		2022		2021
Direct operating expense	$	1,723	$	1,459	$	1,310
Brokered natural gas and marketing expense		2,095		2,439		1,794
Exploration expense		1,250		1,578		1,507
General and administrative expense		35,850		42,023		39,673
Total stock-based compensation	$	40,918	$	47,499	$	44,284

Schedule of Share Based Payment Award Performance Stock Awards Valuation Assumptions

The following assumptions were used to estimate the fair value of the TSR awards granted during the years ended December 31, 2023, 2022 and 2021:


	Year Ended December 31,
	2023			2022			2021
Risk-free interest rate		3.8	%		1.4	%		0.2	%
Expected annual volatility		61	%		68	%		75	%
Grant date fair value per unit	$	30.37		$	27.90		$	12.58

Restricted Stock and Restricted Stock Units and performance awards Outstanding

The following is a summary of the activity for our restricted stock and performance awards for the year ended December 31, 2023:


	Restricted Stock Equity Awards					Restricted Stock Liability Awards					Stock-Based Performance Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value		Number of Units (a)			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2022		1,736,688		$	14.44		379,633		$	14.71		1,950,632		$	9.02
Granted		1,629,816		$	25.11		21,170		$	25.41		145,747		$	26.86
Vested		(1,863,153	)	$	17.10		(307,687	)	$	14.01		(1,158,797	)	$	4.80
Forfeited		(29,546	)	$	17.73		—		$	—		—		$	—
Outstanding at December 31, 2023		1,473,805		$	22.82		93,116		$	19.44		937,582		$	17.01


(a)	Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200% depending on achievement of either total stockholder return ranking compared to our peers at the vesting date or on the achievement of internal performance targets.

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
Net operating loss carryforward	$ 538,340	$ 581,349
Divestiture contract obligation	107,067	105,227
Deferred compensation	17,342	25,733
Equity compensation	6,767	4,813
Asset retirement obligations	25,614	24,113
Interest expense carryforward	19,861	16,118
Lease right-of-use liabilities	6,023	19,395
Unrealized mark-to-market loss	0	30,307
Other	16,396	16,922
Total deferred tax assets	542,013	631,234
Deferred tax liabilities:
Depreciation and depletion	(998,886)	(935,710)
Unrealized mark-to-market gain	(96,545)	0
Lease right-of-use assets	(5,184)	(18,440)
Other	(2,686)	(10,655)
Total deferred tax liabilities	(1,103,301)	(964,805)
Net deferred tax liability	(561,288)	(333,571)
Federal
Valuation allowances:
Valuation allowances	(23,396)	(21,320)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (172,001)	$ (171,423)

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation [Abstract]
Beginning of period	$ 109,851	$ 95,836
Liabilities incurred	2,047	2,589
Liabilities settled	(3,039)	(10,650)
Accretion expense	6,000	6,569
Change in estimate	2,570	15,507
End of period	117,429	109,851
Less current portion	(2,395)	(4,570)
Long-term asset retirement obligations	$ 115,034	$ 105,281

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(7) Asset Retirement Obligations

ARO primarily represents the present value of the estimated amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2023 and 2022 (in thousands):


	Year Ended December 31,
	2023			2022
Beginning of period	$	109,851		$	95,836
Liabilities incurred		2,047			2,589
Liabilities settled		(3,039	)		(10,650	)
Accretion expense		6,000			6,569
Change in estimate		2,570			15,507
End of period		117,429			109,851
Less current portion		(2,395	)		(4,570	)
Long-term asset retirement obligations	$	115,034		$	105,281

Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying consolidated statements of income.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2023 and 2022 (in thousands):


	Year Ended December 31,
	2023			2022
Beginning of period	$	109,851		$	95,836
Liabilities incurred		2,047			2,589
Liabilities settled		(3,039	)		(10,650	)
Accretion expense		6,000			6,569
Change in estimate		2,570			15,507
End of period		117,429			109,851
Less current portion		(2,395	)		(4,570	)
Long-term asset retirement obligations	$	115,034		$	105,281

Indebtedness - Senior Note Redemptions - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 31, 2024
Debt Instrument [Line Items]
Repurchases of senior notes on the open market	$ 60,934	$ 1,659,422	$ 63,324
Loss (gain) on early extinguishment of debt	438	$ (69,493)	$ (98)
Subsequent Event
Debt Instrument [Line Items]
Repurchases of senior notes on the open market				$ 8,700
Four Point Eight Seven Five Percent Senior Notes Due Two Thousand Twenty Five [Member]
Debt Instrument [Line Items]
Repurchases of senior notes on the open market	$ 61,600
Interest rate on notes	4.875%	4.875%
Loss (gain) on early extinguishment of debt	$ 438,000
Four Point Eight Seven Five Percent Senior Notes Due Two Thousand Twenty Five [Member] \| Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes				4.875%
Senior Debt [Member]
Debt Instrument [Line Items]
Redemption price of notes as percentage of principal amount	101.00%

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Capital Stock - Schedule of Change in Treasury Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Stockholders' Equity Note [Abstract]
Beginning balance	24,001,535	10,002,646
Rabbi trust shares distributed and/or sold	(470)	(1,111)
Shares repurchased	715,000	14,000,000
Ending balance	24,716,065	24,001,535

Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

(4) Income Taxes

Our income tax expense was $229.2 million for the year ended December 31, 2023 compared to expense of $230.5 million in 2022 and a benefit of $9.7 million in 2021. The effective income tax rate is influenced by a variety of factors including geographic sources and relative magnitude of these sources of income. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2023				2022				2021
Federal statutory tax rate		21.0		%		21.0		%		21.0		%
State, net of federal benefit		(0.1	)			1.0				0.6
Equity compensation and executive compensation disallowance		(0.3	)			0.2				2.6
Valuation allowances		0.2				(5.5	)			(26.8	)
Permanent differences and other		—				(0.4	)			0.2
Consolidated effective tax rate		20.8		%		16.3		%		(2.4	)	%

Income tax expense (benefit) attributable to income before income taxes consists of the following (in thousands):


	Year Ended December 31,
	2023			2022			2021
Current
Federal	$	—		$	—		$	—
State		1,547			14,688			7,984
	$	1,547		$	14,688		$	7,984

Deferred
Federal	$	230,563		$	245,839		$	6,297
State		(2,909	)		(30,067	)		(24,024	)
		227,654			215,772			(17,727	)
Income tax expense (benefit)	$	229,201		$	230,460		$	(9,743	)

Significant components of deferred tax assets and liabilities are as follows (in thousands):


	December 31,
	2023			2022
Deferred tax assets:
Net operating loss carryforward	$	538,340		$	581,349
Divestiture contract obligation		107,067			105,227
Deferred compensation		17,342			25,733
Equity compensation		6,767			4,813
Asset retirement obligations		25,614			24,113
Interest expense carryforward		19,861			16,118
Lease right-of-use liabilities		6,023			19,395
Unrealized mark-to-market loss		—			30,307
Other		16,396			16,922
Valuation allowances:
Federal		(23,396	)		(21,320	)
State, net of federal benefit		(172,001	)		(171,423	)
Total deferred tax assets		542,013			631,234
Deferred tax liabilities:
Depreciation and depletion		(998,886	)		(935,710	)
Unrealized mark-to-market gain		(96,545	)		—
Lease right-of-use assets		(5,184	)		(18,440	)
Other		(2,686	)		(10,655	)
Total deferred tax liabilities		(1,103,301	)		(964,805	)
Net deferred tax liability	$	(561,288	)	$	(333,571	)

At December 31, 2023, deferred tax liabilities exceeded deferred tax assets by $561.3 million. As of December 31, 2023, we have a state valuation allowance of $172.0 million related to state tax attributes in Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia. As of December 31, 2023, we have federal valuation allowances of $23.4 million primarily related to our federal basis differences. The net change in our deferred tax asset valuation allowances was an increase of $2.7 million for the year ended December 31, 2023 compared to a reduction in our valuation allowances of $78.3 million in 2022 and a reduction of $108.0 million in 2021. We continue to evaluate the realizability of our federal and state deferred tax assets.

At December 31, 2023, we had federal NOL carryforwards of $1.8 billion. This includes $157.5 million that expires in 2037 and also includes $1.7 billion of NOL carryforwards generated after 2017 that do not expire. We have state NOL carryforwards in Pennsylvania of $811.1 million that expire between 2031 and 2042 and in Louisiana, we have state NOL carryforwards of $1.6 billion that do not expire. We file a consolidated tax return in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana and Pennsylvania and file consolidated or unitary state income tax returns in Oklahoma, Texas and West Virginia. We are subject to U.S. federal income tax examinations for the years 2020 and after and we are subject to various state tax examinations for years 2019 and after. We have not extended the statute of limitation period in any income tax jurisdiction. Our policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any material accrued interest or penalties related to tax amounts as of December 31, 2023 or December 31, 2022. Throughout 2023, 2022 and 2021, our unrecognized tax benefits were not material.

On July 12, 2022, the Commonwealth of Pennsylvania enacted legislation to reduce the corporate net income tax rate from 9.99% to 8.99% in 2023 and continues to reduce that rate by 0.5% per year beginning in 2024, with the rate becoming 4.99% in 2031 and each year thereafter.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480990/946-20-50-13

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//740/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-14

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-21

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482526/740-270-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

Stock-Based Compensation Plans - Additional Information 1 (Detail)	12 Months Ended
	Dec. 31, 2023 Award shares	Dec. 31, 2022	Dec. 31, 2021
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Restricted Stock Equity Awards \| Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Restricted Stock Liability Awards \| Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
Restricted Stock Liability Awards \| Non Employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	1 year
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of awards available for grant	2
Performance Share \| Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of share value each unit represents at grant date \| shares	1
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	1
Performance Based TSR - PSUs \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Performance Based TSR - PSUs \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%
Performance Based TSR \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Performance Based TSR \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)

12 Months Ended

Dec. 31, 2023

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)

(15) Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)

Our natural gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)


	December 31,
	2023			2022			2021
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	10,435,611		$	9,855,287		$	9,338,236
Unproved properties		789,871			800,592			837,334
Total		11,225,482			10,655,879			10,175,570
Accumulated depreciation, depletion and amortization		(5,107,801	)		(4,765,475	)		(4,420,914	)
Net capitalized costs	$	6,117,681		$	5,890,404		$	5,754,656

(a)

Includes capitalized asset retirement costs and the associated accumulated amortization.

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


	December 31,
	2023		2022		2021
	(in thousands)
Acquisitions:
Acreage purchases	$	40,067	$	28,735	$	21,942
Development		568,484		460,668		381,753
Exploration:
Drilling		—		—		6,329
Expense		25,280		25,194		22,048
Stock-based compensation expense		1,250		1,578		1,507
Gas gathering facilities:
Development		3,123		1,466		3,402
Subtotal		638,204		517,641		436,981
Asset retirement obligations		4,616		18,096		18,634
Total costs incurred	$	642,820	$	535,737	$	455,615

(a)

Includes cost incurred whether capitalized or expensed.

Reserves Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2023, Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conducted an audit of our 2023 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2023, our consultant audited approximately 96% of our proved reserves. A copy of the summary reserve report prepared by our independent petroleum consultant is included as an exhibit to this Annual Report on Form 10-K. The technical professional at our independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished during the reserves audit process. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultant to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any significant changes to our proved reserves. We provide historical information to our consultant for our largest producing properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve differences. The reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared

lease-by-lease, field-by-field or area-by-area, some of our estimates may be greater and some may be less than the estimates of our reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been approximately 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than forty years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Estimated Quantities of Proved Oil and Gas Reserves

Reserves of natural gas, NGLs, crude oil and condensate are estimated by our petroleum engineering staff and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, production taxes and other economic factors.

The SEC defines proved reserves as those volumes of natural gas, NGLs, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

The average realized prices used at December 31, 2023 to estimate reserve information were $68.32 per barrel of oil, $24.91 per barrel of NGLs and $2.20 per mcf for gas using a benchmark (NYMEX) of $78.10 per barrel and $2.62 per Mmbtu. The average realized prices used at December 31, 2022 to estimate reserve information were $87.14 per barrel of oil, $38.35 per barrel of NGLs and $6.08 per mcf for gas using a benchmark (NYMEX) of $94.13 per barrel and $6.36 per Mmbtu. The average realized prices used at December 31, 2021 to estimate reserve information were $59.35 per barrel of oil, $28.41 per barrel of NGLs and $3.30 per mcf for gas using a benchmark (NYMEX) of $66.34 per barrel and $3.60 per Mmbtu.


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) (a)
Proved developed and undeveloped reserves:
Balance, December 31, 2020		11,148,560			951,466			57,626			17,203,114
Revisions		(311,410	)		16,845			(7,089	)		(252,876	)
Extensions, discoveries and additions		1,155,952			69,367			5,103			1,602,769
Production		(541,021	)		(36,373	)		(3,044	)		(777,523	)
Balance, December 31, 2021		11,452,081			1,001,305			52,596			17,775,484
Revisions		(393,165	)		(20,251	)		(12,885	)		(591,983	)
Extensions, discoveries and additions		1,278,499			59,296			5,661			1,668,244
Production		(539,443	)		(36,392	)		(2,716	)		(774,089	)
Balance, December 31, 2022		11,797,972			1,003,958			42,656			18,077,656
Revisions		326,783			44,515			2,485			608,784
Extensions, discoveries and additions		24,078			30,234			296			207,260
Production		(538,085	)		(37,940	)		(2,475	)		(780,575	)
Balance, December 31, 2023		11,610,748			1,040,767			42,962			18,113,125
Proved developed reserves:
December 31, 2021		6,809,849			577,506			23,833			10,417,887
December 31, 2022		7,230,313			594,931			22,213			10,933,180
December 31, 2023		7,631,202			629,379			21,396			11,535,852
Proved undeveloped reserves:
December 31, 2021		4,642,232			423,798			28,762			7,357,597
December 31, 2022		4,567,659			409,027			20,443			7,144,476
December 31, 2023		3,979,546			411,388			21,566			6,577,273

(a)

During 2023, revisions of previous estimates of a positive 608.8 Bcfe include a positive revision of 280.2 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 701.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions and 370.6 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added approximately 207.3 Bcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale.

During 2022, we added approximately 1.7 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 77% of the 2022 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 592.0 Bcfe include a positive revision of 716.2 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, positive performance revisions of 72.8 Bcfe and positive pricing revisions more than offset by 1.4 Tcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. These wells were removed due to the out-performance of existing wells which resulted in a higher utilization of in-field gathering capacity and a reallocation of capital due to the drilling of longer laterals on existing locations.

During 2021, we added approximately 1.6 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 72% of the 2021 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 252.9 Bcfe include positive performance revisions of 1.0 Tcfe and positive pricing revisions of 22.6 Bcfe more than offset by 1.3 Tcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon.

The following details the changes in proved undeveloped reserves for 2023 (Mmcfe):


Beginning proved undeveloped reserves at December 31, 2022	7,144,476
Undeveloped reserves transferred to developed	(937,906	)
Revisions (a)	191,920
Extension and discoveries	178,783
Ending proved undeveloped reserves at December 31, 2023	6,577,273

(a)

During 2023, we spent approximately $495.1 million on development costs related to proved undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $2.6 billion. As of December 31, 2023, we have 90.2 Bcfe that have been reported for more than five years from their original date of booking, all of which are in the process of being completed and are expected to turn to sales in 2024. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs, crude oil and condensate reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs, crude oil and condensate, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

For the years ended 2023, 2022 and 2021, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.

The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.


	As of December 31,
	2023			2022
	(in thousands)

Future cash inflows	$	54,389,915		$	113,954,835
Future costs:
Production		(29,663,691	)		(31,991,109	)
Development (a)		(2,978,183	)		(3,313,724	)
Future net cash flows before income taxes		21,748,041			78,650,002
Future income tax expense		(4,176,604	)		(16,651,625	)
Total future net cash flows before 10% discount		17,571,437			61,998,377
10% annual discount		(10,732,951	)		(37,453,094	)
Standardized measure of discounted future net cash flows	$	6,838,486		$	24,545,283

(a)

2023 includes $358.7 million of undiscounted future asset retirement costs as of December 31, 2023, using current estimates of future abandonment costs.

The following table summarizes changes in the standardized measure of discounted future net cash flows.


	December 31,
	2023			2022			2021
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	(23,584,574	)	$	14,326,997		$	11,600,850
Revisions in quantities		(131,078	)		109,129			577,737
Changes in future development and abandonment costs		(123,529	)		(524,847	)		(53,818	)
Net change in income taxes		3,920,556			(2,625,699	)		(2,248,161	)
Accretion of discount		2,955,359			1,486,783			298,077
Additions to proved reserves from extensions, discoveries and improved recovery		103,116			2,842,173			1,423,510
Natural gas, NGLs and oil sales, net of production costs		(1,100,908	)		(3,550,632	)		(1,934,254	)
Actual development costs incurred during the period		574,646			471,877			399,681
Changes in timing and other		(320,385	)		(475,724	)		(424,718	)
Net change for the year		(17,706,797	)		12,060,057			9,638,904
Beginning of year		24,545,283			12,485,226			2,846,322
End of year	$	6,838,486		$	24,545,283		$	12,485,226

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
2024	$ 0
2025	688,388
2026	0
2027	0
2028	0
Thereafter	1,100,000
Total debt	$ 1,788,388	$ 1,869,000

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revisions of previous estimates:
Changes in prices and production costs	$ (23,584,574)	$ 14,326,997	$ 11,600,850
Revisions in quantities	(131,078)	109,129	577,737
Changes in future development and abandonment costs	(123,529)	(524,847)	(53,818)
Net change in income taxes	3,920,556	(2,625,699)	(2,248,161)
Accretion of discount	2,955,359	1,486,783	298,077
Additions to proved reserves from extensions, discoveries and improved recovery	103,116	2,842,173	1,423,510
Natural gas, NGLs and oil sales, net of production costs	(1,100,908)	(3,550,632)	(1,934,254)
Actual development costs incurred during the period	574,646	471,877	399,681
Changes in timing and other	(320,385)	(475,724)	(424,718)
Net change for the year	(17,706,797)	12,060,057	9,638,904
Beginning of year	24,545,283	12,485,226	2,846,322
End of year	$ 6,838,486	$ 24,545,283	$ 12,485,226

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Components of Lease Expense


	Year Ended December 31,
	2023		2022
Operating lease cost	$	70,781	$	37,873
Variable lease expense (1)		25,529		22,082
Short-term lease expense (2)		708		1,807
Sublease income		—		(137	)
Total lease expense	$	97,018	$	61,625

Short-term lease costs (3)	$	14,032	$	17,285


(1)	Variable lease payments that are not dependent on an index or rate and are not included in the lease liability or ROU assets.
(2)	Short-term lease expense represents expense related to leases with a contract term of one year or less and are not included in our ROU assets or lease liability in our consolidated balance sheets.


(3)	These short-term lease costs are related to leases with a contract term of one year or less, the majority of which are related to drilling rigs which are capitalized as part of natural gas and oil properties on our consolidated balance sheets and may fluctuate based on the number of drilling rigs being utilized.

Supplemental Cash Flow Information Related to Operating Leases

Supplemental cash flow information related to our operating leases is included in the table below (in thousands):


	Year Ended December 31,
	2023		2022
Cash paid for amounts included in the measurement of lease liabilities	$	71,669	$	37,457
ROU assets added in exchange for lease obligations	$	7,421	$	78,574

Supplemental Balance Sheet Information Related to Operating Leases

Supplemental balance sheet information related to our operating leases is included in the table below (in thousands):


	Year Ended December 31,
	2023			2022
Operating lease ROU assets	$	23,821		$	84,070
Accrued liabilities – current	$	(11,584	)	$	(67,493	)
Operating lease liabilities – long-term	$	(16,064	)	$	(20,903	)

Schedule of Weighted Average Remaining Lease Term and Weighted Average Discount Rate for Operating Leases

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:


	Year Ended December 31,
	2023	2022
Weighted average remaining lease term	2.9 years	2.0 years
Weighted average discount rate	7%	6%

Schedule of Lease Liabilities with Enforceable Contract Terms are Greater Than One year Mature

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):


	Operating Leases
2024	$	13,119
2025		7,921
2026		6,866
2027		2,698
2028		29
Total lease payments		30,633
Less effects of discounting		(2,985	)
Total lease liability	$	27,648

Schedule of Future Minimum Transportation Fees Due

As of December 31, 2023, future minimum transportation and gathering fees under our commitments are as follows (in thousands):


	Transportation and Gathering Contracts (a)
2024	$	801,694
2025		730,907
2026		670,692
2027		616,260
2028		565,707


Thereafter		2,504,906
	$	5,890,166


(a)	The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

Schedule of Estimated Settlement of Divestiture Contract Obligation Based On Discounted Value

As of December 31, 2023, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands):


	Divestiture Contract Obligation
2024	$	86,762
2025		77,418
2026		61,805
2027		52,622
2028		48,116
Thereafter		70,727
	$	397,450

Future Delivery Commitments

As of December 31, 2023, our delivery commitments through 2037 were as follows:


Year Ending December 31,	Natural Gas (mmbtu per day)	Ethane and Propane (bbls per day)
2024	302,404	70,000
2025	282,493	54,932
2026	200,548	50,000
2027	100,000	46,233
2028	100,000	45,000
2029	100,000	33,444
2030	—	30,000
2031	—	16,575
2032-2037	—	10,000 (each year)

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (Detail) - USD ($)
$ in Thousands

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Natural gas and oil properties:

Properties subject to depletion

^[1]

$ 10,435,611

$ 9,855,287

$ 9,338,236

Unproved properties

^[1]

789,871

800,592

837,334

Total

^[1]

11,225,482

10,655,879

10,175,570

Accumulated depreciation, depletion and amortization

^[1]

(5,107,801)

(4,765,475)

(4,420,914)

Natural gas and oil properties, successful efforts method, net

^[1]

$ 6,117,681

$ 5,890,404

$ 5,754,656

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Income Taxes - Additional Information (Detail) - USD ($)		12 Months Ended
	Jul. 12, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Line Items]
Income tax expense (benefit)		$ 229,201,000	$ 230,460,000	$ (9,743,000)
Deferred tax liabilities		561,288,000	333,571,000
Accrued interest or penalties related to tax amounts		$ 0
Period during which net operating loss carryforwards and alternative minimum tax expire		Dec. 31, 2037
Change in Valuation Allowances		$ 2,700,000	(78,300,000)	$ (108,000,000)
State
Income Taxes [Line Items]
Valuation allowances		172,001,000	171,423,000
Federal
Income Taxes [Line Items]
Valuation allowances		23,396,000	$ 21,320,000
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards		1,800,000,000
Net operating loss carryforward subject to expiration		157,500,000
Net operating loss carryforward not subject to expiration		1,700,000,000
Pennsylvania
Income Taxes [Line Items]
Net operating loss carryforwards		$ 811,100,000
Reduction in tax rate		0.50%
Final tax rate		4.99%
Pennsylvania \| Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire		Dec. 31, 2031
Pennsylvania \| Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire		Dec. 31, 2042
Corporate income tax rate, prior	9.99%
Corporate income tax rate, current	8.99%
Louisiana
Income Taxes [Line Items]
Net operating loss carryforward not subject to expiration		$ 1,600,000,000

Exit Costs (Tables)

12 Months Ended

Dec. 31, 2023

Restructuring and Related Activities [Abstract]

Summary of Exit and Termination Costs

The following summarizes our exit costs for the three years ended December 31, 2023, 2022 and 2021 (in thousands):


	Year Ended December 31,
	2023		2022		2021
Severance costs	$	—	$	—	$	567
Transportation contract capacity releases (including accretion of discount)		345		579		754
Divestiture contract obligation (including accretion of discount)		99,595		69,758		20,340
Total exit costs	$	99,940	$	70,337	$	21,661

Exit and Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet

The following details the accrued exit cost liability activity for the years ended December 31, 2023 and 2022 (in thousands):


	Exit Costs			Termination Costs
Balance at December 31, 2021	$	423,742		$	10
Accrued contract obligations-changes in estimate		26,183			—
Accretion of discount		44,154			—
Payments		(98,399	)		(10	)
Balance at December 31, 2022		395,680		$	—
Accrued contract obligations-changes in estimate		57,735			—
Accretion of discount		42,205			—
Payments		(95,631	)		—
Balance at December 31, 2023	$	399,989		$	—

Stock-Based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Share - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	3.80%	1.40%	0.20%
Expected annual volatility	61.00%	68.00%	75.00%
Grant date fair value per unit	$ 30.37	$ 27.9	$ 12.58

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Commitments And Contingencies Disclosure [Line Items]

Commitments and Contingencies - Schedule of Components of Lease Expense (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Operating lease cost

$ 70,781

$ 37,873

Variable lease expense

^[1]

25,529

22,082

Sublease income

(137)

Total lease expense

97,018

61,625

Natural Gas and Oil Properties

Commitments And Contingencies Disclosure [Line Items]

Short-term lease expense / costs

^[2]

14,032

17,285

Leases with Contract Term of One Year or Less

Commitments And Contingencies Disclosure [Line Items]

Short-term lease expense / costs

^[3]

$ 708

$ 1,807

[1]	Variable lease payments that are not dependent on an index or rate and are not included in the lease liability or ROU assets.
[2]	These short-term lease costs are related to leases with a contract term of one year or less, the majority of which are related to drilling rigs which are capitalized as part of natural gas and oil properties on our consolidated balance sheets and may fluctuate based on the number of drilling rigs being utilized.
[3]	Short-term lease expense represents expense related to leases with a contract term of one year or less and are not included in our ROU assets or lease liability in our consolidated balance sheets.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(2)

Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements, including the notes, have been prepared in accordance with generally accepted accounting principles ("U.S. GAAP") and include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods.

Estimated quantities of natural gas, NGLs, crude oil and condensate reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, NGLs, crude oil and condensate. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs, crude oil and condensate reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of natural gas, NGLs and crude oil and condensate that are ultimately recovered. See Note 15 for further detail.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, valuation of certain derivative instruments, exit cost liabilities and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Business Segment Information

We have evaluated how we are organized and managed and have identified only one operating segment. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate producing activities. We 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 measure financial performance as a single enterprise and not on an area-by-area basis. All of our operating revenues, income from operations and assets are generated and located in the United States.

Revenue Recognition and Accounts Receivable

Natural gas, NGLs and oil sales revenues are recognized when control of the product is transferred to the customer and collectability is reasonably assured. See below for a more detailed summary of our product types.

Natural Gas and NGLs Sales. Under some of our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer and we recognize revenue on a gross basis, with gathering, compression, processing and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity.

In other natural gas processing agreements, we may elect to take our residue gas and/or NGLs in kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any

transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense.

Oil Sales. Our oil sales contracts are generally structured in one of the following ways:

•

We sell oil production at the wellhead and collect an agreed-upon index price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

•

We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation, gathering, processing and compression expense.

Brokered Natural Gas, Marketing and Other. We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties, and subsequently selling that natural gas or NGLs under our existing contracts to fill our contract commitments or use existing infrastructure contracts to economically utilize available capacity. In these arrangements, we take control of the natural gas purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Proceeds generated from the sale of excess firm transportation to third parties is also included here when we are determined to no longer be the primary obligor of such arrangement. Our net brokered margin was income of $4.2 million in 2023 compared to a loss of $5.4 million in 2022 and income of $1.1 million in 2021. Interest income included here was $5.9 million in 2023 compared to $2.5 million in 2022 and $243,000 in 2021.

The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. We may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales or in limited cases may use them for contracts we intend to physically settle but that do not meet all of the criteria to be treated as normal sales.

Accounts Receivable. Our accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties we operate. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. However, this concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. Each reporting period, we assess the recoverability of material receivables using historical data and current market conditions. The loss given default method is used when, based on management’s judgment, an allowance for expected credit losses is accrued on material receivables to reflect the net amount to be collected. In certain instances, we require purchasers to post stand-by letters of credit. For receivables from joint interest owners, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We regularly review collectability and establish or adjust our allowance as necessary. We have allowances for doubtful accounts relating to exploration and production receivables of $308,000 at December 31, 2023 compared to $314,000 at December 31, 2022. We recorded no bad debt expense in the year ended December 31, 2023 compared to a reduction of $250,000 in the year ended December 31, 2022 and expense of $200,000 in the year ended December 31, 2021.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows.

Natural Gas and Oil Properties

Property Acquisition Costs. We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to acquire mineral interests in natural gas and oil properties, to drill exploratory wells that find proved reserves and to drill development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of proved properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have 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.

Impairments. Our proved natural gas and oil properties are reviewed for impairment of value whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying value of the asset, an impairment loss is recognized based on the fair value of the asset. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. Natural gas and oil properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management which could impact the number of locations we intend to drill. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Information such as reservoir performance or future plans to develop acreage is also considered. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $789.9 million as of December 31, 2023 compared to $800.6 million in 2022. We have recorded abandonment and impairment expense related to unproved properties of $46.4 million in the year ended December 31, 2023 compared to $28.6 million in 2022 and $7.2 million in 2021.

Dispositions. Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets.

Other Property and Equipment

Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $1.5 million in the year ended December 31, 2023 compared to $2.2 million in the year ended December 31, 2022 and $2.4 million in the year ended December 31, 2021.

Leases

We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling or completion equipment, office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. Certain of our lease agreements include lease and non-lease components. We account for these components as a single lease. Lease costs associated with drilling and completion equipment are capitalized as part of well costs.

Lease right-of-use ("ROU") assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of our lease contracts do not provide an implicit discount rate, we use our incremental borrowing rate which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at our discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with a term of 12 months or less are not recorded as a right-of-use asset and liability. The majority of our leases are classified as either short-term or long-term operating leases.

Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined and disclosed based on gross contractual obligations. Our lease costs are also presented on a gross contractual basis.

Other Assets

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets.

Other assets at December 31, 2023 include $72.0 million of marketable securities held in our deferred compensation plan, $7.3 million of deferred financing costs related to our bank credit facility and $9.7 million of investments and other. Other assets at December 31, 2022 included $57.7 million of marketable securities held in our deferred compensation plan and $10.4 million of investments and other.

Stock-based Compensation Arrangements

We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 10.

Derivative Financial Instruments

All of our commodity derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are important. Among these benefits are more consistent returns on invested capital and better access to bank and other capital markets, more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs. All unsettled commodity derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements, which in an event of default, allows us to offset payables to and receivables from the defaulting counterparty. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

All realized and unrealized gains and losses on derivative instruments are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of income. Certain of our commodity derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We have collars which establish a minimum floor price and a predetermined ceiling price. Our program may also include a three-way collar which is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price while the purchased put establishes the floor price until the market price for the commodity falls below the sold put stock price at which time the value of the purchased put is effectively capped. 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). We have entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location ("basis"), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. For additional information regarding our derivative instruments, see Note 8.

From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. We did not materially modify any existing derivative contracts in 2023, 2022 or 2021.

Concentrations of Credit Risk

As of December 31, 2023, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. The nature of our customers’ businesses may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.

To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. We may also limit the level of exposure with any single counterparty. We do not anticipate a material impact on our financial results due to non-performance by third parties.

For the year ended December 31, 2023, we had one customer that accounted for 10% or more of natural gas, NGLs and oil sales compared to no such customers for the year ended December 31, 2022 and one customer for the year ended December 31, 2021. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production.

We have executed International Swap Dealers Association Master Agreements ("ISDA Agreements") with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have a margin requirement or collateral provision that would require us to fund or post additional collateral prior to the scheduled cash settlement date.

At December 31, 2023, our derivative counterparties included fourteen financial institutions and commodity traders, of which all but six are secured lenders in our bank credit facility. At December 31, 2023, our net derivative asset includes a payable to one counterparty not included in our bank credit facility totaling $329,000 and a receivable from the remaining five counterparties of $26.4 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Historically, we have not experienced any issues of non-performance by derivative counterparties. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance.

Asset Retirement Obligations

The fair value of asset retirement obligations ("ARO") is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing properties and include costs to dismantle and relocate or dispose of production platforms, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future, federal and state regulatory requirements, inflation rates and credit-adjusted-risk-free interest rates. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 7 for additional information.

Exit Costs

We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on future discounted cash outflows required to satisfy the obligation. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change utilizing the initial discount rate. These costs, including associated accretion expense, are included in exit costs in the accompanying consolidated statements of income. See Note 14 for additional information.

Contingencies

We are subject to legal proceedings, claims, and liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 13 for a more detailed discussion regarding our contingencies.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.

Deferred Taxes

Deferred tax assets and liabilities, measured by the enacted tax rates, are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include whether we are in a cumulative loss position in recent years, our reversal of temporary differences and our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term in the accompanying consolidated balance sheets.

Treasury Stock

Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

Adoption of New Accounting Standards

There have not been any new standards issued we consider material to our accounting or disclosures. There are no issued but pending standards expected to have a material impact on our consolidated financial statements.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Proved Developed and Undeveloped Reserves (Detail)

12 Months Ended

Dec. 31, 2023

MMcfe

MMcf

MMBbls

Dec. 31, 2022

MMcfe

MMcf

MMBbls

Dec. 31, 2021

MMcfe

MMcf

MMBbls

Proved undeveloped reserves | MMcfe

6,577,273

7,144,476

Natural Gas

Extensions, discoveries and additions | MMcf

Beginning Balance | MMcf

11,797,972

11,452,081

11,148,560

Revisions | MMcf

326,783

(393,165)

(311,410)

24,078

1,278,499

1,155,952

Production | MMcf

(538,085)

(539,443)

(541,021)

Ending Balance | MMcf

11,610,748

11,797,972

11,452,081

Proved developed reserves | MMcf

7,631,202

7,230,313

6,809,849

Proved undeveloped reserves | MMcf

3,979,546

4,567,659

4,642,232

NGLs

Extensions, discoveries and additions

Beginning Balance

1,003,958

1,001,305

951,466

Revisions

44,515

(20,251)

16,845

30,234

59,296

69,367

Production

(37,940)

(36,392)

(36,373)

Ending Balance

1,040,767

1,003,958

1,001,305

Proved developed reserves

629,379

594,931

577,506

Proved undeveloped reserves

411,388

409,027

423,798

Crude Oil and Condensate

Extensions, discoveries and additions

Beginning Balance

42,656

52,596

57,626

Revisions

2,485

(12,885)

(7,089)

296

5,661

5,103

Production

(2,475)

(2,716)

(3,044)

Ending Balance

42,962

42,656

52,596

Proved developed reserves

21,396

22,213

23,833

Proved undeveloped reserves

21,566

20,443

28,762

Natural Gas Equivalents

Proved developed reserves | MMcfe

^[1]

11,535,852

10,933,180

10,417,887

Proved undeveloped reserves | MMcfe

^[1]

6,577,273

7,144,476

7,357,597

Beginning Balance | MMcfe

^[1]

18,077,656

17,775,484

17,203,114

Revisions | MMcfe

^[1]

608,784

(591,983)

(252,876)

Extensions, discoveries and additions | MMcfe

^[1]

207,260

1,668,244

1,602,769

Production | MMcfe

^[1]

(780,575)

(774,089)

(777,523)

Ending Balance | MMcfe

^[1]

18,113,125

18,077,656

17,775,484

[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.

Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail)
$ in Thousands

Dec. 31, 2023

USD ($)

^[1]

Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]

$ 801,694

730,907

670,692

616,260

565,707

2,504,906

Transportation and Gathering Contracts

$ 5,890,166

[1]	The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Stock-Based Compensation Plans

(10) Stock-Based Compensation Plans

Description of the Plans

We have two active equity-based stock plans, our Amended and Restated 2005 Equity-Based Compensation Plan, which we refer to as the 2005 Plan and the Amended and Restated 2019 Equity-Based Compensation Plan, which we refer to as the 2019 Plan. Under these plans, the Compensation Committee of the board of directors may grant, various awards to non-employee directors and employees. Shares issued as a result of awards granted are generally new common shares but can be funded out of treasury shares, if available.

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 financial categories. The following details the allocation of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2023 (in thousands):


	2023		2022		2021
Direct operating expense	$	1,723	$	1,459	$	1,310
Brokered natural gas and marketing expense		2,095		2,439		1,794
Exploration expense		1,250		1,578		1,507
General and administrative expense		35,850		42,023		39,673
Total stock-based compensation	$	40,918	$	47,499	$	44,284

In 2023, we recorded an additional tax benefit of an estimated $10.6 million for the tax effect of financial accounting expense compared to the corporate income tax deduction for equity compensation that vested during the year compared to additional tax benefit of $7.2 million in 2022 and additional tax benefit of $340,000 in 2021.

Stock-Based Awards

Restricted Stock Awards. We grant restricted stock units and restricted stock under our equity-based stock compensation plans to our employees, which we refer to as restricted stock Equity Awards. The restricted stock units generally vest over a three-year period and are contingent on the recipient’s continued employment. Beginning in 2023, we began granting restricted stock (that was previously placed in our deferred compensation plan) that vests at the end of a three-year period for employee grants and at the end of a one-year period for non-employee directors. Vesting is also based upon the employee's continued employment with us. Prior to vesting, recipients of restricted stock typically earn dividends payable in cash upon vesting but they have no voting rights prior to vesting.

The Compensation Committee has granted restricted stock to certain employees and non-employee directors of the board of directors as part of their compensation. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, these shares were placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. Compensation expense is recognized over the balance of the vesting period, which is typically at the end of three years for employee grants and at the end of a one-year period for non-employee directors. All Liability Awards were 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, Liability Awards recipients have the right to vote such stock and receive dividends thereon. 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 income.

Stock-Based Performance Awards - (PSUs). We grant two types of performance share awards: one based on performance conditions measured against internal performance metrics and one based on market conditions measured based on Range’s performance relative to a predetermined peer group ("TSR Awards").

Each unit granted represents one share of our common stock. These units are settled in stock and the amount of the payout is based on the vesting percentage, which can range from zero to 200%, and (1) the internal performance metrics achieved, which is determined by the Compensation Committee and (2) for our TSR Awards, the value of our common stock on the vesting date compared to our peers. Dividend equivalents accrue during the performance period and are paid in stock at the end of the performance period. The performance period is three years.

Restricted Stock – Equity Awards

In 2023, we granted 1.6 million restricted stock Equity Awards to employees which generally vest over a three-year period compared to 1.4 million in 2022 and 2.3 million in 2021. We recorded compensation expense for these outstanding awards of $31.6 million in the year ended December 31, 2023 compared to $21.0 million in 2022 and $19.6 million in 2021. The vesting date fair value of restricted stock Equity Awards which vested during 2023, 2022 and 2021 was $31.9 million, $20.3 million and $17.6 million. The weighted average grant date fair value of these Equity Awards was $22.82, $14.44 and $7.39 for awards unvested at December 31, 2023, 2022 and 2021. As of December 31, 2023, there was $31.2 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.7 years. These awards are not issued until such time as they are vested and the grantees do not have the option to receive cash.

Restricted Stock – Liability Awards

In 2023, we granted 13,000 shares of restricted stock Liability Awards as compensation to employees at a grant date fair value of $25.61 which generally vest at the end of a three-year period and 8,000 shares were granted to non-employee directors, at an average grant date fair value of $25.07 with vesting at the end of one year. In 2022, we granted 603,000 shares of restricted stock liability awards as compensation to employees at an average grant date value of $20.44 with vesting generally at the end of a three-year period and 47,000 shares were granted to non-employee directors at an average grant date fair value of $27.52 with vesting at the end of one year. In 2021, we granted 1.2 million shares of restricted stock liability awards of compensation to employees at an average grant date value of $9.31 with vesting generally at the end of a three year period and 102,000 shares were granted to non-employee directors at an average grant date fair value $12.49 with vesting at the end of one year. In 2023, the number of shares granted into our deferred compensation plan was reduced in favor of restricted stock Equity Awards. We recorded compensation expense for these restricted stock Liability Awards of $4.0 million in the year ended December 31, 2023 compared to $13.6 million in 2022 and $11.4 million in 2021. The vesting date fair value of these Liability Awards vested during 2023, 2022 and 2021 was $4.3 million, $13.2 million and $12.1 million. The weighted average grant date fair value of these Liability Awards was $19.44, $14.71 and $6.49 for awards unvested at December 31, 2023, 2022 and 2021. As of December 31, 2023, there was $1.0 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of less than one year. 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 income (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $75.2 million in 2023 compared to $22.2 million in 2022 and $5.9 million in 2021.

Stock-Based Performance Awards

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.

Internal performance metric awards granted in 2023 and 2022 are earned based on:

•

Net debt (total debt less cash on hand balance); and

•

GHG emissions intensity.

Internal performance metric awards granted in 2021 are earned based on:

•

Debt/EBITDAX (earnings before interest, taxes, depreciation and amortization and exploration expense); and

•

GHG emissions intensity.

In 2023, we granted 81,000 units as compensation to employees at a grant date fair value of $24.08 which vest at the end of a three-year period compared to 153,000 units at a grant date fair value of $20.38 in 2022 and 303,000 units at a grant date fair value of $9.81 in 2021. We recorded compensation expense for these awards of $2.2 million in the year ended December 31, 2023 compared to $6.2 million in the year ended December 31, 2022 and $6.6 million in the year ended December 31, 2021. As of December 31, 2023, there was $1.7 million of unrecognized compensation related to these internal performance metric awards to be recognized over a weighted average period of 1.9 years.

TSR awards. These awards 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 awards 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 the TSR awards granted during the years ended December 31, 2023, 2022 and 2021:


	Year Ended December 31,
	2023			2022			2021
Risk-free interest rate		3.8	%		1.4	%		0.2	%
Expected annual volatility		61	%		68	%		75	%
Grant date fair value per unit	$	30.37		$	27.90		$	12.58

In 2023, we granted 64,000 units as compensation to employees which vest at the end of a three-year period compared to 112,000 in 2022 and 224,000 in 2021. We recorded TSR award compensation expense of $1.7 million in the year ended December 31, 2023 compared to $3.2 million in the year ended December 31, 2022 and $2.6 million in the year ended December 31, 2021. As of December 31, 2023, there was $1.7 million of unrecognized compensation related to these TSR awards to be recognized over a weighted average period of 1.9 years.

The following is a summary of the activity for our restricted stock and performance awards for the year ended December 31, 2023:


	Restricted Stock Equity Awards					Restricted Stock Liability Awards					Stock-Based Performance Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value		Number of Units (a)			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2022		1,736,688		$	14.44		379,633		$	14.71		1,950,632		$	9.02
Granted		1,629,816		$	25.11		21,170		$	25.41		145,747		$	26.86
Vested		(1,863,153	)	$	17.10		(307,687	)	$	14.01		(1,158,797	)	$	4.80
Forfeited		(29,546	)	$	17.73		—		$	—		—		$	—
Outstanding at December 31, 2023		1,473,805		$	22.82		93,116		$	19.44		937,582		$	17.01


(a)	Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200% depending on achievement of either total stockholder return ranking compared to our peers at the vesting date or on the achievement of internal performance targets.

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. We match up to 6% of salary in cash and vesting of those contributions is immediate. In 2023, we contributed $5.2 million to the 401(k) Plan compared to $4.8 million in 2022 and $4.6 million in 2021. Employees have a variety of investment options in the 401(k) benefit plan.

Deferred Compensation Plan

Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests at the end of three years. The assets of the plans are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our 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 in the 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 income. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in 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 mark-to-market loss of $26.6 million in 2023 compared to a loss of $61.9 million in 2022 and a loss of $68.4 million in 2021. The Rabbi Trust held 1.6 million shares (1.5 million of vested shares) of Range stock at December 31, 2023 compared to 5.6 million (5.3 million of vested shares) at December 31, 2022.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)
$ in Thousands

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Future net cash flows before income taxes

Future cash inflows

$ 54,389,915

$ 113,954,835

Future costs:

Production

(29,663,691)

(31,991,109)

Development

^[1]

(2,978,183)

(3,313,724)

21,748,041

78,650,002

Future income tax expense

(4,176,604)

(16,651,625)

Total future net cash flows before 10% discount

17,571,437

61,998,377

10% annual discount

(10,732,951)

(37,453,094)

Standardized measure of discounted future net cash flows

$ 6,838,486

$ 24,545,283

$ 12,485,226

$ 2,846,322

[1]	2023 includes $358.7 million of undiscounted future asset retirement costs as of December 31, 2023, using current estimates of future abandonment costs.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

(12) Supplemental Cash Flow Information


	Year Ended December 31,
	2023			2022			2021
				(in thousands)

Net cash provided from operating activities included:
Income taxes paid to taxing authorities	$	(2,200	)	$	(20,335	)	$	(7,061	)
Interest paid		(120,631	)		(193,732	)		(196,750	)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	4,616		$	18,096		$	18,634
Increase (decrease) in accrued capital expenditures		4,403			1,966			(4,505	)

Exit Costs - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2023	Jun. 30, 2023	Jun. 30, 2020	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
North Louisiana
Restructuring Cost And Reserve [Line Items]
Accretion expense				$ 41,900	$ 43,600	$ 47,900
Exit and termination costs	$ 18,000	$ 37,800			26,200
Exit cost							$ 479,800
Restructuring Reserve, Total	397,400			397,400
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost				345	$ 579	$ 754
Pennsylvania \| Capacity Releases on Transportation Pipelines
Restructuring Cost And Reserve [Line Items]
Exit cost			$ 10,400
Restructuring Reserve, Total	$ 2,500			$ 2,500

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Stock-Based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 40,918	$ 47,499	$ 44,284
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,723	1,459	1,310
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	2,095	2,439	1,794
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,250	1,578	1,507
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 35,850	$ 42,023	$ 39,673

Stock-Based Compensation Plans - Additional Information 4 (Detail) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Retirement Benefits [Abstract]
Maximum percentage of employees contribution	75.00%
Maximum percentage of employers contribution in cash	6.00%
Employer contribution	$ 5.2	$ 4.8	$ 4.6
Deferred compensation plan vesting period	3 years
Deferred compensation plan	$ (26.6)	$ (61.9)	$ (68.4)
Shares held in rabbi trust total	1.6	5.6
Vested shares held in rabbi trust	1.5	5.3

Revenues from Contracts with Customers - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Stream	Dec. 31, 2022 USD ($)
Disaggregation of Revenue [Line Items]
Number of revenue streams \| Stream	3
Maximum [Member]
Disaggregation of Revenue [Line Items]
Settlement statements, number of days	90 days
Minimum [Member]
Disaggregation of Revenue [Line Items]
Settlement statements, number of days	30 days
Revenue Contract with Customer
Disaggregation of Revenue [Line Items]
Accounts receivable \| $	$ 263.9	$ 463.3

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Indebtedness - Additional Information (Detail)	36 Months Ended
Indebtedness - Additional Information (Detail)	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):


		Fair Value Measurements at December 31, 2023 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, 2023
Trading securities held in the deferred compensation plans		$	71,989	$	—	$	—		$	71,989
Derivatives	–swaps		—		247,580		—			247,580
	–collars		—		152,540		—			152,540
	–three-way collars		—		25,406		—			25,406
	–basis swaps		—		18,277		—			18,277
	–swaptions		—		—		(1,161	)		(1,161	)


		Fair Value Measurements at December 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 December 31, 2022
Trading securities held in the deferred compensation plans		$	57,717	$	—		$	—	$	57,717
Derivatives	–swaps		—		(109,844	)		—		(109,844	)
	–collars		—		(16,837	)		—		(16,837	)
	–three-way collars		—		(11,917	)		—		(11,917	)
	–basis swaps		—		521			—		521
Divestiture contingent consideration			—		13,080			—		13,080

Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy

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):


	Year Ended December 31, 2023
Balance at December 31, 2022	$	—
Additions		(1,161	)
Settlements		—
Transfers out of Level 3		—
Balance at December 31, 2023	$	(1,161	)

Carrying Amounts and Fair Values of Financial Instruments

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2023 and 2022 (in thousands):


	December 31, 2023						December 31, 2022
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and basis swaps	$	442,971		$	442,971		$	28,835		$	28,835
Divestiture contingent consideration		—			—			13,080			13,080
Marketable securities (a)		71,989			71,989			57,717			57,717
(Liabilities):
Commodity swaps, collars and basis swaps		(329	)		(329	)		(166,912	)		(166,912	)
Bank credit facility (b)		—			—			(19,000	)		(19,000	)
4.875% senior notes due 2025 (b)		(688,388	)		(679,363	)		(750,000	)		(714,870	)
8.25% senior notes due 2029 (b)		(600,000	)		(624,816	)		(600,000	)		(618,312	)
4.75% senior notes due 2030 (b)		(500,000	)		(463,085	)		(500,000	)		(442,350	)
Deferred compensation plan (c)		(117,125	)		(117,125	)		(189,241	)		(189,241	)


(a)	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are updated based on end of period closing prices which is a Level 1 input.
(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 at the closing price on the balance sheet date which is a Level 1 input.

Derivative Activities - Additional Information (Detail) $ in Thousands	Dec. 31, 2023 USD ($) MMBTU	Dec. 31, 2022 USD ($)
Contingent Consideration \| Fair Value, Recurring
Derivative [Line Items]
Derivative assets liabilities at fair value net		$ 13,080
Derivatives Excluding Contingent Consideration and Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 424,400
Commodity \| Natural Gas Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 18,300
Volume hedged \| MMBTU	313,453,000

Commitments and Contingencies - Schedule of Weighted Average Remaining Lease Term and Weighted Average Discount Rate for Operating Leases (Detail)	Dec. 31, 2023	Dec. 31, 2022
Lessee Disclosure [Abstract]
Weighted average remaining lease term	2 years 10 months 24 days	2 years
Weighted average discount rate	7.00%	6.00%

Fair Value Measurements

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

(9) 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 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. When transfers between levels occur, it is our policy to assume the transfer occurred at the date of the event or change in circumstances that caused the transfer.

Fair Values-Recurring


		Fair Value Measurements at December 31, 2023 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, 2023
Trading securities held in the deferred compensation plans		$	71,989	$	—	$	—		$	71,989
Derivatives	–swaps		—		247,580		—			247,580
	–collars		—		152,540		—			152,540
	–three-way collars		—		25,406		—			25,406
	–basis swaps		—		18,277		—			18,277
	–swaptions		—		—		(1,161	)		(1,161	)


		Fair Value Measurements at December 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 December 31, 2022
Trading securities held in the deferred compensation plans		$	57,717	$	—		$	—	$	57,717
Derivatives	–swaps		—		(109,844	)		—		(109,844	)
	–collars		—		(16,837	)		—		(16,837	)
	–three-way collars		—		(11,917	)		—		(11,917	)
	–basis swaps		—		521			—		521
Divestiture contingent consideration			—		13,080			—		13,080

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2023 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. Derivatives in Level 3 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 but will also utilize unobservable pricing inputs that are significant to overall value. As of December 31, 2023, a portion of our natural gas 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. At December 31, 2023, we used a weighted average implied volatility of 18% for our swaptions. 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):


	Year Ended December 31, 2023
Balance at December 31, 2022	$	—
Additions		(1,161	)
Settlements		—
Transfers out of Level 3		—
Balance at December 31, 2023	$	(1,161	)

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying consolidated statements of income. For the year ended December 31, 2023, interest and dividends were $1.6 million and mark-to-market was a gain of $7.8 million. For the year ended December 31, 2022, interest and dividends were $1.1 million and mark-to-market was a loss of $14.2 million. For the year ended December 31, 2021, interest and dividends were $951,000 and mark-to-market was a gain of $3.0 million.

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. There were no proved property impairment charges for the three-year period ended December 31, 2023.

Fair Values-Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2023 and 2022 (in thousands):


	December 31, 2023						December 31, 2022
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and basis swaps	$	442,971		$	442,971		$	28,835		$	28,835
Divestiture contingent consideration		—			—			13,080			13,080
Marketable securities (a)		71,989			71,989			57,717			57,717
(Liabilities):
Commodity swaps, collars and basis swaps		(329	)		(329	)		(166,912	)		(166,912	)
Bank credit facility (b)		—			—			(19,000	)		(19,000	)
4.875% senior notes due 2025 (b)		(688,388	)		(679,363	)		(750,000	)		(714,870	)
8.25% senior notes due 2029 (b)		(600,000	)		(624,816	)		(600,000	)		(618,312	)
4.75% senior notes due 2030 (b)		(500,000	)		(463,085	)		(500,000	)		(442,350	)
Deferred compensation plan (c)		(117,125	)		(117,125	)		(189,241	)		(189,241	)


(a)	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are updated based on end of period closing prices which is a Level 1 input.
(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 at the closing price on the balance sheet date which is a Level 1 input.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. 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 incurrence of and expected future insignificance 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.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Volumes Hedged and Average Hedge Prices

The following table sets forth the derivative volumes by year as of December 31, 2023, excluding our basis swaps which are discussed separately below:


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
			Swap		Sold Put		Floor		Ceiling
Natural Gas (a)
2024	Swaps	304,973 Mmbtu/day	$	4.01
2024	Collars	436,694 Mmbtu/day					$	3.50	$	5.63
2024	Three-way Collars	93,511 Mmbtu/day			$	2.50	$	3.40	$	4.15
2025	Swaps	400,000 Mmbtu/day	$	4.12
2025	Three-way Collars	30,000 Mmbtu/day			$	2.70	$	4.00	$	5.00
2026	Swaps	60,000 Mmbtu/day	$	4.15

Crude Oil
January-September 2024	Swaps	4,000 bbls/day	$	80.25
January-September 2024	Collars	832 bbls/day					$	80.00	$	90.12


(a)	We also sold natural gas swaptions of 40,000 Mmbtu/day for calendar year 2026 at a weighted average price of $4.11/Mmbtu that expire June 2024.

Combined Fair Value of Derivatives, by Consolidated Balance Sheets


		December 31, 2023
		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	$	238,465	$	—		$	238,465
	–swaptions		—		(1,161	)		(1,161	)
	–collars		150,456		—			150,456
	–three-way collars		25,406		—			25,406
	–basis swaps		26,852		(8,246	)		18,606
Crude oil	–swaps		9,115		—			9,115
	–collars		2,084		—			2,084
		$	452,378	$	(9,407	)	$	442,971


		December 31, 2023
		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	–swaptions	$	(1,161	)	$	1,161	$	—
	–basis swaps		(8,575	)		8,246		(329	)
		$	(9,736	)	$	9,407	$	(329	)


		December 31, 2022
		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	$	19,438	$	(6,236	)	$	13,202
	–collars		54,222		(45,452	)		8,770
	–three-way collars		12,424		(12,424	)		—
	–basis swaps		25,493		(20,437	)		5,056
Crude oil	–collars		1,807		—			1,807
Divestiture contingent consideration			13,080		—			13,080
		$	126,464	$	(84,549	)	$	41,915


		December 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	$	(115,374	)	$	6,236	$	(109,138	)
	–collars		(72,866	)		45,452		(27,414	)
	–three-way collars		(24,341	)		12,424		(11,917	)
	–basis swaps		(24,972	)		20,437		(4,535	)
Crude oil	–swaps		(13,908	)		—		(13,908	)
		$	(251,461	)	$	84,549	$	(166,912	)

Effects of Derivatives on Consolidated Statements of Operations

The effects of our derivatives on our consolidated statements of income for the last three years are summarized below (in thousands).


	Year Ended December 31,
Derivative Fair Value Income (Loss)	2023			2022			2021
Commodity swaps	$	434,836		$	(713,122	)	$	(466,203	)
Swaptions		(1,161	)		11,149			(1,346	)
Collars		260,630			(302,364	)		(117,612	)
Three-way collars		88,096			(235,335	)		(137,443	)
Basis swaps		43,833			41,622			33,691
Calls		—			(1,363	)		(836	)
Freight swaps		—			(33	)		(647	)
Divestiture contingent consideration		(5,080	)		10,940			40,180
Total	$	821,154		$	(1,188,506	)	$	(650,216	)

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.