CNX Resources (CNX) 10-K 8 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 06, 2024	Jun. 30, 2023
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-14901
Entity Registrant Name	CNX Resources Corporation
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0337383
Entity Address, Address Line One	CNX Center
Entity Address, Address Line Two	1000 Horizon Vue Drive
Entity Address, City or Town	Canonsburg
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	15317-6506
City Area Code	724
Local Phone Number	485-4000
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 2,216,454,440
Entity Common Stock, Shares Outstanding		151,791,457
Documents Incorporated by Reference	Portions of CNX's Proxy Statement for the Annual Meeting of Shareholders to be held on May 2, 2024, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001070412
Common Stock
Document Information [Line Items]
Title of 12(b) Security	Common Stock ($.01 par value)
Trading Symbol	CNX
Security Exchange Name	NYSE
Preferred Share Purchase Rights
Document Information [Line Items]
Title of 12(b) Security	Preferred Share Purchase Rights
Security Exchange Name	NYSE
No Trading Symbol Flag	true

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Firm ID	42
Auditor Name	Ernst & Young LLP
Auditor Location	Pittsburgh, Pennsylvania

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Gain (Loss) on Commodity Derivative Instruments	$ 1,928,652	$ (2,663,775)	$ (1,632,733)
Other Revenue and Operating Income	129,860	87,322	105,883
Total Revenue and Other Operating Income	3,434,948	1,261,211	756,792
Operating Expense
Lease Operating Expense	63,333	66,658	46,256
Production, Ad Valorem and Other Fees	27,946	44,965	34,051
Depreciation, Depletion and Amortization	433,586	461,215	515,118
Purchased Gas Costs	69,924	185,383	93,776
Selling, General and Administrative Costs	125,344	121,697	112,757
Other Operating Expense	79,595	63,765	68,655
Total Operating Expense	1,192,109	1,321,641	1,234,874
Other Expense
Other Expense	9,008	9,859	15,748
Gain on Asset Sales and Abandonments, net	(132,372)	(8,984)	(42,210)
Loss on Debt Extinguishment	0	22,953	33,737
Interest Expense	143,278	127,689	151,156
Total Other Expense	19,914	151,517	158,431
Total Costs and Expenses	1,212,023	1,473,158	1,393,305
Income (Loss) Before Income Tax	2,222,925	(211,947)	(636,513)
Income Tax Expense (Benefit)	502,209	(69,870)	(137,870)
Net Income (Loss)	$ 1,720,716	$ (142,077)	$ (498,643)
Earnings (Loss) Per Share
Basic (in usd per share)	$ 10.59	$ (0.75)	$ (2.31)
Diluted (in usd per share)	8.99	(0.75)	(2.31)
Dividends Declared Per Share (in usd per share)	$ 0	$ 0	$ 0
Natural Gas, NGLs and Oil Revenue
Revenue	$ 1,302,218	$ 3,652,112	$ 2,183,929
Purchased Gas Revenue
Revenue	74,218	185,552	99,713
Transportation, Gathering and Compression
Operating Expense
Cost of Goods and Services Sold	381,934	369,660	343,635
Exploration and Production Related Other Costs
Operating Expense
Cost of Goods and Services Sold	$ 10,447	$ 8,298	$ 20,626

Consolidated Statements of Comp

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 (Loss)	$ 1,720,716	$ (142,077)	$ (498,643)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $258, $(2,728), $(234))	(788)	8,010	661
Comprehensive Income (Loss)	$ 1,719,928	$ (134,067)	$ (497,982)

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Adjustment For Actuarially Determined Liabilities
Other comprehensive income, tax expense	$ 258	$ (2,728)	$ (234)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current Assets:
Cash and Cash Equivalents	$ 443	$ 21,321
Accounts and Notes Receivable:
Trade, net (Note 17)	116,119	348,458
Other Receivables, net	17,872	6,184
Supplies Inventories	19,846	27,156
Derivative Instruments (Note 19)	252,524	154,474
Prepaid Expenses	14,984	16,211
Total Current Assets	421,788	573,804
Property, Plant and Equipment (Note 8):
Property, Plant and Equipment	12,537,118	11,907,698
Less—Accumulated Depreciation, Depletion and Amortization	5,194,485	4,811,189
Total Property, Plant and Equipment—Net	7,342,633	7,096,509
Other Non-Current Assets:
Operating Lease Right-of-Use Assets (Note 13)	139,466	174,849
Derivative Instruments (Note 19)	280,530	244,931
Goodwill (Note 9)	323,314	323,314
Other Intangible Assets (Note 9)	70,438	76,990
Other	48,488	25,376
Total Other Non-Current Assets	862,236	845,460
TOTAL ASSETS	8,626,657	8,515,773
Current Liabilities:
Accounts Payable	147,361	191,343
Derivative Instruments (Note 19)	61,102	782,653
Current Portion of Finance Lease Obligations (Note 13)	1,862	881
Current Portion of Long-Term Debt (Note 12)	325,668	0
Current Portion of Operating Lease Obligations (Note 13)	53,791	47,436
Other Accrued Liabilities (Note 11)	233,214	290,491
Total Current Liabilities	822,998	1,312,804
Non-Current Liabilities:
Long-Term Debt (Note 12)	1,888,706	2,205,735
Finance Lease Obligations (Note 13)	5,500	1,970
Operating Lease Obligations (Note 13)	89,531	132,105
Derivative Instruments (Note 19)	526,554	1,517,021
Deferred Income Taxes (Note 6)	729,454	232,280
Asset Retirement Obligations (Note 7)	105,315	89,079
Other	97,582	74,318
Total Non-Current Liabilities	3,442,642	4,252,508
TOTAL LIABILITIES	4,265,640	5,565,312
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 154,382,880 Issued and Outstanding at December 31, 2023; 170,841,164 Issued and Outstanding at December 31, 2022	1,548	1,712
Capital in Excess of Par Value	2,384,910	2,506,269
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding	0	0
Retained Earnings	1,981,860	448,993
Accumulated Other Comprehensive Loss	(7,301)	(6,513)
TOTAL STOCKHOLDERS' EQUITY	4,361,017	2,950,461
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 8,626,657	$ 8,515,773

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500,000,000	500,000,000
Common stock, issued (in shares)	154,382,880	170,841,164
Common stock, outstanding (in shares)	154,382,880	170,841,164
Preferred stock, authorized (in shares)	15,000,000	15,000,000
Preferred stock, issued (in shares)	0	0
Preferred stock, outstanding (in shares)	0	0

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Cumulative Effect, Period of Adoption, Adjustment	Common Stock	Capital in Excess of Par Value	Capital in Excess of Par Value Cumulative Effect, Period of Adoption, Adjustment	Retained Earnings	Retained Earnings Cumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2020	$ 4,422,437		$ 2,208	$ 2,959,357		$ 1,476,056		$ (15,184)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(498,643)					(498,643)
Issuance of Common Stock	5,087		7	5,080
Purchase and Retirement of Common Stock	(241,243)		(183)	(146,094)		(94,966)
Shares Withheld for Taxes	(4,553)					(4,553)
Amortization of Stock-Based Compensation Awards	16,560		7	16,553
Equity Component, net of Purchase Discounts and Issuance Costs	(33)			(33)
Other Comprehensive Income	661							661
Ending balance at Dec. 31, 2021	3,700,273		2,039	2,834,863		877,894		(14,523)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of Adoption of New Accounting Standard		$ (59,337)			$ (78,284)		$ 18,947
Net Income (Loss)	(142,077)					(142,077)
Issuance of Common Stock	1,197		2	1,195
Purchase and Retirement of Common Stock	(568,128)		(335)	(267,874)		(299,919)
Shares Withheld for Taxes	(5,852)					(5,852)
Amortization of Stock-Based Compensation Awards	16,375		6	16,369
Other Comprehensive Income	8,010							8,010
Ending balance at Dec. 31, 2022	2,950,461		1,712	2,506,269		448,993		(6,513)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of Adoption of New Accounting Standard	2,950,461
Net Income (Loss)	1,720,716					1,720,716
Issuance of Common Stock	1,760		2	1,758
Purchase and Retirement of Common Stock	(321,867)		(175)	(143,343)		(178,349)
Shares Withheld for Taxes	(9,500)					(9,500)
Amortization of Stock-Based Compensation Awards	20,235		9	20,226
Other Comprehensive Income	(788)							(788)
Ending balance at Dec. 31, 2023	4,361,017		$ 1,548	$ 2,384,910		$ 1,981,860		$ (7,301)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of Adoption of New Accounting Standard	$ 4,361,017

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities:
Net Income (Loss)	$ 1,720,716	$ (142,077)	$ (498,643)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Continuing Operating Activities:
Depreciation, Depletion and Amortization	433,586	461,215	515,118
Amortization of Deferred Financing Costs	9,275	8,456	27,052
Stock-Based Compensation	20,235	16,375	16,560
Gain on Asset Sales and Abandonments, net	(132,372)	(8,984)	(42,210)
Loss on Debt Extinguishment	0	22,953	33,737
(Gain) Loss on Commodity Derivative Instruments	(1,928,652)	2,663,775	1,632,733
Loss (Gain) on Other Derivative Instruments	3,463	(10,348)	(8,485)
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	79,523	(1,735,115)	(539,016)
Deferred Income Taxes	497,432	(76,058)	(137,887)
Other	(1,967)	5,588	(1,280)
Changes in Operating Assets:
Accounts and Notes Receivable	222,751	(20,338)	(184,461)
Supplies Inventories	7,310	(21,008)	1,487
Recoverable Income Taxes	0	72	17
Prepaid Expenses	1,227	(252)	(3,204)
Changes in Other Assets	75	21,499	(23,838)
Changes in Operating Liabilities:
Accounts Payable	(55,309)	53,772	3,006
Accrued Interest	7,483	710	9,486
Other Operating Liabilities	(67,140)	(267)	107,498
Changes in Other Liabilities	(3,048)	(4,954)	18,687
Net Cash Provided by Operating Activities	814,588	1,235,014	926,357
Cash Flows from Investing Activities:
Capital Expenditures	(679,404)	(565,754)	(465,861)
Proceeds from Asset Sales	170,027	37,460	45,251
Net Cash Used in Investing Activities	(509,377)	(528,294)	(420,610)
Cash Flows from Financing Activities:
Payments on Long-Term Notes	0	(385,719)	(421,467)
Payments on Other Debt	(1,627)	(665)	(2,785)
Proceeds from Issuance of Common Stock	1,760	1,197	5,087
Shares Withheld for Taxes	(9,500)	(5,852)	(4,553)
Purchases of Common Stock	(319,866)	(565,125)	(245,243)
Debt Issuance and Financing Fees	(356)	(3,250)	(14,476)
Net Cash Used in Financing Activities	(326,089)	(688,964)	(523,781)
Net (Decrease) Increase in Cash and Cash Equivalents	(20,878)	17,756	(18,034)
Cash and Cash Equivalents at Beginning of Period	21,321	3,565	21,599
Cash and Cash Equivalents at End of Period	443	21,321	3,565
CNX Senior Notes
Cash Flows from Financing Activities:
Proceeds from issuance of senior notes	0	493,750	0
CNXM Senior Notes
Cash Flows from Financing Activities:
Repayments of revolving credit facility borrowings	0	0	(160,544)
Proceeds from issuance of senior notes	0	0	395,000
CNXM Revolving Credit Facility
Cash Flows from Financing Activities:
Proceeds from revolving credit facility borrowings	333,575	343,900	391,500
Repayments of revolving credit facility borrowings	(382,125)	(375,200)	(497,500)
CNX Revolving Credit Facility
Cash Flows from Financing Activities:
Proceeds from revolving credit facility borrowings	1,588,350	3,332,875	1,725,800
Repayments of revolving credit facility borrowings	$ (1,536,300)	$ (3,524,875)	$ (1,694,600)

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Significant Accounting Policies	SIGNIFICANT ACCOUNTING POLICIES: A summary of the significant accounting policies of CNX Resources Corporation and subsidiaries (“CNX” or “the Company”) is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements. Basis of Consolidation: The Consolidated Financial Statements include the accounts of CNX Resources Corporation, its wholly-owned subsidiaries, and its majority-owned and/or controlled subsidiaries. Investments in business entities in which CNX does not have control but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate consolidation method. Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates included in, but not limited to, the preparation of the consolidated financial statements are related to long-lived assets (including intangible assets and goodwill), accounts receivable credit losses, the values of natural gas, NGLs, condensate and oil (collectively “natural gas”) reserves, asset retirement obligations, deferred income tax assets and liabilities, contingencies, fair value of derivative instruments, the fair value of the liability and equity components of the convertible senior notes prior to the adoption of Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity on January 1, 2022, stock-based compensation and salary retirement benefits. Cash and Cash Equivalents: Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less. Trade Accounts Receivable and Allowance for Credit Losses: Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. Management records an allowance for credit losses related to the collectability of third-party customers' receivables using the historical aging of the customer receivable balance. The collectability is determined based on past events, including historical experience, customer credit rating, as well as current market conditions. CNX monitors customer ratings and collectability on an on-going basis. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no material financing receivables with a contractual maturity greater than one year at December 31, 2023 or 2022. The following represents activity related to the allowance for credit losses for the years ended: December 31, 2023 2022 Allowance for Credit Losses - Trade, Beginning of Year $ 84 $ 84 Provision for Expected Credit Losses — — Allowance for Credit Losses - Trade, End of Period $ 84 $ 84 Allowance for Credit Losses - Other Receivables, Beginning of Year $ 2,937 $ 3,322 Provision for Expected Credit Losses 32 (198) Write-off of Uncollectible Accounts (122) (187) Allowance for Credit Losses - Other Receivables, End of Period $ 2,847 $ 2,937 Inventories: Inventories are stated at the lower of cost or net realizable value. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's operations. Property, Plant and Equipment: CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Depreciation, depletion and amortization expense is calculated based on the actual produced sales volumes multiplied by the applicable rate per unit, which is derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Proved developed reserves, as estimated by petroleum engineers, are used to calculate amortization of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by petroleum engineers, are used to calculate depletion on property acquisitions. Proved oil and natural gas reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates. The Company recorded depreciation, depletion and amortization expense related to proved gas properties using the units-of-production method of $332,596, $359,761, and $415,069 for the years ended December 31, 2023, 2022 and 2021, respectively. Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred. Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and Improvements 10 to 45 Machinery and Equipment 3 to 25 Gathering and Transmission 30 to 40 Leasehold Improvements Life of Lease Costs for purchased software are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed seven years. Impairment of Long-Lived Assets: Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present, and the estimated fair value of the investment is less than the assets' carrying value. Impairment of Proved Properties: CNX performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, tests require that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using significant assumptions including projected revenues, future commodity prices and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions. Impairment of Unproved Properties: Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include, but are not limited to, changes brought about by economic factors, commodity price outlooks, our geologists’ evaluation of the property, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment expense is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire. Exploration expense, which is associated primarily with lease expirations, was $10,447, $8,298 and $20,626 for the years ended December 31, 2023, 2022 and 2021, respectively, and is included in Exploration and Production Related Other Costs in the Consolidated Statements of Income. Impairment of Goodwill: Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. All goodwill is attributed to the Midstream reporting unit within the Shale segment. Goodwill is not amortized, but rather it is evaluated for impairment annually during the fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. These indicators include, but are not limited to, overall financial performance, industry and market considerations, anticipated future cash flows and discount rates, changes in the stock price with regards to CNX, regulatory and legal developments, and other relevant factors. In connection with the annual evaluation of goodwill for impairment or earlier if an impairment indicator is identified, CNX may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. If after assessing such factors or circumstances, CNX determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. If CNX chooses to bypass the qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then CNX will perform a quantitative assessment. In the case of a quantitative assessment, CNX estimates the fair value of the reporting unit with which the goodwill is associated using level 3 inputs and compares it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. The Company uses a combination of the income approach (generally a discounted cash flow method) and market approach (which may include the guideline public company method and/or the guideline transaction method) to estimate the fair value of a reporting unit. The income approach is used to estimate value based on the present value of future economic benefits that are expected to be produced by an asset or business entity. This approach generally involves two general steps: (i) The first step involves establishing a forecast of the estimated future net cash flows expected to accrue directly or indirectly to the owner of the asset over its remaining useful life or to the owner of the business entity (including a reporting unit). (ii) The second step involves discounting these estimated future net cash flows to their present value using a market rate of return. CNX determines the fair value based on estimated future revenues and earnings before deducting net interest expense (interest expense less interest income) and income taxes (EBITDA - a non-GAAP financial measure), and also includes estimates for capital expenditures, discounted to present value using an industry rate adjusted for company-specific risk, which management feels reflects the overall level of inherent risk of the reporting unit. These assumptions are affected by expectations about future market, industry and economic conditions. Cash flow projections are derived from board approved budgeted amounts and require us to make projections and assumptions for many years into the future for demand, competition and operating costs, among other variables. Subsequent cash flows are developed using growth or contraction rates that management believes are reasonably likely to occur. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from business risks as described in Item 1A. Risk Factors of this Form 10-K. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. Although CNX believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the estimated fair value. Future results could differ from our current estimates and assumptions. For the Company’s annual impairment assessment during the fourth quarter of 2023, the Company elected to perform a qualitative impairment test on its goodwill and concluded that it is more likely than not that the fair value exceeded the carrying value and goodwill was not impaired. Impairment of Definite-Lived Intangible Assets: Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed for impairment when indicators of impairment are present. Other intangible assets are comprised of customer relationships which are amortized on a straight-line basis over approximately 17 years. Income Taxes: Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of the Company's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized. CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that do not meet the more likely than not to be sustained criteria, the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate settlement. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that the Company believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. Asset Retirement Obligations: CNX accrues the estimated costs to dismantle and remove gas-related facilities upon exhaustion of mineral reserves and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income. Investment Plan: CNX has an investment plan that is available to most employees. Throughout the years ended December 31, 2023, 2022 and 2021, the Company's matching contribution was up to 6% of eligible compensation contributed by eligible employees. The Company may also make discretionary contributions to the Plan ranging from 1% to 6% of eligible compensation for eligible employees (as defined by the Plan). There were no such discretionary contributions made by CNX for the years ended December 31, 2023, 2022 and 2021. Total matching contribution payments and costs were $3,509, $3,187 and $2,937 for the years ended December 31, 2023, 2022 and 2021, respectively. Revenue Recognition: Revenues are recognized when the recognition criteria of Accounting Standards Codification (ASC) 606 are met, which generally occurs at the point in which title passes to the customers. For natural gas, NGL and oil revenue, this occurs at the contractual point of delivery. For revenues generated from natural gas gathering services provided to third parties, this occurs when obligations under the terms of the contract with the shipper are satisfied. CNX sells a portion of its natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within the Consolidated Statements of Income in the Purchased Gas Revenue line. CNX purchases natural gas produced by third parties at market prices less a fee. The gas purchased from third parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Revenue and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX from the third party. Contingencies: From time to time, CNX, or its subsidiaries, are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred. Stock-Based Compensation: Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CNX recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 15 – Stock-Based Compensation for more information. Derivative Instruments: CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The changes in fair value of the interest rate swap agreements are accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings. CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. Commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings. None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if CNX's obligations with any of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would be required to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with the counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis, generally measured based upon Level 2 inputs, which is further described in Note 18 – Fair Value of Financial Instruments. Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions. CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties. Recent Accounting Pronouncements: In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09 - Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which enhances the transparency and decision usefulness of income tax disclosures. The amendments address more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The ASU also includes certain other amendments to improve the effectiveness of income tax disclosures. The amendments in this ASU are effective for public business entities for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of this guidance. In November 2023, the FASB issued ASU 2023-07 - Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is still evaluating the effect of the adoption of this guidance. See Note 12 – Long-Term Debt for the impact of adoption of ASU 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. Reclassifications: Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2023, with no effect on previously reported net income, stockholders' equity or statement of cash flows. Subsequent Events:

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE: Basic earnings per share is computed by dividing net income or net loss by the weighted average shares outstanding during the reporting period. Diluted earnings per share is computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include, if dilutive, additional shares from stock options, restricted stock units, performance share units and shares issuable upon conversion of CNX's outstanding 2.25% convertible senior notes due May 2026 (“the Convertible Notes”) (See Note 12 – Long-Term Debt). The number of additional shares is calculated by assuming that outstanding stock options were exercised, that outstanding restricted stock units and performance share units were released, that the shares that are issuable from the conversion of the Convertible Notes are issued (subject to the considerations discussed further in the paragraph below), and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In periods when CNX recognizes a net loss, the impact of outstanding stock awards and the potential share settlement impact related to CNX’s Convertible Notes are excluded from the diluted loss per share calculation as their inclusion would have an anti-dilutive effect. The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive: For the Years Ended December 31, 2023 2022 2021 Anti-Dilutive Options 21,650 2,262,845 2,990,094 Anti-Dilutive Restricted Stock Units 25,156 2,350,661 2,436,846 Anti-Dilutive Performance Share Units — 1,829,081 996,863 46,806 6,442,587 6,423,803 The Convertible Notes, if converted by the holder, may be settled in cash, shares of the Company's common stock or a combination thereof, at the Company's election. The Company expects to settle the principal amount of the Convertible Notes in cash. ASU 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (“ASU 2020-06”) amended the diluted earnings per share calculation for convertible instruments by requiring the use of the if-converted method (See Note 12 – Long-Term Debt for more information). The if-converted method assumes the conversion of convertible instruments occurs at the beginning of the reporting period and diluted weighted average shares outstanding includes the common shares issuable upon conversion of the convertible instruments. In periods where CNX recognizes net income, the conversion spread has a dilutive impact on diluted earnings per share when the average market price of the Company’s common stock for a given period exceeds the initial conversion price of $12.84 per share for the Convertible Notes. In connection with the Convertible Notes’ issuance, the Company entered into privately negotiated capped call transactions with certain counterparties (the “Capped Calls” and “Capped Call Transactions”), which were not included in calculating the number of diluted shares outstanding, as their effect would have been anti-dilutive. The computations for basic and diluted loss per share are as follows: For the Years Ended December 31, 2023 2022 2021 Net Income (Loss) $ 1,720,716 $ (142,077) $ (498,643) Basic Earnings (Loss) Available to Shareholders $ 1,720,716 $ (142,077) $ (498,643) Effect of Dilutive Securities: Add Back Interest on Convertible Notes (Net of Tax) 5,758 — — Diluted Earnings (Loss) Available to Shareholders $ 1,726,474 $ (142,077) $ (498,643) Weighted-Average Shares of Common Stock Outstanding 162,490,245 189,507,682 215,971,381 Effect of Diluted Shares:* Options 1,168,526 — — Restricted Stock Units 1,349,299 — — Performance Share Units 1,254,050 — — Convertible Notes 25,751,869 — — Weighted-Average Diluted Shares of Common Stock Outstanding 192,013,989 189,507,682 215,971,381 Earnings (Loss) Per Share: Basic $ 10.59 $ (0.75) $ (2.31) Diluted $ 8.99 $ (0.75) $ (2.31) *During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards and the potential share settlement impact related to CNX’s Convertible Notes are antidilutive. Shares of common stock outstanding were as follows: For the Years Ended December 31, 2023 2022 2021 Balance, Beginning of Year 170,841,164 203,531,320 220,440,993 Issuance Related to Stock-Based Compensation (1) 1,106,240 836,070 1,374,925 Retirement of Common Stock (2) (17,564,524) (33,526,226) (18,284,598) Balance, End of Year 154,382,880 170,841,164 203,531,320 (1) See Note 15 – Stock-Based Compensation for additional information. (2) See Note 5 – Stock Repurchase for additional information.

Revenue From Contracts With Cus

Revenue From Contracts With Customers	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue From Contracts With Customers	REVENUE FROM CONTRACTS WITH CUSTOMERS: Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to exclude all taxes from the measurement of transaction price. For natural gas, NGL and oil, and purchased gas revenue, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company’s efforts to satisfy the performance obligations. A portion of the contracts contain fixed consideration (i.e., fixed price contracts or contracts with a fixed differential to NYMEX or index prices). The fixed consideration is allocated to each performance obligation on a relative standalone selling price basis. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price. Revenue associated with natural gas, NGL and oil as presented on the accompanying Consolidated Statements of Income represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling natural gas, NGL and oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Included in Other Revenue and Operating Income in the Consolidated Statements of Income and in the below table are revenues generated from natural gas gathering services provided to third parties and sales of environmental attributes. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric based fees are based on actual volumes gathered. The Company generally considers the interruptible gathering of each unit (MMBtu) of natural gas as a separate performance obligation. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered. All sales of environmental attributes (which includes items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances) were under short-term contracts, and revenue is recognized when the environmental attribute is transferred to a third party. Disaggregation of Revenue The following table is a disaggregation of revenue by major source: For the Years Ended December 31, 2023 2022 2021 Revenue from Contracts with Customers: Natural Gas Revenue $ 1,131,068 $ 3,390,422 $ 1,958,718 NGL Revenue 157,573 241,535 202,670 Oil/Condensate Revenue 13,577 20,155 22,541 Total Natural Gas, NGL and Oil Revenue 1,302,218 3,652,112 2,183,929 Purchased Gas Revenue 74,218 185,552 99,713 Other Sources of Revenue and Other Operating Income: Gain (Loss) on Commodity Derivative Instruments 1,928,652 (2,663,775) (1,632,733) Other Revenue and Operating Income 129,860 87,322 105,883 Total Revenue and Other Operating Income $ 3,434,948 $ 1,261,211 $ 756,792 The disaggregated revenue information corresponds with the Company’s segment reporting found in Note 21 – Segment Information. Contract Balances CNX invoices its customers once a performance obligation has been satisfied, at which point payment is unconditional. Accordingly, CNX's contracts with customers do not give rise to material contract assets or liabilities under ASC 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer. Transaction Price Allocated to Remaining Performance Obligations ASC 606 requires that the Company disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement, including when variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a series. A significant portion of CNX's natural gas, NGL and oil and purchased gas revenue is short-term in nature with a contract term of one year or less. For those contracts, CNX has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For revenue associated with contract terms greater than one year, a significant portion of the consideration in those contracts is variable in nature and the Company allocates the variable consideration in its contract entirely to each specific performance obligation to which it relates. Therefore, any remaining variable consideration in the transaction price is allocated entirely to wholly unsatisfied performance obligations. As such, the Company has not disclosed the value of unsatisfied performance obligations pursuant to the practical expedient. For natural gas, NGL and oil revenue associated with contract terms greater than one year with a fixed price component, the aggregate amount of the transaction price allocated to remaining performance obligations was $25,629 as of December 31, 2023. The Company expects to recognize net revenue of $18,622 in the next 12 months and $4,749 over the following 12 months, with the remainder recognized thereafter. For revenue associated with CNX's midstream contracts, which also have terms greater than one year, the interruptible gathering of each unit of natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Prior-Period Performance Obligations

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Acquisitions And Dispositions	ACQUISITIONS AND DISPOSITIONS: On June 29, 2023, CNX closed on the sale of various non-operated producing oil and gas assets primarily located in the Appalachian Basin to a third party. The transaction was subject to customary adjustments in accordance with the terms and conditions of the purchase and sales agreement and was completed on September 29, 2023. Net cash proceeds of $124,600 are included in Proceeds from Asset Sale in the Consolidated Statements of Cash Flows for the year ended December 31, 2023. The net gain on the transaction was $99,516 and is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income for the year ended December 31, 2023.

Stock Repurchase

Stock Repurchase	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Stock Repurchase	STOCK REPURCHASE: On each of January 26, 2021, October 25, 2021 and July 25, 2023, the Company’s Board of Directors approved increases in the aggregate amount of the Company’s previously approved $750,000 stock repurchase program plan to $900,000, $1,900,000, and $2,900,000, respectively. As of December 31, 2023 the amount available under the stock repurchase program is $1,128,119 and is not subject to an expiration date. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans. During the year ended December 31, 2023, 17,564,524 shares were repurchased and retired at an average price of $18.14 per share for a total cost of $321,867. During the year ended December 31, 2022, 33,526,226 shares were repurchased and retired at an average price of $16.93 per share for a total cost of $568,128. During the year ended December 31, 2021, 18,284,598 shares were repurchased and retired at an average price of $13.17 per share for a total cost of $241,243.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES: Income tax expense (benefit) provided on earnings consisted of: For the Years Ended December 31, 2023 2022 2021 Current: U.S. Federal $ — $ — $ — U.S. State 4,777 6,188 17 4,777 6,188 17 Deferred: U.S. Federal 455,224 (40,649) (157,626) U.S. State 42,208 (35,409) 19,739 497,432 (76,058) (137,887) Total Income Tax Expense (Benefit) $ 502,209 $ (69,870) $ (137,870) The components of the net deferred taxes are as follows: December 31, 2023 2022 Deferred Tax Assets: Net Operating Loss- Federal $ 160,405 $ 187,154 Section 174 Expenses 92,414 26,397 Net Operating Loss - State 76,259 82,189 Federal Tax Credits 45,619 34,317 Interest Limitation 36,451 14,618 Operating Lease Liabilities 36,297 45,427 Gas Well Closing 24,652 25,045 State Deferred Tax Adjustment 15,983 — Gas Derivatives 14,466 461,952 Salary Retirement 8,488 8,167 Equity Compensation 5,419 4,474 Convertible Note Amortization 3,628 5,080 Foreign Tax Credit — 7,738 Other 6,089 8,396 Total Deferred Tax Assets 526,170 910,954 Valuation Allowance (39,264) (84,609) Net Deferred Tax Assets 486,906 826,345 Deferred Tax Liabilities: Property, Plant and Equipment (1,177,773) (850,095) Operating Lease Right-of-Use Assets (35,321) (44,238) Investment in Partnerships (2,303) (163,483) Advance Gas Royalties (404) (286) Other (559) (523) Total Deferred Tax Liabilities (1,216,360) (1,058,625) Net Deferred Tax Liability $ (729,454) $ (232,280) Deferred taxes are recorded for certain tax benefits, including net operating losses and tax credit carry-forwards, if management assesses the utilization of those assets to be more likely than not. A valuation allowance is required when it is not more likely than not that all or a portion of a deferred tax asset will be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. Positive evidence considered included financial earnings generated over the past three years for certain subsidiaries, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence includes financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods. On December 31, 2023, the Company made a state law conversion of a subsidiary from a corporation to a limited liability company. The conversion effectively terminates the tax partnership treatment of CNX Midstream Partners LP for federal and state income tax purposes. As such as of December 31, 2023, the deferred tax assets and liabilities are separately stated in the underlying deferred tax asset and liability categories, primarily Property, Plant and Equipment. As of December 31, 2023, the Company has a deferred tax asset related to federal net operating losses of $160,405. The pre-2018 federal net operating losses will expire at various times between 2035 and 2037. Because of the Tax Cuts and Jobs Act (TCJA) enacted on December 22, 2017 and the Coronavirus Aid, Relief, and Economic Security (CARES) Act enacted on March 27, 2020, the federal net operating losses (NOLs) generated in 2018 - 2021 do not expire but may only offset 80% of taxable income in any tax years beginning after 2020. As of December 31, 2023 and 2022, the Company has $45,619 and $34,317, respectively, of Federal Tax Credits available to offset future federal tax. These credits expire between 2032 and 2043. A valuation allowance on foreign tax credits of $7,738 was recorded at December 31, 2022. The valuation allowance was decreased by $7,738 in 2023 due to the expiration of the remaining foreign tax credits. CNX has, on an after federal tax basis, a deferred tax asset related to state operating losses of $76,259 with a related valuation allowance of $39,264 at December 31, 2023. The deferred tax asset related to state operating losses, on an after-tax adjusted basis, was $82,189 with a related valuation allowance of $76,871 at December 31, 2022. A review of positive and negative evidence regarding these state tax attributes concluded that the valuation allowances for various CNX subsidiaries was warranted. West Virginia enacted legislation in March 2023 for public companies which allows for a deduction for the deferred tax adjustment as of January 1, 2022 resulting from the change in state apportionment methodology from three factor to single sales factor and elimination of the throw-out rule if the change results in an aggregate increase in net deferred tax liabilities, decrease in net deferred tax assets, or change from a net deferred tax asset to a net deferred tax liability. The deduction is available over a ten year period beginning with the first tax year on or after January 1, 2033. The Company has recorded an income tax benefit of $15,983 in the Consolidated Statements of Income to reflect the recent legislative change resulting in a decrease to deferred tax liabilities in the Consolidated Balance Sheets. Pennsylvania enacted legislation in July 2022 that, among other things, gradually reduced the corporate net income tax rate over the next several years beginning in 2023 to 8.99% to ultimately 4.99% in 2031. In 2022, the Company revised the deferred state income tax rates and apportionment factors for several states to reflect, among other things, the recent PA rate reduction resulting in a benefit to deferred tax expense in the Consolidated Statements of Income. Deferred taxes also include changes relating to valuation allowance assertions against various state net operating losses due to the tax accounting treatment of unrealized gains and losses on commodity derivatives. Management will continue to assess the potential for realized deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that could materially impact net income. The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to CNX's effective tax rate: For the Years Ended December 31, 2023 2022 2021 Amount Percent Amount Percent Amount Percent Statutory U.S. Federal Income Tax Rate $ 466,814 21.0 % $ (44,509) 21.0 % $ (133,668) 21.0 % Net Effect of State Income Taxes 83,379 3.8 (5,817) 2.8 (36,300) 5.7 Uncertain Tax Positions 17,673 0.8 14,440 (6.8) 35,914 (5.6) Effect of Equity Compensation 1,036 — 2,254 (1.1) 2,465 (0.4) Effect of Change in Valuation Allowance (37,607) (1.7) (35,427) 16.7 28,704 (4.5) Deferred Adjustments (837) — 2,481 (1.2) (4,408) 0.7 Effect of State Rate Changes 297 — 10,025 (4.7) 22,458 (3.5) Effect of Federal Tax Credits (28,974) (1.3) (15,723) 7.4 (53,269) 8.3 Other 428 — 2,406 (1.1) 234 — Income Tax Expense (Benefit) / Effective Rate $ 502,209 22.6 % $ (69,870) 33.0 % $ (137,870) 21.7 % The effective tax rate for the year ended December 31, 2023 differs from the U.S. federal statutory rate primarily due to federal income tax credits, offset by uncertain tax positions, state taxes (West Virginia tax law change), equity compensation, and the decrease in certain state valuation allowance assertions as a result of a higher-than-expected unrealized gain on commodity derivative instruments generated during 2023. The effective tax rate for the year ended December 31, 2022 differs from the U.S. federal statutory rate primarily due to federal income tax credits, offset by uncertain tax positions, state taxes, equity compensation, and the decrease in certain state valuation allowance assertions as a result of a reduction in the Pennsylvania corporate income tax rate applied to deferred taxes and a higher-than-expected unrealized loss on commodity derivative instruments generated during 2022. The effective tax rate for the year ended December 31, 2021 differs from the U.S. federal statutory rate primarily due to federal income tax credits, offset by uncertain tax positions, state taxes, equity compensation, and the increase in certain state valuation allowance assertions as a result of a higher-than-expected unrealized loss on commodity derivative instruments generated during 2021. A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows: For the Years Ended December 31, 2023 2022 Balance at Beginning of Period $ 82,245 $ 67,805 Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Current Period 11,229 — Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Prior Periods 6,444 14,440 Balance at End of Period $ 99,918 $ 82,245 If these unrecognized tax benefits were recognized, $99,918 and $82,245 would affect CNX's effective income tax rate for 2023 and 2022, respectively. In 2023 and 2022, CNX recognized an increase in unrecognized tax benefits of $6,444 and $14,440, respectively, for tax benefits resulting from tax positions taken on our 2022 and 2021 federal tax returns for additional federal tax credits. CNX also recognized an increase in unrecognized tax benefits in 2023 of $11,229 for tax benefits resulting from tax positions expected to be taken on our 2023 federal tax returns for additional federal tax credits. CNX recognizes accrued interest related to unrecognized tax benefits in its interest expense. As of December 31, 2023 and 2022, the Company reported no accrued liability relating to interest in Other Liabilities in the Consolidated Balance Sheets. During the years ended December 31, 2023 and 2022, CNX paid no interest related to income tax deficiencies. CNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. CNX had no accrued liabilities for tax penalties as of December 31, 2023 and 2022.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS: The reconciliation of changes in asset retirement obligations is as follows: December 31, 2023 2022 Balance, Beginning of Year $ 98,814 $ 96,013 Obligations Divested (2,263) (251) Accretion Expense 9,025 7,982 Obligations Incurred 1,846 1,336 Obligations Settled (12,070) (7,360) Revisions in Estimated Cash Flows 17,860 1,094 Balance, End of Year $ 113,212 $ 98,814

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT: December 31, 2023 2022 Intangible Drilling Cost $ 5,902,498 $ 5,554,021 Gas Gathering Equipment 2,631,110 2,542,587 Gas Wells and Related Equipment 1,513,945 1,342,719 Proved Gas Properties 1,374,685 1,345,114 Unproved Gas Properties 724,401 734,890 Surface Land and Other Equipment 187,316 193,153 Other 203,163 195,214 Total Property, Plant and Equipment 12,537,118 11,907,698 Less: Accumulated Depreciation, Depletion and Amortization 5,194,485 4,811,189 Total Property, Plant and Equipment - Net $ 7,342,633 $ 7,096,509 Amounts below reflect properties where drilling operations have not yet commenced and therefore were not being amortized for the years ended December 31, 2023 and 2022, respectively. These assets will be amortized using the units-of-production method and reclassified to proved gas properties when placed in service. December 31, 2023 2022 Unproved Gas Properties $ 724,401 $ 734,890 Advance Royalties 1,597 1,130 Total $ 725,998 $ 736,020

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets	GOODWILL AND OTHER INTANGIBLE ASSETS: Impairment of Goodwill: All goodwill is attributed to the Midstream reporting unit within the Shale segment. Goodwill is evaluated for impairment at least annually and whenever events or changes in circumstance indicate that the fair value of a reporting unit is less than its carrying amount. In connection with the evaluation of goodwill for impairment, CNX may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. If after assessing such factors or circumstances, CNX determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. If CNX chooses to bypass the qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then CNX will perform a quantitative assessment. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. The Company uses a combination of the income approach (generally a discounted cash flow method) and market approach (which may include the guideline public company method and/or the guideline transaction method) to estimate the fair value of a reporting unit. For the Company’s annual impairment assessment during the fourth quarter of 2023, the Company elected to perform a qualitative impairment test on its goodwill and concluded that it is more likely than not that the fair value exceeded the carrying value and goodwill was not impaired. In estimating the fair value of the Midstream reporting unit, the Company used the income approach’s discounted cash flow method, which applies significant inputs not observable in the public market (Level 3), including estimates and assumptions related to the use of an appropriate discount rate, future throughput volumes, operating costs and capital spending, discounted to present value using an industry rate adjusted for company-specific risk, which management feels reflects the overall level of inherent risk of the reporting unit. These assumptions are affected by expectations about future market, industry and economic conditions. Cash flow projections were derived from board approved budgeted amounts, a seven-year operating forecast and an estimate of future cash flows. Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur. The Company used the market approach’s comparable company method. The comparable company method evaluates the value of a company using metrics of other businesses of similar size and industry. The estimates of future cash flows utilized in the impairment analysis described above were subjective in nature and are subject to impacts from business risks as described in “Item 1A. Risk Factors”. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. Although CNX believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the estimated fair value. Future results could differ from our current estimates and assumptions. The accumulated impairment loss on goodwill is $473,045, resulting in a carrying value of $323,314 at both December 31, 2023 and 2022. Other Intangible Assets: The carrying amount and accumulated amortization of other intangible assets consist of the following: December 31, 2023 2022 Other Intangible Assets: Gross Amortizable Asset - Customer Relationships $ 109,752 $ 109,752 Less: Accumulated Amortization - Customer Relationships 39,314 32,762 Total Other Intangible Assets, net $ 70,438 $ 76,990

Revolving Credit Facilities

Revolving Credit Facilities	12 Months Ended
	Dec. 31, 2023
Short-Term Debt, Other Disclosure [Abstract]
Revolving Credit Facilities	REVOLVING CREDIT FACILITIES: CNX: On each of May 10, 2023 and May 5, 2022, CNX amended its Third Amended and Restated Credit Agreement dated October 6, 2021 (as amended, the “CNX Credit Agreement”), which provides for a senior secured revolving credit facility (the “CNX Credit Facility”). In 2022, revisions were made to replace LIBOR as a benchmark interest rate with SOFR, or the secured overnight financing rate. In 2023, the elected commitments of the CNX Credit Agreement were increased from $1,300,000 to $1,350,000. Following the amendments, CNX remains the borrower and certain of its subsidiaries (not including CNX Midstream Partners LP (CNXM), its subsidiaries or general partner) as guarantor loan parties on the CNX Credit Agreement. The CNX Credit Agreement replaced the prior CNX revolving credit facility and remains subject to semi-annual redetermination. The CNX Credit Agreement has a $2,250,000 borrowing base and $1,350,000 in elected commitments, including borrowings and letters of credit. The CNX Credit Agreement matures on October 6, 2026, provided that if at any time on or after January 30, 2026 availability under the CNX Credit Agreement minus the aggregate principal amount of any and all such outstanding Convertible Notes is less than 20% of the aggregate commitments under the CNX Credit Agreement (the first such date, the “Springing Maturity Date”), then the CNX Credit Agreement will mature on the Springing Maturity Date. In addition to refinancing all outstanding amounts under the prior CNX revolving credit facility, borrowings under the CNX Credit Agreement may be used by CNX for general corporate purposes. Under the terms of the CNX Credit Agreement, borrowings will bear interest at CNX’s option at either: • the highest of (i) PNC Bank, National Association’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month SOFR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or • the one-month SOFR rate plus a margin ranging from 1.85% to 2.85%. The availability under the CNX Credit Agreement, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of the Company’s proved reserves. The CNX Credit Agreement also requires that CNX maintain a maximum net leverage ratio of no greater than 3.50 to 1.00, which is calculated as the ratio of debt less cash on hand to consolidated EBITDA, measured quarterly. CNX must also maintain a minimum current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current liabilities, excluding derivative asset/liability position, and convertible note liability until one year prior to maturity, and borrowings under the revolver, measured quarterly. The calculation of all of the ratios excludes CNX Gathering and CNXM and its subsidiaries. CNX was in compliance with all financial covenants as of December 31, 2023. At December 31, 2023, the CNX Credit Agreement had $52,050 borrowings outstanding, with a weighted average interest rate of 7.64% and $43,684 of letters of credit outstanding, leaving $1,254,266 of unused capacity. At December 31, 2022, the CNX Credit Agreement had no borrowings outstanding and $171,272 of letters of credit outstanding, leaving $1,128,728 of unused capacity. CNX M: On May 5, 2022, CNXM amended its Amended and Restated Credit Agreement dated October 6, 2021 (as amended, the “CNXM Credit Agreement”), which provides for a $600,000 senior secured revolving credit facility (“CNXM Credit Facility”) that matures on October 6, 2026. Revisions were made to replace LIBOR as a benchmark interest rate with SOFR. CNXM remains the borrower and certain of its subsidiaries remain as guarantor loan parties on the CNXM Credit Agreement. The CNXM Credit Agreement replaced the prior CNXM revolving credit facility and is not subject to semi-annual redetermination. CNX is not a guarantor under the CNXM Credit Agreement. In addition to refinancing all outstanding amounts under the prior CNXM revolving credit facility, borrowings under the CNXM Credit Agreement may be used by CNXM for general corporate purposes. Interest on outstanding indebtedness under the CNXM Credit Agreement currently accrues, at CNXM’s option, at a rate based on either: • the highest of (i) PNC Bank, National Association’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month SOFR rate plus 1.0%, in each case, plus a margin ranging from 1.00% to 2.00%; or • the one-month SOFR rate plus a margin ranging from 2.10% to 3.10%. In addition, CNXM is obligated to maintain at the end of each fiscal quarter (x) a maximum net leverage ratio of no greater than between 5.00 to 1.00 ranging to no greater than 5.25 to 1.00 in certain circumstances; (y) a maximum secured leverage ratio of no greater than 3.25 to 1.00 and (z) a minimum interest coverage ratio of no less than 2.50 to 1.00; in each case as calculated in accordance with the terms and definitions determining such ratios contained in the CNXM Credit Agreement. CNXM was in compliance with all financial covenants as of December 31, 2023. At December 31, 2023, the CNXM Credit Agreement had $105,150 of borrowings outstanding, with a weighted avera ge interest rate of 7.50% and no letters of credit outstanding, leaving $494,850 of unused capacity. At December 31, 2022, the CNXM Credit Agreement had $153,700 of borrowings outstanding, with a weighted average interest rate

Other Accrued Liabilities

Other Accrued Liabilities	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Other Accrued Liabilities	OTHER ACCRUED LIABILITIES: December 31, 2023 2022 Royalties $ 100,847 $ 144,482 Accrued Interest 44,227 36,744 Transportation Charges 17,824 12,808 Deferred Revenue 15,831 22,095 Short-Term Incentive Compensation 10,961 18,956 Accrued Other Taxes 9,343 14,067 Accrued Payroll & Benefits 6,619 6,318 Purchased Gas Payable 1,002 5,266 Other 16,777 18,142 Current Portion of Long-Term Liabilities: Asset Retirement Obligations 7,897 9,735 Salary Retirement 1,886 1,878 Total Other Accrued Liabilities $ 233,214 $ 290,491

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Long-Term Debt	LONG-TERM DEBT: December 31, 2023 2022 Senior Notes due January 2029 at 6.00%, Issued at Par Value $ 500,000 $ 500,000 Senior Notes due January 2031 at 7.375% (Principal of $500,000 less Unamortized Discount of $5,308 and $6,061, respectively) 494,692 493,939 CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $3,654 and $4,231, respectively)* 396,346 395,769 Senior Notes due March 2027 at 7.25% (Principal of $350,000 plus Unamortized Premium of $1,728 and $2,266 , respectively) 351,728 352,266 Convertible Senior Notes due May 2026 at 2.25% (Principal of $330,654 less Unamortized Discount and Issuance Costs of $4,586 and $6,460, respectively) 326,068 324,194 CNX Midstream Partners LP Revolving Credit Facility* 105,150 153,700 CNX Revolving Credit Facility 52,050 — Less: Unamortized Debt Issuance Costs 11,660 14,133 $ 2,214,374 $ 2,205,735 Less: Current Portion 325,668 — Long-Term Debt $ 1,888,706 $ 2,205,735 *CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or CNXM's Credit Facility. At December 31, 2023, annual undiscounted maturities of CNX and CNXM long-term debt during the next five years and thereafter are as follows: Year ended December 31, Amount 2024 $ — 2025 — 2026 487,854 2027 350,000 2028 — Thereafter 1,400,000 Total Long-Term Debt Maturities $ 2,237,854 During the year ended December 31, 2022, CNX completed a private offering of $500,000 in aggregate principal of 7.375% Senior Notes due January 2031 (the “Senior Notes due January 2031”) less an unamortized discount of $6,250 which accrue interest from September 26, 2022 at a rate of 7.375% per year. Interest is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on July 15, 2023. The Senior Notes due January 2031 mature on January 15, 2031, rank equally in right of payment to all of CNX's existing and future senior indebtedness and senior to any subordinated indebtedness that the Company may incur and are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). During the year ended December 31, 2022, CNX purchased and retired $350,000 of its outstanding 7.25% Senior Notes due March 2027. As part of the transaction, a loss of $9,972 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income. During the year ended December 31, 2022, CNX purchased $14,346 of its outstanding Convertible Notes. As part of this transaction, a loss of $12,981 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income. During the year ended December 31, 2021, CNXM completed a private offering of $400,000 aggregate principal amount of 4.75% CNXM Senior Notes due April 2030 (the “CNXM Senior Notes due April 2030”) less an unamortized bond discount of $5,000. The CNXM Senior Notes due April 2030, along with the related guarantees, were issued pursuant to an indenture dated September 22, 2021. The CNXM Senior Notes due April 2030 accrue interest from September 22, 2021 at a rate of 4.75% per year. Interest is payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2022. The CNXM Senior Notes due April 2030 mature on April 15, 2030. The CNXM Senior Notes due April 2030 rank equally in right of payment to all of CNXM's existing and future indebtedness and senior to any subordinated indebtedness that CNXM may incur. CNX is not a guarantor of the CNXM Senior Notes due April 2030. During the year ended December 31, 2021, CNXM purchased and retired $400,000 aggregate principal amount of its outstanding 6.50% Senior Notes due March 2026. As part of this transaction, a loss of $25,727 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income. During the year ended December 31, 2021, CNX’s wholly owned subsidiary Cardinal States Gathering Company LLC (“Cardinal States”) repaid in full the outstanding principal of $107,705 of its non-revolving credit facility and terminated the facility. As part of this transaction, a loss of $5,763 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income. Additionally, during the year ended December 31, 2021, CNX’s wholly owned subsidiary CSG Holdings II LLC (“CSG Holdings”) repaid in full the outstanding principal of $39,726 on its non-revolving credit facility and terminated the facility. As part of this transaction, a loss of $2,247 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income. In April 2020, CNX issued $345,000 in aggregate principal amount of Convertible Notes due May 2026 ("Convertible Notes") in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, including $45,000 aggregate principal amount of Convertible Notes issued pursuant to the exercise in full of the initial purchasers’ option to purchase additional Convertible Notes. The Convertible Notes are senior, unsecured obligations of the Company. The Convertible Notes bear interest at a fixed rate of 2.25% per annum, payable semi-annually in arrears on May 1 and November 1 of each year, commencing on November 1, 2020. Proceeds from the issuance of the Convertible Notes totaled $334,650, net of initial purchaser discounts and issuance costs. The Convertible Notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). The initial conversion rate is 77.8816 shares of CNX's common stock per $1,000 principal amount of Convertible Notes, which represents an initial conversion price of approximately $12.84 per share, subject to adjustment upon the occurrence of specified events. The Convertible Notes will mature on May 1, 2026, unless earlier repurchased, redeemed or converted. Before February 1, 2026, note holders will have the right to convert their Convertible Notes only upon the occurrence of the following events: • during any calendar quarter (and only during such calendar quarter) commencing after June 30, 2020, if the Last Reported Sale Price per share of Common Stock exceeds one hundred and thirty percent (130%) of the Conversion Price for each of at least twenty (20) Trading Days (whether or not consecutive) during the thirty (30) consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter; • during the five (5) consecutive Business Days immediately after any ten (10) consecutive trading day period (such ten (10) consecutive Trading Day period, the “Measurement Period”) if the trading Price per $1,000 principal amount of Notes, as determined following a request by a Holder in accordance with the procedures set forth in the indenture, for each trading day of the Measurement Period was less than ninety eight percent (98%) of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day; • if CNX calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or • upon the occurrence of certain specified corporate events as set forth in the indenture governing the Convertible Notes. From and after February 1, 2026, note holders may convert their Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date. Upon conversion, the Company may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture governing the Convertible Notes. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the Convertible Notes, that occur prior to the maturity date, the Company will increase the conversion rate, in certain circumstances, for a holder who elects to convert its Convertible Notes in connection with such a corporate event. The Company’s current intent is to settle the principal amount of the Convertible Notes in cash upon conversion. If certain corporate events that constitute a “Fundamental Change” (as defined in the indenture governing the Convertible Notes) occur, then noteholders may require the Company to repurchase their Convertible Notes at a cash repurchase price equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock. Pursuant to the terms of the Convertible Notes indenture, the Sale Price per share of Common Stock condition for conversion of the Convertible Notes was satisfied as of December 31, 2023, and, accordingly, holders of Convertible Notes are permitted to convert any of their Convertible Notes, at their option, at any time during the quarter beginning on January 1, 2024 and ending on March 31, 2024, subject to all terms and conditions set forth in the Convertible Notes indenture. At December 31, 2023, the conditions of allowing holders of the Convertible Notes to exercise their conversion right were met and as of December 31, 2023, the Convertible Notes were convertible. The Convertible Notes are therefore classified as short-term debt at December 31, 2023. On January 1, 2022, the Company adopted ASU 2020-06 using the modified transition approach with the cumulative effect recognized as an adjustment to the opening balance of retained earnings. This guidance is applicable to the Convertible Notes, for which the embedded conversion option was required to be separately accounted for as a component of stockholders’ equity. Upon adoption on January 1, 2022, long-term debt increased by $82,327 representing the net impact of two adjustments: (1) the $107,260 value of the embedded conversion, which is net of allocated offering costs, previously classified in additional paid-in-capital in stockholders’ equity, and (2) a $24,933 increase to retained earnings for the cumulative effect of adoption primarily related to the non-cash interest expense recorded for the amortization of the portion of the Convertible Notes allocated to stockholders’ equity. In addition, there was a decrease of $22,990 to deferred income taxes, a $5,986 decrease to retained earnings, and a $78,284 decrease in stockholders' equity in the Consolidated Balance Sheet. Prospectively, the reported interest expense for the Convertible Notes will no longer include the non-cash interest expense of the equity component as required under prior accounting standards and will be equal to the 2.25% cash coupon rate. Also, as required by the new accounting guidance, the Company will use the if-converted method instead of the treasury stock method for the assumed conversion of the Convertible Notes on a prospective basis when calculating diluted earnings per share. Prior to the adoption of ASU 2020-06, the Convertible Notes were separated into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of a similar debt instrument that does not have an associated conversion feature. The fair value was based on market data available for publicly traded, senior, unsecured corporate bonds with similar maturity, which represent Level 2 observable inputs. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes and was recorded in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity and was not remeasured as long as it continued to meet the conditions for equity classification. The excess of the principal amount of the Convertible Notes over the liability component and the debt issuance costs was amortized to interest expense over the contractual term of the Convertible Notes using the effective interest method. In accounting for the debt issuance costs of $10,350, the Company allocated the total amount incurred to the liability and equity components using the same proportions as the proceeds of the Convertible Notes. Issuance costs attributable to the liability component were $7,024 and were being amortized to interest expense using the effective interest method over the contractual term of the Convertible Notes. Issuance costs attributable to the equity component were $3,326 and were netted with the equity component in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity. The net carrying amount of the liability and equity components of the Convertible Notes was as follows: December 31, 2023 2022 Liability Component: Principal $ 330,654 $ 330,654 Unamortized Issuance Costs $ (4,586) $ (6,460) Net Carrying Amount $ 326,068 $ 324,194 Fair Value $ 537,465 $ 483,581 Fair Value Hierarchy Level 2 Level 2 Interest expense related to the Convertible Notes is as follows: For the Years Ended December 31, 2023 2022 Contractual Interest Expense $ 7,440 $ 7,577 Amortization of Issuance Costs 1,873 1,871 Total Interest Expense 9,313 9,448

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	LEASES: CNX's leasing activities primarily consist of operating and finance leases for electric fracturing equipment, natural gas drilling rigs, CNX's corporate headquarters as well as field offices, a natural gas gathering pipeline and commercial vehicles. Some leases include options to renew ranging from a period of 1 to 10 years, which are not recognized as part of the lease right-of-use (ROU) assets or liabilities as they are not reasonably certain to be exercised. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of the lease payments over the lease term. As most of CNX's leases do not provide an implicit rate, an incremental borrowing rate is used to determine the present value of lease payments. In accordance with ASC 842, it is the Company’s policy to exclude leases with a term of 12 months or less and to not separate lease components from non-lease components for any asset class. On May 26, 2023, CNX entered into a new lease for office space that is expected to result in an operating lease ROU asset of approximately $5,270 and an operating lease obligation of approximately $4,370 in April 2024, which is when the lease is expected to commence. On January 2, 2024, CNX entered into a new lease for an electric-powered drilling system that is expected to result in a finance lease asset, to be included within property, plant and equipment, and as a finance lease obligation of $18,823 in March 2024, which is when the lease is expected to commence. The components of lease cost were as follows: For the Years Ended December 31, 2023 2022 2021 Operating Lease Cost $ 63,087 $ 56,725 $ 60,364 Finance Lease Cost: Amortization of Right-of-Use Assets 1,628 665 1,577 Interest on Lease Liabilities 429 78 123 Short-term Lease Cost 2,357 7,784 8,589 Variable Lease Cost* 12,401 9,271 7,100 Total Lease Cost $ 79,902 $ 74,523 $ 77,753 *Amounts recognized in the Consolidated Balance Sheets for natural gas drilling rigs are measured using the rates that would be paid if the rigs were idle, as this represents the minimum payment that could be made under the contract. Variable lease cost represents amounts paid for natural gas drilling rigs above this minimum when the rigs are in use. Amounts recognized in the Consolidated Balance Sheets for electric fracturing equipment are measured using minimum pumping hours under the contract; however, pumping hours may exceed the minimum and vary period to period. Any such amounts paid related to pumping hours in excess of the minimum represent variable lease cost. Amounts recognized in the Consolidated Balance Sheets are as follows: December 31, 2023 2022 Operating Leases: Operating Lease Right-of-Use Assets $ 139,466 $ 174,849 Current Portion of Operating Lease Obligations $ 53,791 $ 47,436 Operating Lease Obligations 89,531 132,105 Total Operating Lease Liabilities $ 143,322 $ 179,541 Finance Leases: Property, Plant and Equipment $ 10,864 $ 6,777 Less—Accumulated Depreciation, Depletion and Amortization 3,502 3,926 Property, Plant and Equipment—Net $ 7,362 $ 2,851 Current Portion of Finance Lease Obligations $ 1,862 $ 881 Finance Lease Obligations 5,500 1,970 Total Finance Lease Liabilities $ 7,362 $ 2,851 Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, 2023 2022 2021 Cash Paid for Amounts Included in the Measurement of Lease Liabilities: Operating Cash Flows for Operating Leases $ 64,139 $ 55,729 $ 56,966 Operating Cash Flows for Finance Leases $ 429 $ 78 $ 123 Financing Cash Flows for Finance Leases $ 1,627 $ 665 $ 2,785 Right-of-Use Assets Obtained in Exchange for Lease Obligations: Operating Leases $ 19,477 $ 36,758 $ 4,010 Finance Leases $ 6,178 $ 1,742 $ 772 Maturities of lease liabilities are as follows: Operating Finance Leases Leases Year Ended December 31, 2024 $ 59,430 $ 2,401 2025 50,373 2,347 2026 19,372 2,278 2027 6,048 1,963 2028 6,109 598 Thereafter 15,422 30 Total Lease Payments 156,754 9,617 Less: Interest 13,432 2,255 Present Value of Lease Liabilities $ 143,322 $ 7,362 Lease terms and discount rates are as follows: For the Years Ended December 31, 2023 2022 2021 Weighted Average Remaining Lease Term (years): Operating Leases 3.59 4.41 6.20 Finance Leases 4.08 4.01 3.56 Weighted Average Discount Rate: Operating Leases 4.84 % 4.65 % 4.84 % Finance Leases 7.35 % 6.17 % 1.72 %
Leases	LEASES: CNX's leasing activities primarily consist of operating and finance leases for electric fracturing equipment, natural gas drilling rigs, CNX's corporate headquarters as well as field offices, a natural gas gathering pipeline and commercial vehicles. Some leases include options to renew ranging from a period of 1 to 10 years, which are not recognized as part of the lease right-of-use (ROU) assets or liabilities as they are not reasonably certain to be exercised. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of the lease payments over the lease term. As most of CNX's leases do not provide an implicit rate, an incremental borrowing rate is used to determine the present value of lease payments. In accordance with ASC 842, it is the Company’s policy to exclude leases with a term of 12 months or less and to not separate lease components from non-lease components for any asset class. On May 26, 2023, CNX entered into a new lease for office space that is expected to result in an operating lease ROU asset of approximately $5,270 and an operating lease obligation of approximately $4,370 in April 2024, which is when the lease is expected to commence. On January 2, 2024, CNX entered into a new lease for an electric-powered drilling system that is expected to result in a finance lease asset, to be included within property, plant and equipment, and as a finance lease obligation of $18,823 in March 2024, which is when the lease is expected to commence. The components of lease cost were as follows: For the Years Ended December 31, 2023 2022 2021 Operating Lease Cost $ 63,087 $ 56,725 $ 60,364 Finance Lease Cost: Amortization of Right-of-Use Assets 1,628 665 1,577 Interest on Lease Liabilities 429 78 123 Short-term Lease Cost 2,357 7,784 8,589 Variable Lease Cost* 12,401 9,271 7,100 Total Lease Cost $ 79,902 $ 74,523 $ 77,753 *Amounts recognized in the Consolidated Balance Sheets for natural gas drilling rigs are measured using the rates that would be paid if the rigs were idle, as this represents the minimum payment that could be made under the contract. Variable lease cost represents amounts paid for natural gas drilling rigs above this minimum when the rigs are in use. Amounts recognized in the Consolidated Balance Sheets for electric fracturing equipment are measured using minimum pumping hours under the contract; however, pumping hours may exceed the minimum and vary period to period. Any such amounts paid related to pumping hours in excess of the minimum represent variable lease cost. Amounts recognized in the Consolidated Balance Sheets are as follows: December 31, 2023 2022 Operating Leases: Operating Lease Right-of-Use Assets $ 139,466 $ 174,849 Current Portion of Operating Lease Obligations $ 53,791 $ 47,436 Operating Lease Obligations 89,531 132,105 Total Operating Lease Liabilities $ 143,322 $ 179,541 Finance Leases: Property, Plant and Equipment $ 10,864 $ 6,777 Less—Accumulated Depreciation, Depletion and Amortization 3,502 3,926 Property, Plant and Equipment—Net $ 7,362 $ 2,851 Current Portion of Finance Lease Obligations $ 1,862 $ 881 Finance Lease Obligations 5,500 1,970 Total Finance Lease Liabilities $ 7,362 $ 2,851 Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, 2023 2022 2021 Cash Paid for Amounts Included in the Measurement of Lease Liabilities: Operating Cash Flows for Operating Leases $ 64,139 $ 55,729 $ 56,966 Operating Cash Flows for Finance Leases $ 429 $ 78 $ 123 Financing Cash Flows for Finance Leases $ 1,627 $ 665 $ 2,785 Right-of-Use Assets Obtained in Exchange for Lease Obligations: Operating Leases $ 19,477 $ 36,758 $ 4,010 Finance Leases $ 6,178 $ 1,742 $ 772 Maturities of lease liabilities are as follows: Operating Finance Leases Leases Year Ended December 31, 2024 $ 59,430 $ 2,401 2025 50,373 2,347 2026 19,372 2,278 2027 6,048 1,963 2028 6,109 598 Thereafter 15,422 30 Total Lease Payments 156,754 9,617 Less: Interest 13,432 2,255 Present Value of Lease Liabilities $ 143,322 $ 7,362 Lease terms and discount rates are as follows: For the Years Ended December 31, 2023 2022 2021 Weighted Average Remaining Lease Term (years): Operating Leases 3.59 4.41 6.20 Finance Leases 4.08 4.01 3.56 Weighted Average Discount Rate: Operating Leases 4.84 % 4.65 % 4.84 % Finance Leases 7.35 % 6.17 % 1.72 %

Pension

Pension	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Pension	PENSION: The benefits for the Defined Contribution Restoration Plan were frozen effective July 1, 2018. Employees hired after this date are not eligible for this benefit plan. In addition, current participants receive no further compensation credits after that date, with the last award being 2017. Annual interest credits will continue to be made in accordance with the terms of the plan. The current portion of the pension obligation is included in Other Accrued Liabilities and the noncurrent portion is included in Other Liabilities in the Consolidated Balance Sheets. The reconciliation of changes in the benefit obligation, plan assets and funded status of the pension benefits is as follows: December 31, 2023 2022 Change in Benefit Obligation: Benefit Obligation at Beginning of Period $ 32,223 $ 42,990 Interest Cost 1,675 1,035 Actuarial Loss (Gain) 1,442 (10,006) Benefits and Other Payments (1,799) (1,796) Benefit Obligation at End of Period $ 33,541 $ 32,223 Change in Plan Assets: Fair Value of Plan Assets at Beginning of Period $ — $ — Company Contributions 1,799 1,796 Benefits and Other Payments (1,799) (1,796) Fair Value of Plan Assets at End of Period $ — $ — Funded Status: Current Liabilities $ (1,886) $ (1,878) Noncurrent Liabilities (31,655) (30,345) Net Obligation Recognized $ (33,541) $ (32,223) Amounts Recognized in Accumulated Other Comprehensive Loss Consist of: Net Actuarial Loss $ 9,153 $ 7,884 Prior Service Cost 842 1,063 Total 9,995 8,947 Less: Tax Benefit 2,694 2,434 Net Amount Recognized $ 7,301 $ 6,513 The components of the net periodic benefit cost are as follows: For the Years Ended December 31, 2023 2022 2021 Components of Net Periodic Benefit Cost: Interest Cost 1,675 1,035 855 Amortization of Prior Service Cost 222 221 222 Recognized Net Actuarial Loss 173 510 513 Net Periodic Benefit Cost $ 2,070 $ 1,766 $ 1,590 CNX utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the pension plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO) or the market-related value of plan assets are amortized over the expected remaining future lifetime of all plan participants for the pension plan. The following table provides information related to the pension plan with an accumulated benefit obligation in excess of plan assets: As of December 31, 2023 2022 Projected Benefit Obligation $ 33,541 $ 32,223 Accumulated Benefit Obligation $ 33,541 $ 32,223 Fair Value of Plan Assets $ — $ — Assumptions: The weighted-average assumptions used to determine benefit obligations are as follows: As of December 31, 2023 2022 Discount Rate 5.15 % 5.43 % Rate of Compensation Increase — % — % Interest Credited Rate 4.74 % 4.43 % The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans. The increase in discount rate during 2022 compared to the prior year caused a significant actuarial gain during the year ended December 31, 2022. The weighted-average assumptions used to determine net periodic benefit cost are as follows: For the Years ended December 31, 2023 2022 2021 Discount Rate 5.43 % 2.84 % 2.47 % Rate of Compensation Increase — % — % — % Interest Credited Rate 4.81 % 4.07 % 2.71 % Cash Flows: The following benefit payments, which reflect expected future service, are expected to be paid: Pension Year ended December 31, Benefits 2024 $ 1,886 2025 $ 1,983 2026 $ 2,053 2027 $ 2,143 2028 $ 2,236 Year 2029-2033 $ 13,057

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation	STOCK-BASED COMPENSATION: CNX's Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the Equity Incentive Plan have been adopted and approved by the Board of Directors and the Company's shareholders since the commencement of the Equity Incentive Plan. Most recently, in May 2020 the Company's Shareholders adopted and approved a 10,775,000 increase to the total number of shares available for issuance. At December 31, 2023, 7,853,582 shares of common stock remained available for grant under the plan. The Equity Incentive Plan provides that the aggregate number of shares available for issuance will be reduced by one share for each share relating to stock options and by 1.62 for each share relating to Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the Equity Incentive Plan after the tenth anniversary of the grant date of the award. For those shares expected to vest, CNX recognizes stock-based compensation costs on a straight-line basis over the requisite service period of the award, which is generally the vesting term. Options and RSUs vest over a three-year term. PSUs granted in 2019 vest over a five-year term and PSUs granted in 2020-January 2023 vest over a three-year term subject to performance conditions. PSUs granted in August 2023 vest over a seven-year term. If an employee leaves the Company, all unvested shares are forfeited. CNX recognizes forfeitures as they occur. The vesting of all awards will accelerate in the event of death and disability and may accelerate upon a change in control of CNX. The total stock-based compensation expense recognized relating to CNX shares during the years ended December 31, 2023, 2022 and 2021 was $20,235, $16,375 and $16,560, respectively. The related deferred tax benefit totaled $6,983, $4,497, $4,409, respectively. As of December 31, 2023, CNX has $24,731 of unrecognized compensation cost related to all non-vested stock-based compensation awards, which is expected to be recognized over a weighted-average period of 3.15 years. When stock options are exercised, and restricted and performance stock unit awards become vested, the issuances are made from CNX's common stock shares. Stock Options: CNX examined its historical pattern of option exercises in an effort to determine if there were any discernible activity patterns based on certain employee populations. From this analysis, CNX identified two distinct employee populations and used the Black-Scholes option pricing model to value the options for each of the employee populations. The expected term computation presented in the table below is based upon a weighted average of the historical exercise patterns and post-vesting termination behavior of the two populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends. The total fair value of options granted during the years ended December 31, 2023 and 2022 was $115 and $115, respectively, based on the following assumptions and weighted average fair values. There were no options granted during the year ended December 31, 2021. December 31, 2023 2022 Weighted Average Fair Value of Grants $ 7.06 $ 10.60 Risk-free Interest Rate 3.24 % 3.02 % Expected Dividend Yield — % — % Expected Forfeiture Rate — % — % Expected Volatility 48.70 % 54.00 % Expected Term in Years 5.50 5.5 A summary of the status of stock options granted is presented below: Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic Exercise Term (in Value (in Shares Price years) thousands) Outstanding at December 31, 2022 2,262,845 $ 8.55 Granted 16,289 $ 14.63 Exercised (193,264) $ 9.10 Outstanding at December 31, 2023 2,085,870 $ 8.55 2.72 $ 23,890 Exercisable at December 31, 2023 2,069,581 $ 8.50 2.67 $ 23,802 At December 31, 2023, there were 1,657,445 employee stock options outstanding under the Equity Incentive Plan. Non-employee director stock options vest one year after the grant date. There are 428,425 stock options outstanding under these grants. The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CNX's closing stock price on the last trading day of the year ended December 31, 2023 and the option's exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2023. This amount varies based on the fair market value of CNX's stock. The total intrinsic value of options exercised for the years ended December 31, 2023, 2022 and 2021 was $2,015, $1,825, and $5,027, respectively. Cash received from option exercises for the years ended December 31, 2023, 2022 and 2021 was $1,760, $1,197 and $5,087, respectively. The tax impact from option exercises totaled $529, $463 and $960 for the years ended December 31, 2023, 2022 and 2021, respectively. Restricted Stock Units: Under the Equity Incentive Plan, CNX grants certain employees and non-employee directors RSU awards, which entitle the holder to receive shares of common stock as the award vests. Non-employee director RSUs vest at the end of one year. Compensation expense is recognized over the vesting period of the units, described above. The total fair value of RSUs granted during the years ended December 31, 2023, 2022 and 2021 was $16,194, $16,852 and $12,603, respectively. The total fair value of restricted stock units vested during the years ended December 31, 2023, 2022 and 2021 was $12,321, $11,811 and $9,249, respectively. The following table represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2022 1,833,920 $12.69 Granted 999,465 $16.20 Vested (1,031,200) $11.95 Forfeited (205,645) $14.51 Nonvested at December 31, 2023 1,596,540 $15.14 Performance Share Units: Under the Equity Incentive Plan, CNX grants certain employees performance share unit awards, which entitle the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. The total fair value of performance share units granted during the years ended December 31, 2023, 2022 and 2021 was $18,383, $7,726 and $7,634, respectively. The total fair value of performance share units vested during the years ended December 31, 2023, 2022 and 2021 was $4,563, $949 and $6,206, respectively. The following table represents the nonvested performance share units and their corresponding fair value (based upon the Monte Carlo Methodology for market-based awards and the stock price on the date of grant for performance based awards) on the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2022 2,293,678 $10.53 Granted 1,687,329 $10.89 Vested (576,421) $7.92 Forfeited (605,868) $12.93 Nonvested at December 31, 2023 2,798,718 $10.77

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2023
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	SUPPLEMENTAL CASH FLOW INFORMATION: The following are non-cash transactions that impact the investing and financing activities of CNX. As of December 31, 2023, 2022 and 2021, CNX purchased goods and services related to capital projects in the amount of $28,198, $56,052 and $35,592, respectively, which are included in accounts payable. The following table shows cash paid (received): For the Years Ended December 31, 2023 2022 2021 Interest (Net of Amounts Capitalized) $ 122,279 $ 126,643 $ 123,466 Income Taxes $ 7,329 $ — $ —

Concentration of Credit Risk an

Concentration of Credit Risk and Major Customers	12 Months Ended
	Dec. 31, 2023
Risks and Uncertainties [Abstract]
Concentration of Credit Risk and Major Customers	CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS: CNX markets natural gas primarily to gas wholesalers in the United States. Concentration of credit risk is summarized below: December 31, 2023 2022 Gas Wholesalers $ 99,493 $ 304,842 NGL, Condensate & Processing Facilities 12,005 26,382 Other 4,705 17,318 Allowance for Credit Losses (84) (84) Total Accounts Receivable Trade $ 116,119 $ 348,458 As of December 31, 2023, receivables of $13,416 due from NRG Business Marketing LLC (formerly Direct Energy Business Marketing LLC) and $11,611 due from DTE Energy were included in the Gas Wholesalers balance above. As of December 31, 2022, a receivable of $33,322 due from Direct Energy Business Marketing LLC was included. No other customers made up more than 10% of the total balances. During the year ended December 31, 2023, sales to Citadel Energy Marketing LLC were $180,039 and sales to NRG Business Marketing LLC (formerly Direct Energy Business Marketing LLC) were $165,465, each of which comprised over 10% of the Company's revenue from contracts with external customers for the period. During the year ended December 31, 2022, sales to Direct Energy Business Marketing LLC were $453,501, which comprised over 10% of the Company's revenue from contracts with external customers for the period. During the year ended December 31, 2021, sales to Citadel Energy Marketing LLC were $334,407 and sales to Direct Energy Business Marketing LLC were $235,760, each of which comprised over 10% of the Company's revenue from contracts with external customers for the period.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS: CNX determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR and SOFR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use. The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below: Level 1 - Quoted prices for identical instruments in active markets. Level 2 - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR and SOFR-based discount rates and basis forward curves. Level 3 - Unobservable inputs significant to the fair value measurement supported by little or no market activity. In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy. The financial instrument measured at fair value on a recurring basis is summarized below: Fair Value Measurements at December 31, 2023 Fair Value Measurements at December 31, 2022 Description Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity Derivatives $ — $ (55,701) * $ — $ — $ (1,904,830) ** $ — Interest Rate Swaps $ — $ 1,099 $ — $ — $ 4,561 $ — *Includes $6,741 of derivatives that have been settled but not received and $900 that have been settled but not paid. **Includes $77,662 of gas derivatives that have been settled but not paid . The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows: December 31, 2023 December 31, 2022 Carrying Fair Carrying Fair Cash and Cash Equivalents $ 443 $ 443 $ 21,321 $ 21,321 Long-Term Debt (Excluding Debt Issuance Costs)* $ 2,226,034 $ 2,376,594 $ 2,219,868 $ 2,240,919 Cash and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that is not actively traded is valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	DERIVATIVE INSTRUMENTS: CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The change in fair value of the interest rate swap agreements is accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings. In March 2020, CNX entered into an interest rate swap agreement, inclusive of a put option at zero basis points, related to $160,000 of borrowings under the CNX Credit Facility which has the economic effect of modifying the variable-interest obligation into a fixed-interest obligation over a four-year period. In March 2020, CNX entered into a four-year interest rate swap related to an additional $250,000 of borrowings under the CNX Credit Facility, inclusive of a put option at zero basis points, effective April 3, 2020. In December 2020, CNX executed an offsetting $250,000 interest rate swap, effective immediately, which expires in April 2024. Consistent with the previous interest rate swap agreements, the $250,000 interest rate swaps were entered into to manage CNX's exposure to interest rate volatility. CNX enters into financial derivative instruments (over-the-counter swaps) to manage its exposure to natural gas and NGL price fluctuations. Typically, CNX "sells" swaps under which it receives a fixed price from counterparties and pays a floating market price. In order to lock in certain margins while balancing its basis hedges, during the first quarter of 2022, CNX purchased, rather than sold, financial natural gas swaps for the period April through October of 2022. Under these purchased financial swaps, CNX pays a fixed price to, and receives a floating price from, its hedge counterparties. Purchased swaps have the effect of reducing total hedged volumes for the period of the swap. Commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings. CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties. None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions. However, as stated in the applicable counterparty master agreements, if CNX's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with our counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis. Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions. The total notional amounts of CNX's derivative instruments were as follows: December 31, Forecasted to 2023 2022 Settle Through Natural Gas Commodity Swaps (Bcf) 1,349.2 1,607.9 2027 Natural Gas Basis Swaps (Bcf) 760.3 1,023.7 2027 Propane Commodity Swaps (Mbbls) 81.0 $ — 2024 Interest Rate Swaps $ 410,000 $ 410,000 2024 The gross fair value of CNX's derivative instruments was as follows: December 31, 2023 2022 Current Assets: Commodity Derivative Instruments: Commodity Swaps $ 168,532 $ 21,759 Propane Swaps 1,003 — Basis Only Swaps 77,540 118,115 Interest Rate Swaps 5,449 14,600 Total Current Assets $ 252,524 $ 154,474 Other Non-Current Assets: Commodity Derivative Instruments: Commodity Swaps $ 166,701 $ 42,786 Basis Only Swaps 113,829 197,280 Interest Rate Swaps — 4,865 Total Other Non-Current Assets $ 280,530 $ 244,931 Current Liabilities: Commodity Derivative Instruments: Commodity Swaps $ 47,279 $ 732,717 Basis Only Swaps 9,473 38,559 Interest Rate Swaps 4,350 11,377 Total Current Liabilities $ 61,102 $ 782,653 Non-Current Liabilities: Commodity Derivative Instruments: Commodity Swaps $ 484,357 $ 1,466,124 Basis Only Swaps 42,197 47,370 Interest Rate Swaps — 3,527 Total Non-Current Liabilities $ 526,554 $ 1,517,021 The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows: For the Years Ended December 31, 2023 2022 2021 Realized Gain (Loss) on Commodity Derivative Instruments: Natural Gas Commodity Swaps $ 62,567 $ (1,971,287) $ (596,619) Natural Gas Basis Swaps 98,582 158,510 57,603 Propane Swaps 1,877 — — Total Realized Gain (Loss) on Commodity Derivative Instruments 163,026 * (1,812,777) ** (539,016) Unrealized Gain (Loss) on Commodity Derivative Instruments: Natural Gas Commodity Swaps 1,858,060 (922,424) (1,240,827) Natural Gas Basis Swaps (93,222) 71,426 147,110 Propane Swaps 788 — — Total Unrealized Gain (Loss) on Commodity Derivative Instruments 1,765,626 (850,998) (1,093,717) Gain (Loss) on Commodity Derivative Instruments: Natural Gas Commodity Swaps 1,920,627 (2,893,711) (1,837,446) Natural Gas Basis Swaps 5,360 229,936 204,713 Propane Swaps 2,665 — — Total Gain (Loss) on Commodity Derivative Instruments $ 1,928,652 $ (2,663,775) $ (1,632,733) * Includes $6,741 of derivatives that have been settled but not received and $900 that have been settled but not paid at December 31, 2023, and excludes $77,662 of gas derivatives that were settled but not paid at December 31, 2022. ** Includes $77,662 of gas derivatives that were settled but not paid at December 31, 2022. The effect of interest rate swaps on Interest Expense in the Company's Consolidated Statements of Income was as follows: For the Years Ended December 31, 2023 2022 2021 Cash Received (Paid) in Settlement of Interest Rate Swaps $ 4,207 $ (1,572) $ (5,574) Unrealized (Loss) Gain on Interest Rate Swaps (3,463) 10,348 8,485 Gain on Interest Rate Swaps $ 744 $ 8,776 $ 2,911 The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and normal sales exception and are not subject to derivative instrument accounting.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	COMMITMENTS AND CONTINGENT LIABILITIES: CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, royalty accounting, damage to property, climate change, governmental regulations including environmental violations and remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CNX; however, such amounts cannot be reasonably estimated. The 1992 Coal Industry Retiree Health Benefit Act ("Coal Act"), in Section 9711, requires coal companies that were providing health benefits to United Mine Workers of America ("UMWA") retirees as of February 1993 to continue providing health benefits to such individuals, in substantially the same coverages, for as long as the last signatory operator remains in business. Section 9711 also requires any "related person" to be joint and severally liable for the provision of these health benefits. On May 1, 2020, the court in the Murray Energy Corporation ("Murray") bankruptcy proceedings approved a settlement agreement between Murray and the UMWA that transferred to the UMWA 1992 Benefit Plan the Coal Act liabilities for retirees in Murray’s Section 9711 plan. The retirees transferred by Murray to the 1992 Benefit Plan include approximately 2,159 retirees allegedly traced to the December 2013 sale by CONSOL Energy Inc. to Murray Energy of the following possible last signatory operators: Consolidation Coal Company, McElroy Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Keystone Coal Mining Corp., and Eighty-Four Mining Company (the "Sold Subsidiaries"). On May 2, 2020, the Trustees of the UMWA 1992 Benefit Plan sued CNX and CONSOL Energy Inc. ("CONSOL'") in federal court contending that the Sold Subsidiaries were last signatory operators and that CNX and CONSOL are related persons to the Sold Subsidiaries and, as such, CNX and CONSOL are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The 1992 Plan seeks, among other relief, a declaration that CNX and CONSOL are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 Plan; that CNX and CONSOL are liable to post the security required by Section 9712; and, that CNX and CONSOL are liable to pay per beneficiary premiums until the eligible retirees are enrolled in a Section 9711 plan, and other fees, costs and disbursements under the Coal Act. On March 29, 2022, the Court denied the Defendants’ Motions to Dismiss and we are now defending this action on the merits. Further, under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, CONSOL agreed to indemnify CNX for all coal-related liabilities, including this lawsuit. With respect to this matter, although a loss is possible, it is not probable, and accordingly no accrual has been recognized. On July 22, 2021, CNX received a letter from the UMWA 1974 Pension Plan requesting information related to the facts and circumstances surrounding the 2013 sale of certain of its coal subsidiaries to Murray Energy. The letter indicates that litigation related to potential withdrawal liabilities from the plan created by the 2019 bankruptcy of Murray Energy is reasonably foreseeable. At this time, no liability has been assessed. Under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, CONSOL agreed to indemnify CNX for all coal-related liabilities including any potential withdrawal liabilities. At December 31, 2023, CNX has provided the following financial guarantees, unconditional purchase obligations, and letters of credit to certain third parties as described by major category in the following tables. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management believes that the commitments in the following table will expire without being funded, and therefore will not have a material adverse effect on CNX’s financial condition. Amount of Commitment Expiration Per Period Total Less Than 1-3 Years 3-5 Years Beyond Letters of Credit: Firm Transportation $ 40,331 $ 40,331 $ — $ — $ — Other 3,353 3,353 — — — Total Letters of Credit 43,684 43,684 — — — Surety Bonds: Employee-Related 2,250 2,250 — — — Environmental 11,449 11,449 — — — Firm Transportation 126,336 126,336 — — — Financial Guarantees 72,720 72,720 — — — Other 8,682 8,682 — — — Total Surety Bonds 221,437 221,437 — — — Total Commitments $ 265,121 $ 265,121 $ — $ — $ — Excluded from the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business in November 2017. Although CONSOL has agreed to indemnify CNX to the extent that CNX would be called upon to pay any of these liabilities, there is no assurance that CONSOL will satisfy its obligations to indemnify CNX in the event that CNX is so called upon (See “Item 1A. Risk Factors” in this Form 10-K). CNX enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded in the Consolidated Balance Sheets. As of December 31, 2023, the purchase obligations for each of the next five years and beyond are as follows: Obligations Due Amount Less than 1 year $ 247,586 1 - 3 years 446,255 3 - 5 years 373,180 More than 5 years 581,370 Total Purchase Obligations $ 1,648,391

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Segment Information	SEGMENT INFORMATION: The Company reports segment information based on the “management” approach. The management approach designates the internal reporting used by management for making decisions and assessing performance as the source of the Company’s reportable segments. The Company evaluates the performance of its reportable segments based on total revenue and other operating income and operating expenses directly attributable to that segment. Certain expenses are managed outside the reportable segments and therefore are not allocated. These expenses include, but are not limited to, interest expense and other corporate expenses such as selling, general and administrative costs. CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers and the Company has two reportable segments that conducts those operations: Shale and Coalbed Methane. The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, New Technologies, as well as various other expenses that are managed outside the reportable segments as discussed above. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Industry segment results for the year ended December 31, 2023 are: Shale Coalbed Other Consolidated Natural Gas, NGLs and Oil Revenue $ 1,170,393 $ 130,763 $ 1,062 $ 1,302,218 (A) Purchased Gas Revenue — — 74,218 74,218 Gain on Commodity Derivative Instruments 151,408 11,554 1,765,690 1,928,652 Other Revenue and Operating Income 66,559 — 63,301 129,860 (B) Total Revenue and Other Operating Income $ 1,388,360 $ 142,317 $ 1,904,271 $ 3,434,948 Total Operating Expense $ 746,050 $ 141,708 $ 304,351 $ 1,192,109 Earnings Before Income Tax $ 642,310 $ 609 $ 1,580,006 $ 2,222,925 Segment Assets $ 6,656,655 $ 948,795 $ 1,021,207 $ 8,626,657 (C) Depreciation, Depletion and Amortization $ 365,020 $ 50,052 $ 18,514 $ 433,586 Capital Expenditures $ 629,631 $ 36,804 $ 12,969 $ 679,404 (A) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $180,039 to Citadel Energy Marketing LLC and $165,465 to NRG Business Marketing LLC (formerly Direct Energy Business Marketing LLC), each of which comprises over 10% of revenue from contracts with external customers for the period. (B) Includes midstream revenue of $66,559 and equity in earnings of unconsolidated affiliates of $2,942 for Shale and Other, respectively. Other also includes sales of environmental attributes of $40,685. (C) Includes investments in unconsolidated equity affiliates of $13,682. Industry segment results for the year ended December 31, 2022 are: Shale Coalbed Other Consolidated Natural Gas, NGLs and Oil Revenue $ 3,334,677 $ 314,695 $ 2,740 $ 3,652,112 (D) Purchased Gas Revenue — — 185,552 185,552 Loss on Commodity Derivative Instruments (1,672,974) (139,131) (851,670) (2,663,775) Other Revenue and Operating Income 69,618 — 17,704 87,322 (E) Total Revenue and Other Operating Income (Loss) $ 1,731,321 $ 175,564 $ (645,674) $ 1,261,211 Total Operating Expense $ 790,960 $ 131,426 $ 399,255 $ 1,321,641 Earnings (Loss) Before Income Tax $ 940,361 $ 44,138 $ (1,196,446) $ (211,947) Segment Assets $ 6,452,075 $ 959,126 $ 1,104,572 $ 8,515,773 (F) Depreciation, Depletion and Amortization $ 388,641 $ 53,201 $ 19,373 $ 461,215 Capital Expenditures $ 544,914 $ 15,043 $ 5,797 $ 565,754 (D) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $453,501 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period. (E) Includes midstream revenue of $69,618 and equity in earnings of unconsolidated affiliates of $1,412 for Shale and Other, respectively. (F) Includes investments in unconsolidated equity affiliates of $11,714. Industry segment results for the year ended December 31, 2021 are: Shale Coalbed Other Consolidated Natural Gas, NGLs and Oil Revenue $ 1,988,993 $ 193,578 $ 1,358 $ 2,183,929 (G) Purchased Gas Revenue — — 99,713 99,713 Loss on Commodity Derivative Instruments (492,526) (46,304) (1,093,903) (1,632,733) Other Revenue and Operating Income 81,267 — 24,616 105,883 (H) Total Revenue and Other Operating Income (Loss) $ 1,577,734 $ 147,274 $ (968,216) $ 756,792 Total Operating Expense $ 804,004 $ 117,900 $ 312,970 $ 1,234,874 Earnings (Loss) Before Income Tax $ 773,730 $ 29,374 $ (1,439,617) $ (636,513) Segment Assets $ 6,071,495 $ 1,047,851 $ 981,405 $ 8,100,751 (I) Depreciation, Depletion and Amortization $ 440,024 $ 58,602 $ 16,492 $ 515,118 Capital Expenditures $ 453,603 $ 10,880 $ 1,378 $ 465,861 (G) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $334,407 to Citadel Energy Marketing LLC and $235,760 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period. (H) Includes midstream revenue of $81,267 and equity in earnings of unconsolidated affiliates of $5,780 for Shale and Other, respectively. (I) Includes investments in unconsolidated equity affiliates of $17,301. Reconciliation of Segment Information to Consolidated Amounts: Revenue and Other Operating Income: For the Years Ended December 31, 2023 2022 2021 Total Segment Revenue from Contracts with External Customers $ 1,442,995 $ 3,907,282 $ 2,364,909 Gain (Loss) on Commodity Derivative Instruments 1,928,652 (2,663,775) (1,632,733) Other Operating Income 63,301 17,704 24,616 Total Consolidated Revenue and Other Operating Income $ 3,434,948 $ 1,261,211 $ 756,792

Supplemental Gas Data (unaudite

Supplemental Gas Data (unaudited)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Supplemental Gas Data (unaudited)	SUPPLEMENTAL GAS DATA (unaudited): The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” The supplementary information summarized below presents the results of natural gas and oil activities for the Company in accordance with the successful efforts method of accounting for production activities. Capitalized Costs: As of December 31, 2023 2022 Intangible Drilling Costs $ 5,902,498 $ 5,554,021 Gas Gathering Assets 2,631,110 2,542,587 Proved Gas Properties 1,374,685 1,345,114 Unproved Gas Properties 724,401 734,890 Gas Wells and Related Equipment 1,513,945 1,342,719 Other Gas Assets 119,163 99,457 Total Property, Plant and Equipment 12,265,802 11,618,788 Accumulated Depreciation, Depletion and Amortization (5,110,938) (4,710,684) Net Capitalized Costs $ 7,154,864 $ 6,908,104 Costs incurred for property acquisition, exploration and development (*): For the Years Ended December 31, 2023 2022 2021 Property Acquisitions: Proved Properties $ 2,319 $ 19,766 $ 32,355 Unproved Properties 26,405 14,802 20,568 Development** 637,711 526,092 393,641 Exploration 4,257 6,806 30,927 Total $ 670,692 $ 567,466 $ 477,491 __________ (*) Includes costs incurred whether capitalized or expensed. (**) Includes development costs for midstream of $47 million, $38 million and $35 million for 2023, 2022 and 2021, respectively. Results of Operations for Producing Activities: For the Years Ended December 31, 2023 2022 2021 Natural Gas, NGLs and Oil Revenue $ 1,302,218 $ 3,652,112 $ 2,183,929 Realized Gain (Loss) on Commodity Derivative Instruments 163,026 (1,812,777) (539,016) Unrealized Gain (Loss) on Commodity Derivative Instruments 1,765,626 (850,998) (1,093,717) Purchased Gas Revenue 74,218 185,552 99,713 Total Revenue 3,305,088 1,173,889 650,909 Lease Operating Expense 63,333 66,658 46,256 Production, Ad Valorem and Other Fees 27,946 44,965 34,051 Transportation, Gathering and Compression 381,934 369,660 343,635 Purchased Gas Costs 69,924 185,383 93,776 Exploration Costs 10,447 8,298 20,626 Depreciation, Depletion and Amortization 433,586 461,215 515,118 Total Costs 987,170 1,136,179 1,053,462 Pre-tax Operating Income (Loss) 2,317,918 37,710 (402,553) Income Tax Expense (Benefit) 523,849 12,444 (87,354) Results of Operations for Producing Activities excluding Corporate and Interest Costs $ 1,794,069 $ 25,266 $ (315,199) The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production: For the Years Ended December 31, 2023 2022 2021 Production (MMcfe) 560,366 580,169 590,248 Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe) $ 2.32 $ 6.29 $ 3.70 Average Effects of Commodity Derivative Financial Settlements (per Mcfe) $ 0.32 $ (3.35) $ (0.98) Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe) $ 2.61 $ 3.17 $ 2.79 Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe) $ 0.11 $ 0.11 $ 0.08 During the years ended December 31, 2023, 2022 and 2021, the Company drilled 30.8, 37.0, and 33.0 net development wells, respectively. There were no net dry development wells in 2023, 2022 or 2021. There were no net exploratory wells drilled during the years ended December 31, 2023, 2022 or 2021. There were no net dry exploratory wells in 2023, 2022 or 2021. As of December 31, 2023, there were 13.8 net development wells and no explo ratory wells drilled but uncompleted. CNX is committed to provide 470.9 Bcf of gas under existing sales contracts or agreements over the course of the next four years. The Company expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments. Most of the Company’s development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2023, the number of producing wells, developed acreage and undeveloped acreage: Gross(1) Net(2) Producing Gas Wells (including Gob Wells) - Working Interest 4,499 4,425 Producing Oil Wells - Working Interest 2 — Producing Gas Wells - Royalty Interest 320 — Producing Oil Wells - Royalty Interest 126 — Acreage Position: Proved Developed Acreage 385,087 385,087 Proved Undeveloped Acreage 40,811 40,811 Unproved Acreage 4,704,922 3,392,132 Total Acreage 5,130,820 3,818,030 ____________ (1) All of our acreage identified as proved developed and undeveloped is controlled fully by CNX through ownership of a 100% working interest. (2) Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. Proved Oil and Gas Reserves Quantities: Annually, the preparation of natural gas reserves estimates is completed in accordance with CNX prescribed internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as multi-functional management review. As part of the annual review, management reviews and approves changes in the future development plan and the impact to proved-undeveloped locations to ensure that annual changes are aligned with the overall strategic business plan of the Company. A detailed review is completed to ensure that all proved undeveloped locations will be fully developed within five-years of the reserves booking. As part of the development plan review, management reviews current well production data, acreage position, downstream infrastructure availability, operational leases and other commitments, financial capacity to complete the development and individual project economics in expected future gas pricing scenarios. The input data verification includes reviews of the price and operating, and development cost assumptions as well as tax rates by jurisdiction used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a registered professional engineer in the state of West Virginia with over 19 years of experience in the oil and gas industry. The Company’s gas reserves results, which are reported in Note 22 – Supplemental Gas Data for the year ended December 31, 2023 Form 10-K, were audited by independent petroleum engineers, Netherland, Sewell & Associates, Inc. The technical person primarily responsible for overseeing the audit of the Company's reserves is a registered professional engineer in the state of Texas with over 11 years of experience in the oil and gas industry. The oil and gas reserves estimates are as follows: Condensate Consolidated Natural Gas NGLs & Crude Oil Operations (MMcf) (Mbbls) (Mbbls) (MMcfe) Balance December 31, 2020 (a) 9,034,066 81,867 4,081 9,549,758 Revisions (b) (409,215) 13,655 39 (327,050) Price Changes 82,248 692 22 86,532 Extensions and Discoveries (e) 832,696 12,047 294 906,738 Production (551,988) (5,976) (400) (590,248) Balance December 31, 2021 (a) 8,987,807 102,285 4,036 9,625,730 Revisions (c) (339,878) (6,140) (1,768) (387,320) Price Changes 24,795 17 1 24,904 Extensions and Discoveries (e) 1,055,250 10,324 1,092 1,123,745 Production (540,696) (6,333) (246) (580,169) Balance December 31, 2022 (a) 9,187,278 100,153 3,115 9,806,890 Revisions (d) (698,397) 41,119 (453) (454,409) Price Changes (382,311) (12,733) (1,101) (465,314) Extensions and Discoveries (e) 478,026 16,778 589 582,229 Production (514,668) (7,410) (206) (560,366) Sales of Reserves In-Place (146,936) (3,196) (363) (168,288) Balance December 31, 2023 (a) 7,922,992 134,711 1,581 8,740,742 Proved developed reserves: December 31, 2021 5,569,332 53,204 2,843 5,905,611 December 31, 2022 5,788,814 70,063 2,038 6,221,422 December 31, 2023 5,521,437 83,682 706 6,027,762 Proved undeveloped reserves: December 31, 2021 3,418,475 49,081 1,193 3,720,119 December 31, 2022 3,398,464 30,090 1,077 3,585,468 December 31, 2023 2,401,555 51,029 875 2,712,980 __________ (a) Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods. (b) The downward revisions in 2021 are partly due to changes in our five-year development plan that were driven by acreage consolidation initiatives. These initiatives resulted in 267 Bcfe being removed. Additional downward revisions of 356 Bcfe are due to additional changes in our five-year development plans from continued focus on optimizing and maximizing value of our assets. The remaining 20 Bcfe was removed due to risk in well development. 60 Bcfe was removed due to the five-year rule. Offsetting these negative revisions are positive performance revisions of 46 Bcfe associated with Proved Developed Producing assets and 331 Bcfe related to increase performance in Proved Undeveloped assets. (c) The downward revisions in 2022 are partly due to changes in our five-year development plan that were driven by our continued focus on optimizing the development timing of our assets. These initiatives resulted in 298 Bcfe being removed. Additional downward revisions of 66 Bcfe are primarily the result of the plugging of a Shale well. Additionally, there was a 24 Bcfe reduction as a result of net performance revisions. (d) The downward revisions in 2023 are partly due to changes in our five-year development plan that were driven by development optimization initiatives where wells were shifted into the future. These initiatives resulted in 169 Bcfe being removed. Additional downward revisions of 710 Bcfe are due to the wells not being developed within five years of their original booking. The remaining negative revisions of 43 Bcfe are due to plugging and abandoning of wells due to mining and performance. These are partially offset by positive performance revisions of 467 Bcfe for proved undeveloped assets. The 467 Bcfe contains 146 Bcfe of reserves associated with wells that fell out due to price and were uneconomic, but are in 2023 due to improved performance. (e) Extensions and Discoveries in 2021, 2022, and 2023 are due to the addition of wells on the Company’s Shale acreage more than one offset location away with continued use of reliable technology. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sites and data exchanges to confirm continuity of the formation. Total proved extensions and discoveries are a combination of proved developed and proved undeveloped reserves; and, extensions and discoveries for proven developed reserves are associated with non-operated assets and exploratory wells. In 2023, 2022, and 2021, the Company added 42 Bcfe, 23 Bcfe and 26 Bcfe, respectively, related to exploratory and non-operated wells. For the Year Ended December 31, 2023 Proved Undeveloped Reserves (MMcfe) Beginning Proved Undeveloped Reserves 3,585,468 Undeveloped Reserves Transferred to Developed (a) (819,365) Price Revisions (181,837) Revisions Due to Plan Changes (b) (168,800) Revisions Due to Changes Related to Well Performance (c) 466,730 Revisions Due to 5 Year Rule (709,561) Extension and Discoveries (d) 540,345 Ending Proved Undeveloped Reserves(e) 2,712,980 _________ (a) During 2023, various exploration and development drilling and evaluations were completed. Approximately, $319,475 of capital was spent in the year ended December 31, 2023 related to undeveloped reserves that were transferred to developed. (b) The downward revisions for 2023 plan changes are due to changes in our five-year development plan that are driven by our continued focus on optimizing the development timing of our assets. These initiatives resulted in 169 Bcfe being removed. (c) The upward revisions of 467 Bcfe are from increased production performance related to producing offset locations, leasing activities and performance revisions related to wells that fell out for price, but performance resulted in them being in our 2023 reserves. (d) Extensions and discoveries are due mainly to the addition of 336 Bcfe related to 16 Marcellus wells within our Southwest Pennsylvania and Central Pennsylvania operations and 204 Bcfe related to 9 Utica wells within our Central Pennsylvania and Southwest Pennsylvania operations. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sites and data exchanges to confirm continuity of the formation. (e) Included in proved undeveloped reserves at December 31, 2023 are approximately 290 Bcfe of reserves that have been reported for more than five years. These reserves are all attributable to acreage within the current operating plan identified by the life-of-mine timing maps for the Buchanan mine. These reserves specifically relate to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time, and our GOB forecasts are consistent with the future plans of the Buchanan Mine that was sold in March 2016 to Coronado IV LLC with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons constitute the specific circumstances that exist to continue recognizing these reserves for CNX. The following table indicates the changes to the Company’s suspended exploratory well costs: For the Years Ended December 31, 2023 2022 2021 Balance, Beginning of Period $ — $ — $ 9,062 Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves — — — Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves — — — Capitalized Exploratory Well Costs Charged to Expense — — (9,062) Balance, End of Period $ — $ — $ — During the year-ended December 31, 2021, the Company determined it would be more economical to access the underlying reserves from a different location and the costs associated with this well were recorded to Exploration and Production Related Other Costs in the Consolidated Statements of Income. Standardized Measure of Discounted Future Net Cash Flows: The following information has been prepared in accordance with the provisions of the FASB Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions. The standardized measure is intended to provide a better means for comparing the value of CNX proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities. December 31, 2023 2022 2021 Future Cash Flows (a) Revenues $ 20,281,496 $ 54,713,692 $ 31,838,532 Production Costs (8,515,152) (10,225,451) (8,246,671) Development Costs (b) (1,903,477) (2,233,706) (1,735,784) Income Tax Expense (2,507,151) (10,695,511) (5,838,632) Future Net Cash Flows 7,355,716 31,559,024 16,017,445 Discounted to Present Value at a 10% Annual Rate (4,245,681) (20,796,325) (10,135,869) Total Standardized Measure of Discounted Net Cash Flows $ 3,110,035 $ 10,762,699 $ 5,881,576 _________ (a) For 2023, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2023, adjusted for energy content and a regional price differential. For 2023, this adjusted natural gas price was $2.23 per Mcf, the adjusted oil/condensate price was $65.41 per barrel and the adjusted NGL price was $18.54 per barrel. For 2022, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2022, adjusted for energy content and a regional price differential. For 2022, this adjusted natural gas price was $5.48 per Mcf, the adjusted oil/condensate price was $85.71 per barrel and the adjusted NGL price was $41.05 per barrel. For 2021, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2021, adjusted for energy content and a regional price differential. For 2021, this adjusted natural gas price was $3.19 per Mcf, the adjusted oil/condensate price was $55.72 per barrel and the adjusted NGL price was $28.44 per barrel. (b) Development costs for 2023 include $534,853 of plugging and abandonment costs and $210,322 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $48,538 and $172,885, respectively. Development costs for 2022 include $441,980 of plugging and abandonment costs and $292,937 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,861 and $241,782, respectively. Development costs for 2021 include $405,700 of plugging and abandonment costs and $234,761 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,166 and $197,980, respectively. The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during: December 31, 2023 2022 2021 Balance at Beginning of Period $ 10,762,699 $ 5,881,576 $ 2,635,736 Net Changes in Sales Prices and Production Costs (10,722,238) 6,774,652 5,272,386 Sales Net of Production Costs (992,030) (1,358,052) (1,220,971) Net Change Due to Revisions in Quantity Estimates (155,807) (472,831) (334,660) Net Change Due to Extensions, Discoveries and Improved Recovery 32,876 1,853,496 699,710 Development Costs Incurred During the Period 637,711 526,092 393,641 Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period (149,770) (167,298) (33,175) Changes in Estimated Future Development Costs (211,592) (257,458) 31,406 Net Change in Future Income Taxes 2,647,842 (1,539,146) (1,231,883) Accretion 1,403,417 766,899 329,782 Timing and Other (143,073) (1,245,231) (660,396) Total Discounted Cash Flow at End of Period $ 3,110,035 $ 10,762,699 $ 5,881,576

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2023
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts	CNX RESOURCES CORPORATION AND SUBSIDIARIES Valuation and Qualifying Accounts (Dollars in thousands) Additions Deductions Balance at Release of Balance at Beginning Charged to Valuation Charged to End of Period Expense Allowance Expense of Period Year Ended December 31, 2023 State Operating Loss Carry-Forwards $ 76,871 $ — $ — $ (37,607) $ 39,264 Foreign Tax Credits 7,738 — (7,738) — — Total $ 84,609 $ — $ (7,738) $ (37,607) $ 39,264 Year Ended December 31, 2022 State Operating Loss Carry-Forwards $ 112,298 $ 10,815 $ — $ (46,242) $ 76,871 Charitable Contributions 96 — (96) — — Foreign Tax Credits 39,404 — (31,666) — 7,738 Total $ 151,798 $ 10,815 $ (31,762) $ (46,242) $ 84,609 Year Ended December 31, 2021 State Operating Loss Carry-Forwards $ 79,198 $ 41,300 $ (8,200) $ — $ 112,298 Charitable Contributions 706 — (610) — 96 Foreign Tax Credits 43,194 — (3,790) — 39,404 Total $ 123,098 $ 41,300 $ (12,600) $ — $ 151,798

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 1,720,716	$ (142,077)	$ (498,643)

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	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

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Consolidation	Basis of Consolidation:
Use of Estimates	Use of Estimates:
Cash and Cash Equivalents	Cash and Cash Equivalents:
Trade Accounts Receivable and Allowance for Credit Losses	Trade Accounts Receivable and Allowance for Credit Losses: Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. Management records an allowance for credit losses related to the collectability of third-party customers' receivables using the historical aging of the customer receivable balance. The collectability is determined based on past events, including historical experience, customer credit rating, as well as current market conditions. CNX monitors customer ratings and collectability on an on-going basis. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.
Inventories	Inventories:
Property, Plant and Equipment	Property, Plant and Equipment: CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Depreciation, depletion and amortization expense is calculated based on the actual produced sales volumes multiplied by the applicable rate per unit, which is derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Proved developed reserves, as estimated by petroleum engineers, are used to calculate amortization of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by petroleum engineers, are used to calculate depletion on property acquisitions. Proved oil and natural gas reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates. The Company recorded depreciation, depletion and amortization expense related to proved gas properties using the units-of-production method of $332,596, $359,761, and $415,069 for the years ended December 31, 2023, 2022 and 2021, respectively. Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred. Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and Improvements 10 to 45 Machinery and Equipment 3 to 25 Gathering and Transmission 30 to 40 Leasehold Improvements Life of Lease
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets:
Impairment of Proved and Unproved Properties	Impairment of Proved Properties: CNX performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, tests require that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using significant assumptions including projected revenues, future commodity prices and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions. Impairment of Unproved Properties:
Impairment of Goodwill and Definite-Lived Intangible Assets	Impairment of Goodwill: Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. All goodwill is attributed to the Midstream reporting unit within the Shale segment. Goodwill is not amortized, but rather it is evaluated for impairment annually during the fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. These indicators include, but are not limited to, overall financial performance, industry and market considerations, anticipated future cash flows and discount rates, changes in the stock price with regards to CNX, regulatory and legal developments, and other relevant factors. In connection with the annual evaluation of goodwill for impairment or earlier if an impairment indicator is identified, CNX may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. If after assessing such factors or circumstances, CNX determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. If CNX chooses to bypass the qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then CNX will perform a quantitative assessment. In the case of a quantitative assessment, CNX estimates the fair value of the reporting unit with which the goodwill is associated using level 3 inputs and compares it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. The Company uses a combination of the income approach (generally a discounted cash flow method) and market approach (which may include the guideline public company method and/or the guideline transaction method) to estimate the fair value of a reporting unit. The income approach is used to estimate value based on the present value of future economic benefits that are expected to be produced by an asset or business entity. This approach generally involves two general steps: (i) The first step involves establishing a forecast of the estimated future net cash flows expected to accrue directly or indirectly to the owner of the asset over its remaining useful life or to the owner of the business entity (including a reporting unit). (ii) The second step involves discounting these estimated future net cash flows to their present value using a market rate of return. CNX determines the fair value based on estimated future revenues and earnings before deducting net interest expense (interest expense less interest income) and income taxes (EBITDA - a non-GAAP financial measure), and also includes estimates for capital expenditures, discounted to present value using an industry rate adjusted for company-specific risk, which management feels reflects the overall level of inherent risk of the reporting unit. These assumptions are affected by expectations about future market, industry and economic conditions. Cash flow projections are derived from board approved budgeted amounts and require us to make projections and assumptions for many years into the future for demand, competition and operating costs, among other variables. Subsequent cash flows are developed using growth or contraction rates that management believes are reasonably likely to occur. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from business risks as described in Item 1A. Risk Factors of this Form 10-K. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. Although CNX believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the estimated fair value. Future results could differ from our current estimates and assumptions. For the Company’s annual impairment assessment during the fourth quarter of 2023, the Company elected to perform a qualitative impairment test on its goodwill and concluded that it is more likely than not that the fair value exceeded the carrying value and goodwill was not impaired. Impairment of Definite-Lived Intangible Assets: Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed for impairment when indicators of impairment are present. Other intangible assets are comprised of customer relationships which are amortized on a straight-line basis over approximately 17 years.
Income Taxes	Income Taxes: Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of the Company's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.
Asset Retirement Obligations	Asset Retirement Obligations: CNX accrues the estimated costs to dismantle and remove gas-related facilities upon exhaustion of mineral reserves and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income.
Investment Plan	Investment Plan:
Revenue Recognition	Revenue Recognition: Revenues are recognized when the recognition criteria of Accounting Standards Codification (ASC) 606 are met, which generally occurs at the point in which title passes to the customers. For natural gas, NGL and oil revenue, this occurs at the contractual point of delivery. For revenues generated from natural gas gathering services provided to third parties, this occurs when obligations under the terms of the contract with the shipper are satisfied. CNX sells a portion of its natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within the Consolidated Statements of Income in the Purchased Gas Revenue line. CNX purchases natural gas produced by third parties at market prices less a fee. The gas purchased from third parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Revenue and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX from the third party.
Contingencies	Contingencies: From time to time, CNX, or its subsidiaries, are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
Stock-Based Compensation	Stock-Based Compensation:
Derivative Instruments	Derivative Instruments: CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The changes in fair value of the interest rate swap agreements are accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings. CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. Commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings. None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if CNX's obligations with any of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would be required to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with the counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis, generally measured based upon Level 2 inputs, which is further described in Note 18 – Fair Value of Financial Instruments. Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions. CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.
Recent Accounting Pronouncements	Recent Accounting Pronouncements: In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09 - Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which enhances the transparency and decision usefulness of income tax disclosures. The amendments address more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The ASU also includes certain other amendments to improve the effectiveness of income tax disclosures. The amendments in this ASU are effective for public business entities for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of this guidance. In November 2023, the FASB issued ASU 2023-07 - Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is still evaluating the effect of the adoption of this guidance. See Note 12 – Long-Term Debt for the impact of adoption of ASU 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity.
Reclassifications	Reclassifications: Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2023, with no effect on previously reported net income, stockholders' equity or statement of cash flows.
Subsequent Events	Subsequent Events:

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Allowance for Credit Loss	The following represents activity related to the allowance for credit losses for the years ended: December 31, 2023 2022 Allowance for Credit Losses - Trade, Beginning of Year $ 84 $ 84 Provision for Expected Credit Losses — — Allowance for Credit Losses - Trade, End of Period $ 84 $ 84 Allowance for Credit Losses - Other Receivables, Beginning of Year $ 2,937 $ 3,322 Provision for Expected Credit Losses 32 (198) Write-off of Uncollectible Accounts (122) (187) Allowance for Credit Losses - Other Receivables, End of Period $ 2,847 $ 2,937
Schedule of Property, Plant and Equipment, Useful Lives	Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and Improvements 10 to 45 Machinery and Equipment 3 to 25 Gathering and Transmission 30 to 40 Leasehold Improvements Life of Lease December 31, 2023 2022 Intangible Drilling Cost $ 5,902,498 $ 5,554,021 Gas Gathering Equipment 2,631,110 2,542,587 Gas Wells and Related Equipment 1,513,945 1,342,719 Proved Gas Properties 1,374,685 1,345,114 Unproved Gas Properties 724,401 734,890 Surface Land and Other Equipment 187,316 193,153 Other 203,163 195,214 Total Property, Plant and Equipment 12,537,118 11,907,698 Less: Accumulated Depreciation, Depletion and Amortization 5,194,485 4,811,189 Total Property, Plant and Equipment - Net $ 7,342,633 $ 7,096,509

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive: For the Years Ended December 31, 2023 2022 2021 Anti-Dilutive Options 21,650 2,262,845 2,990,094 Anti-Dilutive Restricted Stock Units 25,156 2,350,661 2,436,846 Anti-Dilutive Performance Share Units — 1,829,081 996,863 46,806 6,442,587 6,423,803
Schedule of Earnings Per Share, Basic and Diluted	The computations for basic and diluted loss per share are as follows: For the Years Ended December 31, 2023 2022 2021 Net Income (Loss) $ 1,720,716 $ (142,077) $ (498,643) Basic Earnings (Loss) Available to Shareholders $ 1,720,716 $ (142,077) $ (498,643) Effect of Dilutive Securities: Add Back Interest on Convertible Notes (Net of Tax) 5,758 — — Diluted Earnings (Loss) Available to Shareholders $ 1,726,474 $ (142,077) $ (498,643) Weighted-Average Shares of Common Stock Outstanding 162,490,245 189,507,682 215,971,381 Effect of Diluted Shares:* Options 1,168,526 — — Restricted Stock Units 1,349,299 — — Performance Share Units 1,254,050 — — Convertible Notes 25,751,869 — — Weighted-Average Diluted Shares of Common Stock Outstanding 192,013,989 189,507,682 215,971,381 Earnings (Loss) Per Share: Basic $ 10.59 $ (0.75) $ (2.31) Diluted $ 8.99 $ (0.75) $ (2.31) *During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards and the potential share settlement impact related to CNX’s Convertible Notes are antidilutive.
Schedule of Shares of Common Stock Outstanding	Shares of common stock outstanding were as follows: For the Years Ended December 31, 2023 2022 2021 Balance, Beginning of Year 170,841,164 203,531,320 220,440,993 Issuance Related to Stock-Based Compensation (1) 1,106,240 836,070 1,374,925 Retirement of Common Stock (2) (17,564,524) (33,526,226) (18,284,598) Balance, End of Year 154,382,880 170,841,164 203,531,320 (1) See Note 15 – Stock-Based Compensation for additional information. (2) See Note 5 – Stock Repurchase for additional information.

Revenue From Contracts With C_2

Revenue From Contracts With Customers (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table is a disaggregation of revenue by major source: For the Years Ended December 31, 2023 2022 2021 Revenue from Contracts with Customers: Natural Gas Revenue $ 1,131,068 $ 3,390,422 $ 1,958,718 NGL Revenue 157,573 241,535 202,670 Oil/Condensate Revenue 13,577 20,155 22,541 Total Natural Gas, NGL and Oil Revenue 1,302,218 3,652,112 2,183,929 Purchased Gas Revenue 74,218 185,552 99,713 Other Sources of Revenue and Other Operating Income: Gain (Loss) on Commodity Derivative Instruments 1,928,652 (2,663,775) (1,632,733) Other Revenue and Operating Income 129,860 87,322 105,883 Total Revenue and Other Operating Income $ 3,434,948 $ 1,261,211 $ 756,792

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Income tax expense (benefit) provided on earnings consisted of: For the Years Ended December 31, 2023 2022 2021 Current: U.S. Federal $ — $ — $ — U.S. State 4,777 6,188 17 4,777 6,188 17 Deferred: U.S. Federal 455,224 (40,649) (157,626) U.S. State 42,208 (35,409) 19,739 497,432 (76,058) (137,887) Total Income Tax Expense (Benefit) $ 502,209 $ (69,870) $ (137,870)
Schedule of Deferred Tax Assets and Liabilities	The components of the net deferred taxes are as follows: December 31, 2023 2022 Deferred Tax Assets: Net Operating Loss- Federal $ 160,405 $ 187,154 Section 174 Expenses 92,414 26,397 Net Operating Loss - State 76,259 82,189 Federal Tax Credits 45,619 34,317 Interest Limitation 36,451 14,618 Operating Lease Liabilities 36,297 45,427 Gas Well Closing 24,652 25,045 State Deferred Tax Adjustment 15,983 — Gas Derivatives 14,466 461,952 Salary Retirement 8,488 8,167 Equity Compensation 5,419 4,474 Convertible Note Amortization 3,628 5,080 Foreign Tax Credit — 7,738 Other 6,089 8,396 Total Deferred Tax Assets 526,170 910,954 Valuation Allowance (39,264) (84,609) Net Deferred Tax Assets 486,906 826,345 Deferred Tax Liabilities: Property, Plant and Equipment (1,177,773) (850,095) Operating Lease Right-of-Use Assets (35,321) (44,238) Investment in Partnerships (2,303) (163,483) Advance Gas Royalties (404) (286) Other (559) (523) Total Deferred Tax Liabilities (1,216,360) (1,058,625) Net Deferred Tax Liability $ (729,454) $ (232,280)
Schedule of Effective Income Tax Rate Reconciliation	The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to CNX's effective tax rate: For the Years Ended December 31, 2023 2022 2021 Amount Percent Amount Percent Amount Percent Statutory U.S. Federal Income Tax Rate $ 466,814 21.0 % $ (44,509) 21.0 % $ (133,668) 21.0 % Net Effect of State Income Taxes 83,379 3.8 (5,817) 2.8 (36,300) 5.7 Uncertain Tax Positions 17,673 0.8 14,440 (6.8) 35,914 (5.6) Effect of Equity Compensation 1,036 — 2,254 (1.1) 2,465 (0.4) Effect of Change in Valuation Allowance (37,607) (1.7) (35,427) 16.7 28,704 (4.5) Deferred Adjustments (837) — 2,481 (1.2) (4,408) 0.7 Effect of State Rate Changes 297 — 10,025 (4.7) 22,458 (3.5) Effect of Federal Tax Credits (28,974) (1.3) (15,723) 7.4 (53,269) 8.3 Other 428 — 2,406 (1.1) 234 — Income Tax Expense (Benefit) / Effective Rate $ 502,209 22.6 % $ (69,870) 33.0 % $ (137,870) 21.7 %
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows: For the Years Ended December 31, 2023 2022 Balance at Beginning of Period $ 82,245 $ 67,805 Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Current Period 11,229 — Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Prior Periods 6,444 14,440 Balance at End of Period $ 99,918 $ 82,245

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation [Abstract]
Schedule of Change in Asset Retirement Obligation	The reconciliation of changes in asset retirement obligations is as follows: December 31, 2023 2022 Balance, Beginning of Year $ 98,814 $ 96,013 Obligations Divested (2,263) (251) Accretion Expense 9,025 7,982 Obligations Incurred 1,846 1,336 Obligations Settled (12,070) (7,360) Revisions in Estimated Cash Flows 17,860 1,094 Balance, End of Year $ 113,212 $ 98,814

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and Improvements 10 to 45 Machinery and Equipment 3 to 25 Gathering and Transmission 30 to 40 Leasehold Improvements Life of Lease December 31, 2023 2022 Intangible Drilling Cost $ 5,902,498 $ 5,554,021 Gas Gathering Equipment 2,631,110 2,542,587 Gas Wells and Related Equipment 1,513,945 1,342,719 Proved Gas Properties 1,374,685 1,345,114 Unproved Gas Properties 724,401 734,890 Surface Land and Other Equipment 187,316 193,153 Other 203,163 195,214 Total Property, Plant and Equipment 12,537,118 11,907,698 Less: Accumulated Depreciation, Depletion and Amortization 5,194,485 4,811,189 Total Property, Plant and Equipment - Net $ 7,342,633 $ 7,096,509
Schedule of Amortization Expense Per Unit of Production	December 31, 2023 2022 Unproved Gas Properties $ 724,401 $ 734,890 Advance Royalties 1,597 1,130 Total $ 725,998 $ 736,020

Goodwill and Other Intangible_2

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets	The carrying amount and accumulated amortization of other intangible assets consist of the following: December 31, 2023 2022 Other Intangible Assets: Gross Amortizable Asset - Customer Relationships $ 109,752 $ 109,752 Less: Accumulated Amortization - Customer Relationships 39,314 32,762 Total Other Intangible Assets, net $ 70,438 $ 76,990

Other Accrued Liabilities (Tabl

Other Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Schedule of Accrued Liabilities	December 31, 2023 2022 Royalties $ 100,847 $ 144,482 Accrued Interest 44,227 36,744 Transportation Charges 17,824 12,808 Deferred Revenue 15,831 22,095 Short-Term Incentive Compensation 10,961 18,956 Accrued Other Taxes 9,343 14,067 Accrued Payroll & Benefits 6,619 6,318 Purchased Gas Payable 1,002 5,266 Other 16,777 18,142 Current Portion of Long-Term Liabilities: Asset Retirement Obligations 7,897 9,735 Salary Retirement 1,886 1,878 Total Other Accrued Liabilities $ 233,214 $ 290,491

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	December 31, 2023 2022 Senior Notes due January 2029 at 6.00%, Issued at Par Value $ 500,000 $ 500,000 Senior Notes due January 2031 at 7.375% (Principal of $500,000 less Unamortized Discount of $5,308 and $6,061, respectively) 494,692 493,939 CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $3,654 and $4,231, respectively)* 396,346 395,769 Senior Notes due March 2027 at 7.25% (Principal of $350,000 plus Unamortized Premium of $1,728 and $2,266 , respectively) 351,728 352,266 Convertible Senior Notes due May 2026 at 2.25% (Principal of $330,654 less Unamortized Discount and Issuance Costs of $4,586 and $6,460, respectively) 326,068 324,194 CNX Midstream Partners LP Revolving Credit Facility* 105,150 153,700 CNX Revolving Credit Facility 52,050 — Less: Unamortized Debt Issuance Costs 11,660 14,133 $ 2,214,374 $ 2,205,735 Less: Current Portion 325,668 — Long-Term Debt $ 1,888,706 $ 2,205,735 *CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or CNXM's Credit Facility.
Schedule of Maturities of Long-Term Debt	At December 31, 2023, annual undiscounted maturities of CNX and CNXM long-term debt during the next five years and thereafter are as follows: Year ended December 31, Amount 2024 $ — 2025 — 2026 487,854 2027 350,000 2028 — Thereafter 1,400,000 Total Long-Term Debt Maturities $ 2,237,854
Convertible Debt	The net carrying amount of the liability and equity components of the Convertible Notes was as follows: December 31, 2023 2022 Liability Component: Principal $ 330,654 $ 330,654 Unamortized Issuance Costs $ (4,586) $ (6,460) Net Carrying Amount $ 326,068 $ 324,194 Fair Value $ 537,465 $ 483,581 Fair Value Hierarchy Level 2 Level 2 Interest expense related to the Convertible Notes is as follows: For the Years Ended December 31, 2023 2022 Contractual Interest Expense $ 7,440 $ 7,577 Amortization of Issuance Costs 1,873 1,871 Total Interest Expense 9,313 9,448

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Schedule of Lease Cost	The components of lease cost were as follows: For the Years Ended December 31, 2023 2022 2021 Operating Lease Cost $ 63,087 $ 56,725 $ 60,364 Finance Lease Cost: Amortization of Right-of-Use Assets 1,628 665 1,577 Interest on Lease Liabilities 429 78 123 Short-term Lease Cost 2,357 7,784 8,589 Variable Lease Cost* 12,401 9,271 7,100 Total Lease Cost $ 79,902 $ 74,523 $ 77,753 *Amounts recognized in the Consolidated Balance Sheets for natural gas drilling rigs are measured using the rates that would be paid if the rigs were idle, as this represents the minimum payment that could be made under the contract. Variable lease cost represents amounts paid for natural gas drilling rigs above this minimum when the rigs are in use. Amounts recognized in the Consolidated Balance Sheets for electric fracturing equipment are measured using minimum pumping hours under the contract; however, pumping hours may exceed the minimum and vary period to period. Any such amounts paid related to pumping hours in excess of the minimum represent variable lease cost. Lease terms and discount rates are as follows: For the Years Ended December 31, 2023 2022 2021 Weighted Average Remaining Lease Term (years): Operating Leases 3.59 4.41 6.20 Finance Leases 4.08 4.01 3.56 Weighted Average Discount Rate: Operating Leases 4.84 % 4.65 % 4.84 % Finance Leases 7.35 % 6.17 % 1.72 %
Schedule of Balance Sheet Information	Amounts recognized in the Consolidated Balance Sheets are as follows: December 31, 2023 2022 Operating Leases: Operating Lease Right-of-Use Assets $ 139,466 $ 174,849 Current Portion of Operating Lease Obligations $ 53,791 $ 47,436 Operating Lease Obligations 89,531 132,105 Total Operating Lease Liabilities $ 143,322 $ 179,541 Finance Leases: Property, Plant and Equipment $ 10,864 $ 6,777 Less—Accumulated Depreciation, Depletion and Amortization 3,502 3,926 Property, Plant and Equipment—Net $ 7,362 $ 2,851 Current Portion of Finance Lease Obligations $ 1,862 $ 881 Finance Lease Obligations 5,500 1,970 Total Finance Lease Liabilities $ 7,362 $ 2,851 Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, 2023 2022 2021 Cash Paid for Amounts Included in the Measurement of Lease Liabilities: Operating Cash Flows for Operating Leases $ 64,139 $ 55,729 $ 56,966 Operating Cash Flows for Finance Leases $ 429 $ 78 $ 123 Financing Cash Flows for Finance Leases $ 1,627 $ 665 $ 2,785 Right-of-Use Assets Obtained in Exchange for Lease Obligations: Operating Leases $ 19,477 $ 36,758 $ 4,010 Finance Leases $ 6,178 $ 1,742 $ 772
Maturity of Lease Liability, Operating	Maturities of lease liabilities are as follows: Operating Finance Leases Leases Year Ended December 31, 2024 $ 59,430 $ 2,401 2025 50,373 2,347 2026 19,372 2,278 2027 6,048 1,963 2028 6,109 598 Thereafter 15,422 30 Total Lease Payments 156,754 9,617 Less: Interest 13,432 2,255 Present Value of Lease Liabilities $ 143,322 $ 7,362
Maturity of Lease Liability, Financing	Maturities of lease liabilities are as follows: Operating Finance Leases Leases Year Ended December 31, 2024 $ 59,430 $ 2,401 2025 50,373 2,347 2026 19,372 2,278 2027 6,048 1,963 2028 6,109 598 Thereafter 15,422 30 Total Lease Payments 156,754 9,617 Less: Interest 13,432 2,255 Present Value of Lease Liabilities $ 143,322 $ 7,362

Pension (Tables)

Pension (Tables)	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Schedule of Changes in Accumulated Postemployment Benefit Obligations	The reconciliation of changes in the benefit obligation, plan assets and funded status of the pension benefits is as follows: December 31, 2023 2022 Change in Benefit Obligation: Benefit Obligation at Beginning of Period $ 32,223 $ 42,990 Interest Cost 1,675 1,035 Actuarial Loss (Gain) 1,442 (10,006) Benefits and Other Payments (1,799) (1,796) Benefit Obligation at End of Period $ 33,541 $ 32,223 Change in Plan Assets: Fair Value of Plan Assets at Beginning of Period $ — $ — Company Contributions 1,799 1,796 Benefits and Other Payments (1,799) (1,796) Fair Value of Plan Assets at End of Period $ — $ — Funded Status: Current Liabilities $ (1,886) $ (1,878) Noncurrent Liabilities (31,655) (30,345) Net Obligation Recognized $ (33,541) $ (32,223) Amounts Recognized in Accumulated Other Comprehensive Loss Consist of: Net Actuarial Loss $ 9,153 $ 7,884 Prior Service Cost 842 1,063 Total 9,995 8,947 Less: Tax Benefit 2,694 2,434 Net Amount Recognized $ 7,301 $ 6,513
Schedule of Defined Benefit Plans Disclosures	The components of the net periodic benefit cost are as follows: For the Years Ended December 31, 2023 2022 2021 Components of Net Periodic Benefit Cost: Interest Cost 1,675 1,035 855 Amortization of Prior Service Cost 222 221 222 Recognized Net Actuarial Loss 173 510 513 Net Periodic Benefit Cost $ 2,070 $ 1,766 $ 1,590
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	The following table provides information related to the pension plan with an accumulated benefit obligation in excess of plan assets: As of December 31, 2023 2022 Projected Benefit Obligation $ 33,541 $ 32,223 Accumulated Benefit Obligation $ 33,541 $ 32,223 Fair Value of Plan Assets $ — $ —
Schedule of Assumptions Used	The weighted-average assumptions used to determine benefit obligations are as follows: As of December 31, 2023 2022 Discount Rate 5.15 % 5.43 % Rate of Compensation Increase — % — % Interest Credited Rate 4.74 % 4.43 % The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans. The increase in discount rate during 2022 compared to the prior year caused a significant actuarial gain during the year ended December 31, 2022. The weighted-average assumptions used to determine net periodic benefit cost are as follows: For the Years ended December 31, 2023 2022 2021 Discount Rate 5.43 % 2.84 % 2.47 % Rate of Compensation Increase — % — % — % Interest Credited Rate 4.81 % 4.07 % 2.71 %
Schedule of Expected Benefit Payments	The following benefit payments, which reflect expected future service, are expected to be paid: Pension Year ended December 31, Benefits 2024 $ 1,886 2025 $ 1,983 2026 $ 2,053 2027 $ 2,143 2028 $ 2,236 Year 2029-2033 $ 13,057

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Share-based Payment Award, Options Granted, Assumptions and Weighted Average Fair Value	There were no options granted during the year ended December 31, 2021. December 31, 2023 2022 Weighted Average Fair Value of Grants $ 7.06 $ 10.60 Risk-free Interest Rate 3.24 % 3.02 % Expected Dividend Yield — % — % Expected Forfeiture Rate — % — % Expected Volatility 48.70 % 54.00 % Expected Term in Years 5.50 5.5
Share-based Compensation, Stock and Performance Options Rollforward	A summary of the status of stock options granted is presented below: Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic Exercise Term (in Value (in Shares Price years) thousands) Outstanding at December 31, 2022 2,262,845 $ 8.55 Granted 16,289 $ 14.63 Exercised (193,264) $ 9.10 Outstanding at December 31, 2023 2,085,870 $ 8.55 2.72 $ 23,890 Exercisable at December 31, 2023 2,069,581 $ 8.50 2.67 $ 23,802
Schedule of Nonvested Restricted Stock Units Activity	The following table represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2022 1,833,920 $12.69 Granted 999,465 $16.20 Vested (1,031,200) $11.95 Forfeited (205,645) $14.51 Nonvested at December 31, 2023 1,596,540 $15.14
Schedule of Nonvested Performance-based Units Activity	The following table represents the nonvested performance share units and their corresponding fair value (based upon the Monte Carlo Methodology for market-based awards and the stock price on the date of grant for performance based awards) on the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2022 2,293,678 $10.53 Granted 1,687,329 $10.89 Vested (576,421) $7.92 Forfeited (605,868) $12.93 Nonvested at December 31, 2023 2,798,718 $10.77

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2023
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table shows cash paid (received): For the Years Ended December 31, 2023 2022 2021 Interest (Net of Amounts Capitalized) $ 122,279 $ 126,643 $ 123,466 Income Taxes $ 7,329 $ — $ —

Concentration of Credit Risk _2

Concentration of Credit Risk and Major Customers - (Tables)	12 Months Ended
	Dec. 31, 2023
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk, by Risk Factor	Concentration of credit risk is summarized below: December 31, 2023 2022 Gas Wholesalers $ 99,493 $ 304,842 NGL, Condensate & Processing Facilities 12,005 26,382 Other 4,705 17,318 Allowance for Credit Losses (84) (84) Total Accounts Receivable Trade $ 116,119 $ 348,458

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value, Assets Measured on Recurring Basis	The financial instrument measured at fair value on a recurring basis is summarized below: Fair Value Measurements at December 31, 2023 Fair Value Measurements at December 31, 2022 Description Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity Derivatives $ — $ (55,701) * $ — $ — $ (1,904,830) ** $ — Interest Rate Swaps $ — $ 1,099 $ — $ — $ 4,561 $ — *Includes $6,741 of derivatives that have been settled but not received and $900 that have been settled but not paid. **Includes $77,662 of gas derivatives that have been settled but not paid
Fair Value, by Balance Sheet Grouping	The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows: December 31, 2023 December 31, 2022 Carrying Fair Carrying Fair Cash and Cash Equivalents $ 443 $ 443 $ 21,321 $ 21,321 Long-Term Debt (Excluding Debt Issuance Costs)* $ 2,226,034 $ 2,376,594 $ 2,219,868 $ 2,240,919

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	The total notional amounts of CNX's derivative instruments were as follows: December 31, Forecasted to 2023 2022 Settle Through Natural Gas Commodity Swaps (Bcf) 1,349.2 1,607.9 2027 Natural Gas Basis Swaps (Bcf) 760.3 1,023.7 2027 Propane Commodity Swaps (Mbbls) 81.0 $ — 2024 Interest Rate Swaps $ 410,000 $ 410,000 2024
Schedule of Derivative Liabilities at Fair Value	The gross fair value of CNX's derivative instruments was as follows: December 31, 2023 2022 Current Assets: Commodity Derivative Instruments: Commodity Swaps $ 168,532 $ 21,759 Propane Swaps 1,003 — Basis Only Swaps 77,540 118,115 Interest Rate Swaps 5,449 14,600 Total Current Assets $ 252,524 $ 154,474 Other Non-Current Assets: Commodity Derivative Instruments: Commodity Swaps $ 166,701 $ 42,786 Basis Only Swaps 113,829 197,280 Interest Rate Swaps — 4,865 Total Other Non-Current Assets $ 280,530 $ 244,931 Current Liabilities: Commodity Derivative Instruments: Commodity Swaps $ 47,279 $ 732,717 Basis Only Swaps 9,473 38,559 Interest Rate Swaps 4,350 11,377 Total Current Liabilities $ 61,102 $ 782,653 Non-Current Liabilities: Commodity Derivative Instruments: Commodity Swaps $ 484,357 $ 1,466,124 Basis Only Swaps 42,197 47,370 Interest Rate Swaps — 3,527 Total Non-Current Liabilities $ 526,554 $ 1,517,021
Schedule of Derivative Assets at Fair Value	The gross fair value of CNX's derivative instruments was as follows: December 31, 2023 2022 Current Assets: Commodity Derivative Instruments: Commodity Swaps $ 168,532 $ 21,759 Propane Swaps 1,003 — Basis Only Swaps 77,540 118,115 Interest Rate Swaps 5,449 14,600 Total Current Assets $ 252,524 $ 154,474 Other Non-Current Assets: Commodity Derivative Instruments: Commodity Swaps $ 166,701 $ 42,786 Basis Only Swaps 113,829 197,280 Interest Rate Swaps — 4,865 Total Other Non-Current Assets $ 280,530 $ 244,931 Current Liabilities: Commodity Derivative Instruments: Commodity Swaps $ 47,279 $ 732,717 Basis Only Swaps 9,473 38,559 Interest Rate Swaps 4,350 11,377 Total Current Liabilities $ 61,102 $ 782,653 Non-Current Liabilities: Commodity Derivative Instruments: Commodity Swaps $ 484,357 $ 1,466,124 Basis Only Swaps 42,197 47,370 Interest Rate Swaps — 3,527 Total Non-Current Liabilities $ 526,554 $ 1,517,021
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows: For the Years Ended December 31, 2023 2022 2021 Realized Gain (Loss) on Commodity Derivative Instruments: Natural Gas Commodity Swaps $ 62,567 $ (1,971,287) $ (596,619) Natural Gas Basis Swaps 98,582 158,510 57,603 Propane Swaps 1,877 — — Total Realized Gain (Loss) on Commodity Derivative Instruments 163,026 * (1,812,777) ** (539,016) Unrealized Gain (Loss) on Commodity Derivative Instruments: Natural Gas Commodity Swaps 1,858,060 (922,424) (1,240,827) Natural Gas Basis Swaps (93,222) 71,426 147,110 Propane Swaps 788 — — Total Unrealized Gain (Loss) on Commodity Derivative Instruments 1,765,626 (850,998) (1,093,717) Gain (Loss) on Commodity Derivative Instruments: Natural Gas Commodity Swaps 1,920,627 (2,893,711) (1,837,446) Natural Gas Basis Swaps 5,360 229,936 204,713 Propane Swaps 2,665 — — Total Gain (Loss) on Commodity Derivative Instruments $ 1,928,652 $ (2,663,775) $ (1,632,733) * Includes $6,741 of derivatives that have been settled but not received and $900 that have been settled but not paid at December 31, 2023, and excludes $77,662 of gas derivatives that were settled but not paid at December 31, 2022. ** Includes $77,662 of gas derivatives that were settled but not paid at December 31, 2022. The effect of interest rate swaps on Interest Expense in the Company's Consolidated Statements of Income was as follows: For the Years Ended December 31, 2023 2022 2021 Cash Received (Paid) in Settlement of Interest Rate Swaps $ 4,207 $ (1,572) $ (5,574) Unrealized (Loss) Gain on Interest Rate Swaps (3,463) 10,348 8,485 Gain on Interest Rate Swaps $ 744 $ 8,776 $ 2,911

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Long-term Purchase Commitment	At December 31, 2023, CNX has provided the following financial guarantees, unconditional purchase obligations, and letters of credit to certain third parties as described by major category in the following tables. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management believes that the commitments in the following table will expire without being funded, and therefore will not have a material adverse effect on CNX’s financial condition. Amount of Commitment Expiration Per Period Total Less Than 1-3 Years 3-5 Years Beyond Letters of Credit: Firm Transportation $ 40,331 $ 40,331 $ — $ — $ — Other 3,353 3,353 — — — Total Letters of Credit 43,684 43,684 — — — Surety Bonds: Employee-Related 2,250 2,250 — — — Environmental 11,449 11,449 — — — Firm Transportation 126,336 126,336 — — — Financial Guarantees 72,720 72,720 — — — Other 8,682 8,682 — — — Total Surety Bonds 221,437 221,437 — — — Total Commitments $ 265,121 $ 265,121 $ — $ — $ —
Unrecorded Unconditional Purchase Obligations Disclosure	CNX enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded in the Consolidated Balance Sheets. As of December 31, 2023, the purchase obligations for each of the next five years and beyond are as follows: Obligations Due Amount Less than 1 year $ 247,586 1 - 3 years 446,255 3 - 5 years 373,180 More than 5 years 581,370 Total Purchase Obligations $ 1,648,391

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Industry segment results for the year ended December 31, 2023 are: Shale Coalbed Other Consolidated Natural Gas, NGLs and Oil Revenue $ 1,170,393 $ 130,763 $ 1,062 $ 1,302,218 (A) Purchased Gas Revenue — — 74,218 74,218 Gain on Commodity Derivative Instruments 151,408 11,554 1,765,690 1,928,652 Other Revenue and Operating Income 66,559 — 63,301 129,860 (B) Total Revenue and Other Operating Income $ 1,388,360 $ 142,317 $ 1,904,271 $ 3,434,948 Total Operating Expense $ 746,050 $ 141,708 $ 304,351 $ 1,192,109 Earnings Before Income Tax $ 642,310 $ 609 $ 1,580,006 $ 2,222,925 Segment Assets $ 6,656,655 $ 948,795 $ 1,021,207 $ 8,626,657 (C) Depreciation, Depletion and Amortization $ 365,020 $ 50,052 $ 18,514 $ 433,586 Capital Expenditures $ 629,631 $ 36,804 $ 12,969 $ 679,404 (A) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $180,039 to Citadel Energy Marketing LLC and $165,465 to NRG Business Marketing LLC (formerly Direct Energy Business Marketing LLC), each of which comprises over 10% of revenue from contracts with external customers for the period. (B) Includes midstream revenue of $66,559 and equity in earnings of unconsolidated affiliates of $2,942 for Shale and Other, respectively. Other also includes sales of environmental attributes of $40,685. (C) Includes investments in unconsolidated equity affiliates of $13,682. Industry segment results for the year ended December 31, 2022 are: Shale Coalbed Other Consolidated Natural Gas, NGLs and Oil Revenue $ 3,334,677 $ 314,695 $ 2,740 $ 3,652,112 (D) Purchased Gas Revenue — — 185,552 185,552 Loss on Commodity Derivative Instruments (1,672,974) (139,131) (851,670) (2,663,775) Other Revenue and Operating Income 69,618 — 17,704 87,322 (E) Total Revenue and Other Operating Income (Loss) $ 1,731,321 $ 175,564 $ (645,674) $ 1,261,211 Total Operating Expense $ 790,960 $ 131,426 $ 399,255 $ 1,321,641 Earnings (Loss) Before Income Tax $ 940,361 $ 44,138 $ (1,196,446) $ (211,947) Segment Assets $ 6,452,075 $ 959,126 $ 1,104,572 $ 8,515,773 (F) Depreciation, Depletion and Amortization $ 388,641 $ 53,201 $ 19,373 $ 461,215 Capital Expenditures $ 544,914 $ 15,043 $ 5,797 $ 565,754 (D) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $453,501 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period. (E) Includes midstream revenue of $69,618 and equity in earnings of unconsolidated affiliates of $1,412 for Shale and Other, respectively. (F) Includes investments in unconsolidated equity affiliates of $11,714. Industry segment results for the year ended December 31, 2021 are: Shale Coalbed Other Consolidated Natural Gas, NGLs and Oil Revenue $ 1,988,993 $ 193,578 $ 1,358 $ 2,183,929 (G) Purchased Gas Revenue — — 99,713 99,713 Loss on Commodity Derivative Instruments (492,526) (46,304) (1,093,903) (1,632,733) Other Revenue and Operating Income 81,267 — 24,616 105,883 (H) Total Revenue and Other Operating Income (Loss) $ 1,577,734 $ 147,274 $ (968,216) $ 756,792 Total Operating Expense $ 804,004 $ 117,900 $ 312,970 $ 1,234,874 Earnings (Loss) Before Income Tax $ 773,730 $ 29,374 $ (1,439,617) $ (636,513) Segment Assets $ 6,071,495 $ 1,047,851 $ 981,405 $ 8,100,751 (I) Depreciation, Depletion and Amortization $ 440,024 $ 58,602 $ 16,492 $ 515,118 Capital Expenditures $ 453,603 $ 10,880 $ 1,378 $ 465,861 (G) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $334,407 to Citadel Energy Marketing LLC and $235,760 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period. (H) Includes midstream revenue of $81,267 and equity in earnings of unconsolidated affiliates of $5,780 for Shale and Other, respectively. (I) Includes investments in unconsolidated equity affiliates of $17,301.
Reconciliation of Revenue from Segments to Consolidated	Revenue and Other Operating Income: For the Years Ended December 31, 2023 2022 2021 Total Segment Revenue from Contracts with External Customers $ 1,442,995 $ 3,907,282 $ 2,364,909 Gain (Loss) on Commodity Derivative Instruments 1,928,652 (2,663,775) (1,632,733) Other Operating Income 63,301 17,704 24,616 Total Consolidated Revenue and Other Operating Income $ 3,434,948 $ 1,261,211 $ 756,792

Supplemental Gas Data (unaudi_2

Supplemental Gas Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	Capitalized Costs: As of December 31, 2023 2022 Intangible Drilling Costs $ 5,902,498 $ 5,554,021 Gas Gathering Assets 2,631,110 2,542,587 Proved Gas Properties 1,374,685 1,345,114 Unproved Gas Properties 724,401 734,890 Gas Wells and Related Equipment 1,513,945 1,342,719 Other Gas Assets 119,163 99,457 Total Property, Plant and Equipment 12,265,802 11,618,788 Accumulated Depreciation, Depletion and Amortization (5,110,938) (4,710,684) Net Capitalized Costs $ 7,154,864 $ 6,908,104
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	Costs incurred for property acquisition, exploration and development (*): For the Years Ended December 31, 2023 2022 2021 Property Acquisitions: Proved Properties $ 2,319 $ 19,766 $ 32,355 Unproved Properties 26,405 14,802 20,568 Development** 637,711 526,092 393,641 Exploration 4,257 6,806 30,927 Total $ 670,692 $ 567,466 $ 477,491 __________ (*) Includes costs incurred whether capitalized or expensed. (**) Includes development costs for midstream of $47 million, $38 million and $35 million for 2023, 2022 and 2021, respectively.
Results of Operations for Oil and Gas Producing Activities Disclosure	Results of Operations for Producing Activities: For the Years Ended December 31, 2023 2022 2021 Natural Gas, NGLs and Oil Revenue $ 1,302,218 $ 3,652,112 $ 2,183,929 Realized Gain (Loss) on Commodity Derivative Instruments 163,026 (1,812,777) (539,016) Unrealized Gain (Loss) on Commodity Derivative Instruments 1,765,626 (850,998) (1,093,717) Purchased Gas Revenue 74,218 185,552 99,713 Total Revenue 3,305,088 1,173,889 650,909 Lease Operating Expense 63,333 66,658 46,256 Production, Ad Valorem and Other Fees 27,946 44,965 34,051 Transportation, Gathering and Compression 381,934 369,660 343,635 Purchased Gas Costs 69,924 185,383 93,776 Exploration Costs 10,447 8,298 20,626 Depreciation, Depletion and Amortization 433,586 461,215 515,118 Total Costs 987,170 1,136,179 1,053,462 Pre-tax Operating Income (Loss) 2,317,918 37,710 (402,553) Income Tax Expense (Benefit) 523,849 12,444 (87,354) Results of Operations for Producing Activities excluding Corporate and Interest Costs $ 1,794,069 $ 25,266 $ (315,199)
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production: For the Years Ended December 31, 2023 2022 2021 Production (MMcfe) 560,366 580,169 590,248 Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe) $ 2.32 $ 6.29 $ 3.70 Average Effects of Commodity Derivative Financial Settlements (per Mcfe) $ 0.32 $ (3.35) $ (0.98) Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe) $ 2.61 $ 3.17 $ 2.79 Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe) $ 0.11 $ 0.11 $ 0.08
Schedule of Gas and Oil Acreage	The following table sets forth, at December 31, 2023, the number of producing wells, developed acreage and undeveloped acreage: Gross(1) Net(2) Producing Gas Wells (including Gob Wells) - Working Interest 4,499 4,425 Producing Oil Wells - Working Interest 2 — Producing Gas Wells - Royalty Interest 320 — Producing Oil Wells - Royalty Interest 126 — Acreage Position: Proved Developed Acreage 385,087 385,087 Proved Undeveloped Acreage 40,811 40,811 Unproved Acreage 4,704,922 3,392,132 Total Acreage 5,130,820 3,818,030 ____________ (1) All of our acreage identified as proved developed and undeveloped is controlled fully by CNX through ownership of a 100% working interest.
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The oil and gas reserves estimates are as follows: Condensate Consolidated Natural Gas NGLs & Crude Oil Operations (MMcf) (Mbbls) (Mbbls) (MMcfe) Balance December 31, 2020 (a) 9,034,066 81,867 4,081 9,549,758 Revisions (b) (409,215) 13,655 39 (327,050) Price Changes 82,248 692 22 86,532 Extensions and Discoveries (e) 832,696 12,047 294 906,738 Production (551,988) (5,976) (400) (590,248) Balance December 31, 2021 (a) 8,987,807 102,285 4,036 9,625,730 Revisions (c) (339,878) (6,140) (1,768) (387,320) Price Changes 24,795 17 1 24,904 Extensions and Discoveries (e) 1,055,250 10,324 1,092 1,123,745 Production (540,696) (6,333) (246) (580,169) Balance December 31, 2022 (a) 9,187,278 100,153 3,115 9,806,890 Revisions (d) (698,397) 41,119 (453) (454,409) Price Changes (382,311) (12,733) (1,101) (465,314) Extensions and Discoveries (e) 478,026 16,778 589 582,229 Production (514,668) (7,410) (206) (560,366) Sales of Reserves In-Place (146,936) (3,196) (363) (168,288) Balance December 31, 2023 (a) 7,922,992 134,711 1,581 8,740,742 Proved developed reserves: December 31, 2021 5,569,332 53,204 2,843 5,905,611 December 31, 2022 5,788,814 70,063 2,038 6,221,422 December 31, 2023 5,521,437 83,682 706 6,027,762 Proved undeveloped reserves: December 31, 2021 3,418,475 49,081 1,193 3,720,119 December 31, 2022 3,398,464 30,090 1,077 3,585,468 December 31, 2023 2,401,555 51,029 875 2,712,980 __________ (a) Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods. (b) The downward revisions in 2021 are partly due to changes in our five-year development plan that were driven by acreage consolidation initiatives. These initiatives resulted in 267 Bcfe being removed. Additional downward revisions of 356 Bcfe are due to additional changes in our five-year development plans from continued focus on optimizing and maximizing value of our assets. The remaining 20 Bcfe was removed due to risk in well development. 60 Bcfe was removed due to the five-year rule. Offsetting these negative revisions are positive performance revisions of 46 Bcfe associated with Proved Developed Producing assets and 331 Bcfe related to increase performance in Proved Undeveloped assets. (c) The downward revisions in 2022 are partly due to changes in our five-year development plan that were driven by our continued focus on optimizing the development timing of our assets. These initiatives resulted in 298 Bcfe being removed. Additional downward revisions of 66 Bcfe are primarily the result of the plugging of a Shale well. Additionally, there was a 24 Bcfe reduction as a result of net performance revisions. (d) The downward revisions in 2023 are partly due to changes in our five-year development plan that were driven by development optimization initiatives where wells were shifted into the future. These initiatives resulted in 169 Bcfe being removed. Additional downward revisions of 710 Bcfe are due to the wells not being developed within five years of their original booking. The remaining negative revisions of 43 Bcfe are due to plugging and abandoning of wells due to mining and performance. These are partially offset by positive performance revisions of 467 Bcfe for proved undeveloped assets. The 467 Bcfe contains 146 Bcfe of reserves associated with wells that fell out due to price and were uneconomic, but are in 2023 due to improved performance. (e) Extensions and Discoveries in 2021, 2022, and 2023 are due to the addition of wells on the Company’s Shale acreage more than one offset location away with continued use of reliable technology. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sites and data exchanges to confirm continuity of the formation. Total proved extensions and discoveries are a combination of proved developed and proved undeveloped reserves; and, extensions and discoveries for proven developed reserves are associated with non-operated assets and exploratory wells. In 2023, 2022, and 2021, the Company added 42 Bcfe, 23 Bcfe and 26 Bcfe, respectively, related to exploratory and non-operated wells. For the Year Ended December 31, 2023 Proved Undeveloped Reserves (MMcfe) Beginning Proved Undeveloped Reserves 3,585,468 Undeveloped Reserves Transferred to Developed (a) (819,365) Price Revisions (181,837) Revisions Due to Plan Changes (b) (168,800) Revisions Due to Changes Related to Well Performance (c) 466,730 Revisions Due to 5 Year Rule (709,561) Extension and Discoveries (d) 540,345 Ending Proved Undeveloped Reserves(e) 2,712,980 _________ (a) During 2023, various exploration and development drilling and evaluations were completed. Approximately, $319,475 of capital was spent in the year ended December 31, 2023 related to undeveloped reserves that were transferred to developed. (b) The downward revisions for 2023 plan changes are due to changes in our five-year development plan that are driven by our continued focus on optimizing the development timing of our assets. These initiatives resulted in 169 Bcfe being removed. (c) The upward revisions of 467 Bcfe are from increased production performance related to producing offset locations, leasing activities and performance revisions related to wells that fell out for price, but performance resulted in them being in our 2023 reserves. (d) Extensions and discoveries are due mainly to the addition of 336 Bcfe related to 16 Marcellus wells within our Southwest Pennsylvania and Central Pennsylvania operations and 204 Bcfe related to 9 Utica wells within our Central Pennsylvania and Southwest Pennsylvania operations. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sites and data exchanges to confirm continuity of the formation.
Schedule of Aging of Capitalized Exploratory Well Costs	The following table indicates the changes to the Company’s suspended exploratory well costs: For the Years Ended December 31, 2023 2022 2021 Balance, Beginning of Period $ — $ — $ 9,062 Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves — — — Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves — — — Capitalized Exploratory Well Costs Charged to Expense — — (9,062) Balance, End of Period $ — $ — $ —
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The standardized measure is intended to provide a better means for comparing the value of CNX proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities. December 31, 2023 2022 2021 Future Cash Flows (a) Revenues $ 20,281,496 $ 54,713,692 $ 31,838,532 Production Costs (8,515,152) (10,225,451) (8,246,671) Development Costs (b) (1,903,477) (2,233,706) (1,735,784) Income Tax Expense (2,507,151) (10,695,511) (5,838,632) Future Net Cash Flows 7,355,716 31,559,024 16,017,445 Discounted to Present Value at a 10% Annual Rate (4,245,681) (20,796,325) (10,135,869) Total Standardized Measure of Discounted Net Cash Flows $ 3,110,035 $ 10,762,699 $ 5,881,576 _________ (a) For 2023, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2023, adjusted for energy content and a regional price differential. For 2023, this adjusted natural gas price was $2.23 per Mcf, the adjusted oil/condensate price was $65.41 per barrel and the adjusted NGL price was $18.54 per barrel. For 2022, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2022, adjusted for energy content and a regional price differential. For 2022, this adjusted natural gas price was $5.48 per Mcf, the adjusted oil/condensate price was $85.71 per barrel and the adjusted NGL price was $41.05 per barrel. For 2021, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2021, adjusted for energy content and a regional price differential. For 2021, this adjusted natural gas price was $3.19 per Mcf, the adjusted oil/condensate price was $55.72 per barrel and the adjusted NGL price was $28.44 per barrel. (b) Development costs for 2023 include $534,853 of plugging and abandonment costs and $210,322 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $48,538 and $172,885, respectively. Development costs for 2022 include $441,980 of plugging and abandonment costs and $292,937 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,861 and $241,782, respectively. Development costs for 2021 include $405,700 of plugging and abandonment costs and $234,761 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,166 and $197,980, respectively. The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during: December 31, 2023 2022 2021 Balance at Beginning of Period $ 10,762,699 $ 5,881,576 $ 2,635,736 Net Changes in Sales Prices and Production Costs (10,722,238) 6,774,652 5,272,386 Sales Net of Production Costs (992,030) (1,358,052) (1,220,971) Net Change Due to Revisions in Quantity Estimates (155,807) (472,831) (334,660) Net Change Due to Extensions, Discoveries and Improved Recovery 32,876 1,853,496 699,710 Development Costs Incurred During the Period 637,711 526,092 393,641 Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period (149,770) (167,298) (33,175) Changes in Estimated Future Development Costs (211,592) (257,458) 31,406 Net Change in Future Income Taxes 2,647,842 (1,539,146) (1,231,883) Accretion 1,403,417 766,899 329,782 Timing and Other (143,073) (1,245,231) (660,396) Total Discounted Cash Flow at End of Period $ 3,110,035 $ 10,762,699 $ 5,881,576

Significant Accounting Polici_4

Significant Accounting Policies - Trade Accounts Receivable and Allowance for Credit Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Trade Receivables
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for Credit Losses - Trade, Beginning of Year	$ 84	$ 84
Provision for Expected Credit Losses	0	0
Allowance for Credit Losses - Other Receivables, End of Period	84	84
Other Receivables
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for Credit Losses - Trade, Beginning of Year	2,937	3,322
Provision for Expected Credit Losses	32	(198)
Write-off of Uncollectible Accounts	(122)	(187)
Allowance for Credit Losses - Other Receivables, End of Period	$ 2,847	$ 2,937

Significant Accounting Polici_5

Significant Accounting Policies - Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 433,586	$ 461,215	$ 515,118
Gas Properties
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 332,596	$ 359,761	$ 415,069
Buildings and Improvements | Minimum
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	10 years
Buildings and Improvements | Maximum
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	45 years
Machinery and Equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	3 years
Machinery and Equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	25 years
Gathering and Transmission | Minimum
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	30 years
Gathering and Transmission | Maximum
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	40 years
Purchased Software
Property, Plant and Equipment [Line Items]
Useful life of property, plant and equipment	7 years

Significant Accounting Polici_6

Significant Accounting Policies - Impairment of Proved and Unproved Properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Exploration and Production Related Other Costs
Productive Wells [Line Items]
Exploration expense	$ 10,447	$ 8,298	$ 20,626

Significant Accounting Polici_7

Significant Accounting Policies - Impairment of Goodwill and Definite-Lived Intangible Assets (Details)	Dec. 31, 2023
Customer Relationships
Property, Plant and Equipment [Line Items]
Useful life, customer relationship intangible assets	17 years

Significant Accounting Polici_8

Significant Accounting Policies - Investment Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Contribution Plan Disclosure [Line Items]
Company's matching contribution, percentage	6%	6%	6%
Discretionary contributions to the Plan, amount	$ 0	$ 0	$ 0
Total payment and cost to the Plan	$ 3,509,000	$ 3,187,000	$ 2,937,000
Minimum
Defined Contribution Plan Disclosure [Line Items]
Discretionary contributions to the Plan, percentage	1%
Maximum
Defined Contribution Plan Disclosure [Line Items]
Discretionary contributions to the Plan, percentage	6%

Significant Accounting Polici_9

Significant Accounting Policies - Subsequent Events (Details) - shares	1 Months Ended	12 Months Ended
	Feb. 08, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Subsequent Event [Line Items]
Stock repurchased during period (in shares)		17,564,524	33,526,226	18,284,598
Subsequent Event
Subsequent Event [Line Items]
Stock repurchased during period (in shares)	2,000,000

Earnings Per Share - Narrative

Earnings Per Share - Narrative (Details) - Convertible Notes - Convertible 2.25% Senior Notes Due 2026 - $ / shares	Dec. 31, 2023	Apr. 30, 2020
Business Acquisition [Line Items]
Stated rate, debt instrument		2.25%
Initial conversion price (in usd per share)	$ 12.84	$ 12.84

Earnings Per Share - Anti-Dilut

Earnings Per Share - Anti-Dilutive Options and Units Excluded from Earnings Per Share (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share (in shares)	46,806	6,442,587	6,423,803
Anti-Dilutive Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share (in shares)	21,650	2,262,845	2,990,094
Anti-Dilutive Restricted Stock Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share (in shares)	25,156	2,350,661	2,436,846
Anti-Dilutive Performance Share Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share (in shares)	0	1,829,081	996,863

Earnings Per Share - Computatio

Earnings Per Share - Computation of Basic and Diluted (Loss) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income (Loss)	$ 1,720,716	$ (142,077)	$ (498,643)
Net Loss Attributable to CNX Resources Shareholders	1,720,716	(142,077)	(498,643)
Add Back Interest on Convertible Notes (Net of Tax)	5,758	0	0
Diluted Earnings (Loss) Available to Shareholders	$ 1,726,474	$ (142,077)	$ (498,643)
Weighted-Average Shares of Common Stock Outstanding (in shares)	162,490,245	189,507,682	215,971,381
Weighted-Average Diluted Shares of Common Stock Outstanding (in shares)	192,013,989	189,507,682	215,971,381
Earnings (Loss) Per Share:
Basic (in usd per share)	$ 10.59	$ (0.75)	$ (2.31)
Diluted (in usd per share)	$ 8.99	$ (0.75)	$ (2.31)
Convertible Notes
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-Average Diluted Shares of Common Stock Outstanding (in shares)	25,751,869	0	0
Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-Average Diluted Shares of Common Stock Outstanding (in shares)	1,168,526	0	0
Restricted Stock Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-Average Diluted Shares of Common Stock Outstanding (in shares)	1,349,299	0	0
Performance Share Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-Average Diluted Shares of Common Stock Outstanding (in shares)	1,254,050	0	0

Earnings Per Share - Shares of

Earnings Per Share - Shares of Common Stock Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	170,841,164
Balance, end of year (in shares)	154,382,880	170,841,164
Common Stock
Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	170,841,164	203,531,320	220,440,993
Issuance Related to Stock-Based Compensation (in shares)	1,106,240	836,070	1,374,925
Retirement of Common Stock (in shares)	(17,564,524)	(33,526,226)	(18,284,598)
Balance, end of year (in shares)	154,382,880	170,841,164	203,531,320

Revenue From Contracts With C_3

Revenue From Contracts With Customers - Narrative (Details)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Payment terms for contract with customers (in days)	25 days

Revenue From Contracts With C_4

Revenue From Contracts With Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Gain (Loss) on Commodity Derivative Instruments	$ 1,928,652	$ (2,663,775)	$ (1,632,733)
Other Revenue and Operating Income	129,860	87,322	105,883
Total Revenue and Other Operating Income	3,434,948	1,261,211	756,792
Total Natural Gas, NGL and Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue	1,302,218	3,652,112	2,183,929
Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue	1,131,068	3,390,422	1,958,718
NGL Revenue
Disaggregation of Revenue [Line Items]
Revenue	157,573	241,535	202,670
Oil/Condensate Revenue
Disaggregation of Revenue [Line Items]
Revenue	13,577	20,155	22,541
Purchased Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue	$ 74,218	$ 185,552	$ 99,713

Revenue From Contracts With C_5

Revenue From Contracts With Customers - Performance Obligation (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 25,629
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 18,622
Remaining performance obligations, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 4,749
Remaining performance obligations, expected timing of satisfaction	1 year

Acquisitions and Dispositions -

Acquisitions and Dispositions - Narrative (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Gain on transaction	$ 132,372	$ 8,984	$ 42,210
Non-Operated Producing Oil and Gas Assets
Business Acquisition [Line Items]
Gain on transaction	$ 99,516
CNXM CNX Midstream GP LLC CNX Resources Holding LLC Merger Agreements
Business Acquisition [Line Items]
Number of shares issued in acquisition (in shares)	124,600

Stock Repurchase (Details)

Stock Repurchase (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jul. 25, 2023	Oct. 25, 2021	Jan. 26, 2021	Jan. 25, 2021
Equity [Abstract]
Share repurchase program, authorized amount				$ 2,900,000,000	$ 1,900,000,000	$ 900,000,000	$ 750,000,000
Amount available under the current stock repurchase program	$ 1,128,119
Stock repurchased during period (in shares)	17,564,524	33,526,226	18,284,598
Treasure stock acquired (in usd per share)	$ 18.14	$ 16.93	$ 13.17
Stock repurchased and retired	$ 321,867,000	$ 568,128,000	$ 241,243,000

Income Taxes - Income Tax Benef

Income Taxes - Income Tax Benefits (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current:
U.S. Federal		$ 0	$ 0	$ 0
U.S. State		4,777	6,188	17
Current income tax (benefit)		4,777	6,188	17
Deferred:
U.S. Federal		455,224	(40,649)	(157,626)
U.S. State		42,208	(35,409)	19,739
Deferred income tax (benefit)		497,432	(76,058)	(137,887)
Income Tax Expense (Benefit) / Effective Rate	$ (15,983)	$ 502,209	$ (69,870)	$ (137,870)

Income Taxes - Net Deferred Tax

Income Taxes - Net Deferred Tax Assets/Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred Tax Assets:
Net Operating Loss- Federal	$ 160,405	$ 187,154
Section 174 Expenses	92,414	26,397
Net Operating Loss - State	76,259	82,189
Federal Tax Credits	45,619	34,317
Interest Limitation	36,451	14,618
Operating Lease Liabilities	36,297	45,427
Gas Well Closing	24,652	25,045
State Deferred Tax Adjustment	15,983	0
Gas Derivatives	14,466	461,952
Salary Retirement	8,488	8,167
Equity Compensation	5,419	4,474
Convertible Note Amortization	3,628	5,080
Foreign Tax Credit	0	7,738
Other	6,089	8,396
Total Deferred Tax Assets	526,170	910,954
Valuation Allowance	(39,264)	(84,609)
Net Deferred Tax Assets	486,906	826,345
Deferred Tax Liabilities:
Property, Plant and Equipment	(1,177,773)	(850,095)
Operating Lease Right-of-Use Assets	(35,321)	(44,238)
Investment in Partnerships	(2,303)	(163,483)
Advance Gas Royalties	(404)	(286)
Other	(559)	(523)
Total Deferred Tax Liabilities	(1,216,360)	(1,058,625)
Net Deferred Tax Liability	$ (729,454)	$ (232,280)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Valuation Allowance [Line Items]
Federal net operating losses		$ 160,405,000	$ 187,154,000
Federal Tax Credits		45,619,000	34,317,000
Valuation allowance on foreign tax credits			7,738,000
Deferred tax asset related to state operating losses		76,259,000	82,189,000
Valuation allowance		39,264,000	84,609,000
Income tax benefit	$ 15,983,000	(502,209,000)	69,870,000	$ 137,870,000
Unrecognized tax benefits that would impact effective tax rate		99,918,000	82,245,000
Increase in unrecognized tax benefits resulting from tax position taken on prior year return		6,444,000	14,440,000
Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Current Period		11,229,000	0
Accrued liability relating to uncertain tax positions		0	0
Interest related to income tax deficiencies		0	0
Accrued liabilities for tax penalties		0	0
Foreign Tax Credits
Valuation Allowance [Line Items]
Decrease in valuation allowance		7,738,000
State Operating Losses
Valuation Allowance [Line Items]
Valuation allowance		$ 39,264,000	$ 76,871,000

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Amount
Statutory U.S. Federal Income Tax Rate		$ 466,814	$ (44,509)	$ (133,668)
Net Effect of State Income Taxes		83,379	(5,817)	(36,300)
Uncertain Tax Positions		17,673	14,440	35,914
Effect of Equity Compensation		1,036	2,254	2,465
Effect of Change in Valuation Allowance		(37,607)	(35,427)	28,704
Deferred Adjustments		(837)	2,481	(4,408)
Effect of State Rate Changes		297	10,025	22,458
Effect of Federal Tax Credits		(28,974)	(15,723)	(53,269)
Other		428	2,406	234
Income Tax Expense (Benefit) / Effective Rate	$ (15,983)	$ 502,209	$ (69,870)	$ (137,870)
Percent
Statutory U.S. Federal Income Tax Rate		21%	21%	21%
Net Effect of State Income Taxes		3.80%	2.80%	5.70%
Uncertain Tax Positions		0.80%	(6.80%)	(5.60%)
Effect of Equity Compensation		0%	(1.10%)	(0.40%)
Effect of Change in Valuation Allowance		(1.70%)	16.70%	(4.50%)
Deferred Adjustments		0%	(1.20%)	0.70%
Effect of State Rate Changes		0%	(4.70%)	(3.50%)
Effect of Federal Tax Credits		(1.30%)	7.40%	8.30%
Other		0%	(1.10%)	0%
Income Tax Expense (Benefit) / Effective Rate		22.60%	33%	21.70%

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Beginning of Period	$ 82,245	$ 67,805
Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Current Period	11,229	0
Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Prior Periods	6,444	14,440
Balance at End of Period	$ 99,918	$ 82,245

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance, Beginning of Year	$ 98,814	$ 96,013
Obligations Divested	(2,263)	(251)
Accretion Expense	9,025	7,982
Obligations Incurred	1,846	1,336
Obligations Settled	(12,070)	(7,360)
Revisions in Estimated Cash Flows	17,860	1,094
Balance, End of Year	$ 113,212	$ 98,814

Property, Plant and Equipment -

Property, Plant and Equipment - Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Intangible Drilling Cost	$ 5,902,498	$ 5,554,021
Gas Gathering Equipment	2,631,110	2,542,587
Gas Wells and Related Equipment	1,513,945	1,342,719
Proved Gas Properties	1,374,685	1,345,114
Unproved Gas Properties	724,401	734,890
Surface Land and Other Equipment	187,316	193,153
Other	203,163	195,214
Total	12,537,118	11,907,698
Less: Accumulated Depreciation, Depletion and Amortization	5,194,485	4,811,189
Total Property, Plant and Equipment—Net	$ 7,342,633	$ 7,096,509

Property, Plant and Equipment_2

Property, Plant and Equipment - Assets Amortized by Units of Production (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Unproved Gas Properties	$ 724,401	$ 734,890
Total	12,537,118	11,907,698
Assets amortized by units of production
Property, Plant and Equipment [Line Items]
Unproved Gas Properties	724,401	734,890
Advance Royalties	1,597	1,130
Total	$ 725,998	$ 736,020

Goodwill and Other Intangible_3

Goodwill and Other Intangible Assets - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Line Items]
Goodwill	$ 323,314	$ 323,314
Goodwill, Impaired, Accumulated Impairment Loss	473,045	473,045
Amortization expense	6,552	$ 6,553	$ 6,552
Estimated annual amortization expense expected, 2024	6,552
Estimated annual amortization expense expected, 2025	6,552
Estimated annual amortization expense expected, 2026	6,552
Estimated annual amortization expense expected, 2027	6,552
Estimated annual amortization expense expected, 2028	$ 6,552
Customer Relationships
Goodwill [Line Items]
Useful life, customer relationship intangible assets	17 years

Goodwill and Other Intangible_4

Goodwill and Other Intangible Assets - Carrying Amount and Accumulated Amortization of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Gross Amortizable Asset - Customer Relationships	$ 109,752	$ 109,752
Less: Accumulated Amortization - Customer Relationships	39,314	32,762
Total Other Intangible Assets, net	$ 70,438	$ 76,990

Revolving Credit Facilities (De

Revolving Credit Facilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	May 05, 2022 USD ($)	Oct. 06, 2021 USD ($)
Federal Funds Open Rate
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	0.50%
Federal Funds Open Rate | CNXM
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	0.50%
One-Month LIBOR
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	1%
One-Month LIBOR | CNXM
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	1%
One-Month LIBOR | Minimum
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	0.75%
One-Month LIBOR | Minimum | CNXM
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	1%
One-Month LIBOR | Maximum
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	1.75%
One-Month LIBOR | Maximum | CNXM
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	2%
Secured Overnight Financing Rate (SOFR) | Minimum
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	1.85%
Secured Overnight Financing Rate (SOFR) | Minimum | CNXM
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	2.10%
Secured Overnight Financing Rate (SOFR) | Maximum
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	2.85%
Secured Overnight Financing Rate (SOFR) | Maximum | CNXM
Short-term Debt [Line Items]
Basis spread on variable rate (as a percent)	3.10%
Revolving Credit Facility
Short-term Debt [Line Items]
Elected commitments	$ 1,350,000		$ 1,300,000
Maximum borrowing capacity			$ 2,250,000
Percentage of aggregate commitments available under credit facility	20%
Maximum net leverage ratio	3.50
Minimum current ratio	1
Borrowings outstanding	$ 52,050
Weighted average interest rate	7.64%
Letters of credit outstanding	$ 43,684	$ 171,272
Borrowings and issuance of letters of credit remaining capacity	1,254,266	1,128,728
Revolving Credit Facility | CNXM
Short-term Debt [Line Items]
Maximum borrowing capacity				$ 600,000
Borrowings outstanding	$ 105,150	$ 153,700
Weighted average interest rate	7.50%	6.45%
Letters of credit outstanding		$ 30
Interest coverage ratio	2.50
Current borrowing capacity	$ 494,850	$ 446,270
Revolving Credit Facility | Minimum | CNXM
Short-term Debt [Line Items]
Maximum net leverage ratio	5
Revolving Credit Facility | Maximum | CNXM
Short-term Debt [Line Items]
Maximum net leverage ratio	5.25
Secured leverage ratio	3.25

Other Accrued Liabilities (Deta

Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Royalties	$ 100,847	$ 144,482
Accrued Interest	44,227	36,744
Transportation Charges	17,824	12,808
Deferred Revenue	15,831	22,095
Short-Term Incentive Compensation	10,961	18,956
Accrued Other Taxes	9,343	14,067
Accrued Payroll & Benefits	6,619	6,318
Purchased Gas Payable	1,002	5,266
Other	16,777	18,142
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations	7,897	9,735
Salary Retirement	1,886	1,878
Total Other Accrued Liabilities	$ 233,214	$ 290,491

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Apr. 30, 2020	Mar. 31, 2020
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1
Net Carrying Amount	$ 2,214,374	$ 2,205,735
Less: Unamortized Debt Issuance Costs	11,660	14,133
Less: Current Portion	325,668	0
Long-Term Debt	$ 1,888,706	2,205,735
Senior Notes due January 2029 at 6.00%
Debt Instrument [Line Items]
Stated rate, debt instrument	0.06%
Net Carrying Amount	$ 500,000	$ 500,000
Senior Notes Due January 2031 at 7.375%
Debt Instrument [Line Items]
Stated rate, debt instrument		7.375%
Debt instrument, face amount	500,000	$ 500,000
Debt Instrument, unamortized premium	5,308	6,061
Net Carrying Amount	494,692	493,939
Senior Notes due April 2030
Debt Instrument [Line Items]
Stated rate, debt instrument			0.0475%
Debt instrument, face amount	400,000		$ 400,000
Debt Instrument, unamortized premium	3,654	4,231
Net Carrying Amount	$ 396,346	395,769
Senior Notes due March 2027 at 7.25%
Debt Instrument [Line Items]
Stated rate, debt instrument	0.0725%
Debt instrument, face amount	$ 350,000
Debt Instrument, unamortized premium	1,728	2,266
Net Carrying Amount	$ 351,728	352,266
Senior Notes due May 2026
Debt Instrument [Line Items]
Stated rate, debt instrument	0.0225%
Debt instrument, face amount	$ 330,654
Debt instrument, unamortized discount	4,586	6,460
Net Carrying Amount	326,068	324,194
Revolving Credit Facility
Debt Instrument [Line Items]
Debt instrument, face amount					$ 160,000
Revolving Credit Facility | CNX Midstream Partners LP Revolving Credit Facility
Debt Instrument [Line Items]
Net Carrying Amount	105,150	153,700
Revolving Credit Facility | CNX Revolving Credit Facility
Debt Instrument [Line Items]
Net Carrying Amount	$ 52,050	$ 0

Long-Term Debt - Maturities of

Long-Term Debt - Maturities of Long-Term Debt (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
2023	$ 0
2024	0
2025	487,854
2026	350,000
2027	0
Thereafter	1,400,000
Total Long-Term Debt Maturities	$ 2,237,854

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) $ / shares in Units, $ in Thousands		1 Months Ended	12 Months Ended
	Jan. 01, 2022 USD ($)	Apr. 30, 2020 USD ($) day $ / shares	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1
Loss on Debt Extinguishment			$ 0	$ 22,953	$ 33,737
Proceeds from issuance of convertible notes						$ 334,650
Long-Term Debt			1,888,706	2,205,735
Retained Earnings			1,981,860	448,993
Deferred Income Taxes (Note 6)			729,454	232,280
Cumulative Effect of Adoption of New Accounting Standard			4,361,017	2,950,461
Cumulative Effect, Period of Adoption, Adjustment
Debt Instrument [Line Items]
Cumulative Effect of Adoption of New Accounting Standard					(59,337)
Accounting Standards Update 2020-06
Debt Instrument [Line Items]
Stated rate, debt instrument	2.25%
Long-Term Debt	$ 82,327
Embedded conversion	107,260
Retained Earnings	5,986
Deferred Income Taxes (Note 6)	22,990
Cumulative Effect of Adoption of New Accounting Standard	78,284
Accounting Standards Update 2020-06 | Cumulative Effect, Period of Adoption, Adjustment
Debt Instrument [Line Items]
Retained Earnings	$ 24,933
Convertible Notes
Debt Instrument [Line Items]
Purchase of outstanding debt				14,346
Loss on Debt Extinguishment				12,981
Senior Notes Due January 2031 at 7.375%
Debt Instrument [Line Items]
Debt instrument, face amount			500,000	$ 500,000
Stated rate, debt instrument				7.375%
Unamortized discount				$ 6,250
Senior Notes due March 2027 at 7.25%
Debt Instrument [Line Items]
Debt instrument, face amount			$ 350,000
Stated rate, debt instrument			0.0725%
Purchase of outstanding debt			$ 350,000
Loss on Debt Extinguishment			9,972
Senior Notes due April 2030
Debt Instrument [Line Items]
Debt instrument, face amount			$ 400,000		$ 400,000
Stated rate, debt instrument					0.0475%
Unamortized discount					$ 5,000
Senior Notes due March 2026
Debt Instrument [Line Items]
Stated rate, debt instrument					6.50%
Purchase of outstanding debt					$ 400,000
Loss on Debt Extinguishment					25,727
Cardinal States Gathering Company Credit Facility
Debt Instrument [Line Items]
Purchase of outstanding debt					107,705
Loss on Debt Extinguishment					5,763
CSG Holdings II LLC Credit Facility
Debt Instrument [Line Items]
Purchase of outstanding debt					39,726
Loss on Debt Extinguishment					$ 2,247
Convertible 2.25% Senior Notes Due 2026 | Convertible Notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 345,000
Stated rate, debt instrument		2.25%
Conversion rate (in shares)		77.8816
Initial conversion price (in usd per share) | $ / shares		$ 12.84	$ 12.84
Debt issuance costs gross		$ 10,350
Convertible 2.25% Senior Notes Due 2026 | Convertible Notes | Debt Instrument, Redemption, Period One
Debt Instrument [Line Items]
Threshold percentage of stock price trigger		130%
Threshold trading days | day		20
Threshold consecutive trading days | day		30
Convertible 2.25% Senior Notes Due 2026 | Convertible Notes | Debt Instrument, Redemption, Period Two
Debt Instrument [Line Items]
Threshold percentage of stock price trigger		98%
Threshold trading days | day		5
Threshold consecutive trading days | day		10
Convertible 2.25% Senior Notes Due 2026, Additional Option To Initial Purchasers | Convertible Notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 45,000
Convertible 2.25% Senior Notes Due 2026, Liability Component | Convertible Notes
Debt Instrument [Line Items]
Debt issuance costs gross		7,024
Convertible 2.25% Senior Notes Due 2026, Equity Component | Convertible Notes
Debt Instrument [Line Items]
Debt issuance costs gross		3,326
Private Placement | Senior Notes due March 2027 at 7.25% | Debt Instrument, Issuance, Period Two
Debt Instrument [Line Items]
Stated rate, debt instrument				7.25%
Capped Call Transaction
Debt Instrument [Line Items]
Cost incurred with capped calls		$ 35,673
Minimum | Capped Call Transaction | Call Option
Debt Instrument [Line Items]
Price per share (in usd per share) | $ / shares		$ 12.84
Maximum | Capped Call Transaction | Call Option
Debt Instrument [Line Items]
Price per share (in usd per share) | $ / shares		$ 18.19

Long-Term Debt - Schedule of Co

Long-Term Debt - Schedule of Convertible Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Principal	$ 2,237,854
Net Carrying Amount	2,214,374	$ 2,205,735
Convertible Notes | Convertible 2.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Principal	330,654	330,654
Unamortized Issuance Costs	(4,586)	(6,460)
Net Carrying Amount	326,068	324,194
Fair Value	$ 537,465	$ 483,581

Long-Term Debt - Schedule of In

Long-Term Debt - Schedule of Interest (Details) - Convertible Notes - Convertible 2.25% Senior Notes Due 2026 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Contractual Interest Expense	$ 7,440	$ 7,577
Amortization of Issuance Costs	1,873	1,871
Total Interest Expense	$ 9,313	$ 9,448

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023	May 26, 2023
Lessee, Lease, Description [Line Items]
Lease obligation for lease not yet commenced			$ 4,370
ROU asset for lease not yet commenced			$ 5,270
Forecast
Lessee, Lease, Description [Line Items]
Lease obligation for lease not yet commenced	$ 18,823
ROU asset for lease not yet commenced	$ 18,823
Minimum
Lessee, Lease, Description [Line Items]
Lease renewal term (in years)		1 year
Maximum
Lessee, Lease, Description [Line Items]
Lease renewal term (in years)		10 years

Leases - Components of Lease Co

Leases - Components of Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating Lease Cost	$ 63,087	$ 56,725	$ 60,364
Finance Lease Cost:
Amortization of Right-of-Use Assets	1,628	665	1,577
Interest on Lease Liabilities	429	78	123
Short-term Lease Cost	2,357	7,784	8,589
Variable Lease Cost	12,401	9,271	7,100
Total Lease Cost	$ 79,902	$ 74,523	$ 77,753

Leases - Balance Sheet Informat

Leases - Balance Sheet Information (Details) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Operating Leases:
Operating Lease Right-of-Use Assets	$ 139,466	$ 174,849
Current Portion of Operating Lease Obligations	53,791	47,436
Operating Lease Obligations	89,531	132,105
Total Operating Lease Liabilities	143,322	179,541
Finance Leases:
Property, Plant and Equipment	10,864	6,777
Less—Accumulated Depreciation, Depletion and Amortization	3,502	3,926
Property, Plant and Equipment—Net	7,362	2,851
Current Portion of Finance Lease Obligations	1,862	881
Finance Lease Obligations	5,500	1,970
Total Finance Lease Liabilities	$ 7,362	$ 2,851
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total Property, Plant and Equipment—Net	Total Property, Plant and Equipment—Net

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating Cash Flows for Operating Leases	$ 64,139	$ 55,729	$ 56,966
Operating Cash Flows for Finance Leases	429	78	123
Financing Cash Flows for Finance Leases	1,627	665	2,785
Right-of-Use Assets Obtained in Exchange for Lease Obligations:
Operating Leases	19,477	36,758	4,010
Finance Leases	$ 6,178	$ 1,742	$ 772

Leases - Maturity of Lease Liab

Leases - Maturity of Lease Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
2023	$ 59,430
2024	50,373
2025	19,372
2026	6,048
2027	6,109
Thereafter	15,422
Total Lease Payments	156,754
Less: Interest	13,432
Present Value of Lease Liabilities	143,322	$ 179,541
Finance Leases
2023	2,401
2024	2,347
2025	2,278
2026	1,963
2027	598
Thereafter	30
Total Lease Payments	9,617
Less: Interest	2,255
Present Value of Lease Liabilities	$ 7,362	$ 2,851

Leases - Terms and Discount Rat

Leases - Terms and Discount Rates (Details)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating leases, weighted average remaining lease term	3 years 7 months 2 days	4 years 4 months 28 days	6 years 2 months 12 days
Finance leases, weighted average remaining lease term	4 years 29 days	4 years 3 days	3 years 6 months 21 days
Operating leases, weighted average discount rate	4.84%	4.65%	4.84%
Finance leases, weighted average discount rate	7.35%	6.17%	1.72%

Pension - Reconciliation of Cha

Pension - Reconciliation of Changed in Benefit Obligations, Plan Assets, and Funded Status of Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in Benefit Obligation:
Benefit Obligation at Beginning of Period	$ 32,223	$ 42,990
Interest Cost	1,675	1,035	$ 855
Actuarial Loss (Gain)	1,442	(10,006)
Benefits and Other Payments	(1,799)	(1,796)
Benefit Obligation at End of Period	33,541	32,223	42,990
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Period	0	0
Company Contributions	1,799	1,796
Benefits and Other Payments	(1,799)	(1,796)
Fair Value of Plan Assets at End of Period	0	0	$ 0
Funded Status:
Current Liabilities	(1,886)	(1,878)
Noncurrent Liabilities	(31,655)	(30,345)
Net Obligation Recognized	(33,541)	(32,223)
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss	9,153	7,884
Prior Service Cost	842	1,063
Total	9,995	8,947
Net Amount Recognized	7,301	6,513
Accumulated Defined Benefit Plans Adjustment Attributable to Parent
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Less: Tax Benefit	$ 2,694	$ 2,434

Pension - Components of Net Per

Pension - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Retirement Benefits [Abstract]
Interest Cost	$ 1,675	$ 1,035	$ 855
Amortization of Prior Service Cost	222	221	222
Recognized Net Actuarial Loss	173	510	513
Net Periodic Benefit Cost	$ 2,070	$ 1,766	$ 1,590
Defined Benefit Plan Net Periodic Benefit Cost Credit Interest Cost Statement Of Income Or Comprehensive Income Extensible List Not Disclosed Flag	Interest Cost	Interest Cost	Interest Cost
Defined Benefit Plan Net Periodic Benefit Cost Credit Amortization Of Prior Service Cost Credit Statement Of Income Or Comprehensive Income Extensible List Not Disclosed Flag	Amortization of Prior Service Cost	Amortization of Prior Service Cost	Amortization of Prior Service Cost
Defined Benefit Plan Net Periodic Benefit Cost Credit Amortization Of Gain Loss Statement Of Income Or Comprehensive Income Extensible List Not Disclosed Flag	Recognized Net Actuarial Loss	Recognized Net Actuarial Loss	Recognized Net Actuarial Loss

Pension - Accumulated Benefit O

Pension - Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Retirement Benefits [Abstract]
Projected Benefit Obligation	$ 33,541	$ 32,223
Accumulated Benefit Obligation	33,541	32,223
Fair Value of Plan Assets	$ 0	$ 0

Pension - Weighted Average Assu

Pension - Weighted Average Assumptions (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	5.15%	5.43%
Rate of Compensation Increase	0%	0%
Interest Credited Rate	4.74%	4.43%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	5.43%	2.84%	2.47%
Rate of Compensation Increase	0%	0%	0%
Interest Credited Rate	4.81%	4.07%	2.71%

Pension - Expected Future Benef

Pension - Expected Future Benefit Payment (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Retirement Benefits [Abstract]
2024	$ 1,886
2025	1,983
2026	2,053
2027	2,143
2028	2,236
Year 2029-2033	$ 13,057

Stock-Based Compensation - Narr

Stock-Based Compensation - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) employeePopulation shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($)	May 31, 2020 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for grant (in shares) | shares	7,853,582
Stock-based compensation expense	$ 20,235	$ 16,375	$ 16,560
Deferred tax benefit from stock-based compensation	6,983	$ 4,497	4,409
Unrecognized compensation cost related to nonvested awards	$ 24,731
Recognition period, weighted average	3 years 1 month 24 days
Number of distinct employee populations | employeePopulation	2
Options outstanding (in shares) | shares	2,085,870	2,262,845
Tax impact from option exercises	$ 529	$ 463	960
Board Approved Share Increase
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares approved for increase in available for issuance (in shares) | shares				10,775,000
Anti-Dilutive Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award conversation ratio	1
Award vesting period	3 years
Intrinsic value of options exercised	$ 2,015	1,825	5,027
Cash received from option exercises	$ 1,760	1,197	5,087
Anti-Dilutive Options | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	1 year
Options outstanding (in shares) | shares	428,425
Anti-Dilutive Options | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding (in shares) | shares	1,657,445
Anti-Dilutive Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of RSUs granted during the year	$ 16,194	16,852	12,603
Fair value of restricted stock units vested during the year	$ 12,321	11,811	9,249
Anti-Dilutive Restricted Stock Units | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	1 year
Anti-Dilutive Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award conversation ratio	1.62
Fair value of RSUs granted during the year	$ 18,383	7,726	7,634
Fair value of performance share units vested	$ 4,563	$ 949	$ 6,206
Anti-Dilutive Performance Share Units | Granted in 2016-2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	5 years
Anti-Dilutive Performance Share Units | Granted in 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Anti-Dilutive Performance Share Units | Granted in 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	7 years

Stock-Based Compensation - Opti

Stock-Based Compensation - Options Granted, Assumptions and Weighted Average Fair Value (Details) - Stock Option - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of options granted during the year (in USD per share)	$ 115	$ 115	$ 0
Weighted average fair value of grants (in usd per share)	$ 7.06	$ 10.60
Risk-free interest rate (as a percent)	3.24%	3.02%
Expected dividend yield (as a percent)	0%	0%
Expected forfeiture rate (as a percent)	0%	0%
Expected volatility (as a percent)	48.70%	54%
Expected term in years	5 years 6 months	5 years 6 months	0 years

Stock-Based Compensation - Stoc

Stock-Based Compensation - Stock and Performance Options Rollforward (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Shares
Beginning balance (in shares) | shares	2,262,845
Granted (in shares) | shares	16,289
Exercised (in shares) | shares	(193,264)
Ending balance (in shares) | shares	2,085,870
Exercisable (in shares) | shares	2,069,581
Weighted Average Exercise Price
Beginning balance (in usd per share) | $ / shares	$ 8.55
Granted (in usd per share) | $ / shares	14.63
Exercised (in usd per share) | $ / shares	9.10
Ending balance (in usd per share) | $ / shares	8.55
Exercisable (in usd per share) | $ / shares	$ 8.50
Weighted average remaining contractual term (in years), outstanding	2 years 8 months 19 days
Weighted average remaining contractual term (in years), exercisable	2 years 8 months 1 day
Aggregate intrinsic value, outstanding | $	$ 23,890
Aggregate intrinsic value, exercisable | $	$ 23,802

Stock-Based Compensation - Rest

Stock-Based Compensation - Restricted and Performance Stock Unit Rollforward (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Units
Number of Shares
Beginning nonvested balance (in shares)	1,833,920
Granted (in shares)	999,465
Vested (in shares)	(1,031,200)
Forfeited (in shares)	(205,645)
Ending nonvested balance (in shares)	1,596,540
Weighted Average Grant Date Fair Value
Beginning nonvested balance (in usd per share)	$ 15.14	$ 12.69
Granted (in usd per share)	16.20
Vested (in usd per share)	11.95
Forfeited (in usd per share)	14.51
Ending nonvested balance (in usd per share)	$ 15.14
Performance Share Units
Number of Shares
Beginning nonvested balance (in shares)	2,293,678
Granted (in shares)	1,687,329
Vested (in shares)	(576,421)
Forfeited (in shares)	(605,868)
Ending nonvested balance (in shares)	2,798,718
Weighted Average Grant Date Fair Value
Beginning nonvested balance (in usd per share)	$ 10.77	$ 10.53
Granted (in usd per share)	10.89
Vested (in usd per share)	7.92
Forfeited (in usd per share)	12.93
Ending nonvested balance (in usd per share)	$ 10.77

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Significant Noncash Transactions [Line Items]
Interest (Net of Amounts Capitalized)	$ 122,279	$ 126,643	$ 123,466
Income Taxes	7,329	0	0
Notes Received from Property Sales
Other Significant Noncash Transactions [Line Items]
Capital expenditures incurred, not yet paid	$ 28,198	$ 56,052	$ 35,592

Concentration of Credit Risk _3

Concentration of Credit Risk and Major Customers - Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Concentration Risk [Line Items]
Total Accounts Receivable Trade	$ 116,119	$ 348,458
Accounts Receivable | Customer Concentration Risk
Concentration Risk [Line Items]
Allowance for Credit Losses	(84)	(84)
Total Accounts Receivable Trade	116,119	348,458
Accounts Receivable | Customer Concentration Risk | Gas Wholesalers
Concentration Risk [Line Items]
Accounts Receivable Trade Before Allowance for Credit Losses	99,493	304,842
Accounts Receivable | Customer Concentration Risk | NGL, Condensate & Processing Facilities
Concentration Risk [Line Items]
Accounts Receivable Trade Before Allowance for Credit Losses	12,005	26,382
Accounts Receivable | Customer Concentration Risk | Other
Concentration Risk [Line Items]
Accounts Receivable Trade Before Allowance for Credit Losses	$ 4,705	$ 17,318

Concentration of Credit Risk _4

Concentration of Credit Risk and Major Customers - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Receivables related to contracts with customers	$ 116,119	$ 348,458
Direct Energy Business Marketing LLC
Concentration Risk [Line Items]
Revenue from contracts with customers	165,465	453,501	$ 235,760
Citadel Energy Marketing LLC
Concentration Risk [Line Items]
Revenue from contracts with customers	180,039		$ 334,407
Accounts Receivable | Customer Concentration Risk
Concentration Risk [Line Items]
Receivables related to contracts with customers	116,119	348,458
Accounts Receivable | Customer Concentration Risk | Direct Energy Business Marketing LLC
Concentration Risk [Line Items]
Receivables related to contracts with customers	13,416	$ 33,322
Accounts Receivable | Customer Concentration Risk | DTE Energy
Concentration Risk [Line Items]
Receivables related to contracts with customers	$ 11,611
Revenue from Contract with Customer Benchmark | Customer Concentration Risk | Direct Energy Business Marketing LLC
Concentration Risk [Line Items]
Percentage of revenue (more than)	10%	10%	10%
Revenue from Contract with Customer Benchmark | Customer Concentration Risk | Citadel Energy Marketing LLC
Concentration Risk [Line Items]
Percentage of revenue (more than)	10%		10%

Fair Value of Financial Instr_3

Fair Value of Financial Instruments - Financial Instruments Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 6,741
Gas derivatives settled not paid	(900)	$ 77,662
Level 1 | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Level 1 | Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Level 2 | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	(55,701)	(1,904,830)
Level 2 | Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1,099	4,561
Level 3 | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Level 3 | Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 0	$ 0

Fair Value of Financial Instr_4

Fair Value of Financial Instruments - Fair Value Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$ 443	$ 21,321
Long-Term Debt (Excluding Debt Issuance Costs)*	2,214,374	2,205,735
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents	443	21,321
Long-Term Debt (Excluding Debt Issuance Costs)*	2,226,034	2,219,868
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents	443	21,321
Long-Term Debt (Excluding Debt Issuance Costs)*	$ 2,376,594	$ 2,240,919

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Apr. 30, 2020
Derivative [Line Items]
Debt instrument, face amount					$ 1
Cash received in settlement of derivatives		$ 4,207	$ (1,572)	$ (5,574)
Interest Rate Swap on Revolving Credit Facility | Long
Derivative [Line Items]
Put option (as a percent)	0%
Derivative term of contract	4 years
Derivative notional amount	$ 250,000
Revolving Credit Facility
Derivative [Line Items]
Debt instrument, face amount	$ 160,000

Derivative Instruments - Notion

Derivative Instruments - Notional Amounts of Derivative Instruments (Details) $ in Thousands, Mcf in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Mcf MBbls	Dec. 31, 2022 USD ($) MBbls Mcf
Commodity Swaps | Natural Gas Commodity Swaps (Bcf)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative notional amount (in Bcf)	1,349.2	1,607.9
Commodity Swaps | Propane Commodity Swaps (Mbbls)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative notional amount (in Bcf) | MBbls	81,000	0
Natural Gas Basis Swaps (Bcf)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative notional amount (in Bcf)	760.3	1,023.7
Interest Rate Swaps
Derivative Instruments, Gain (Loss) [Line Items]
Derivative notional amount | $	$ 410,000	$ 410,000

Derivative Instruments - Fair V

Derivative Instruments - Fair Value of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Total Current Assets	$ 252,524	$ 154,474
Total Other Non-Current Assets	280,530	244,931
Total Current Liabilities	61,102	782,653
Total Non-Current Liabilities	526,554	1,517,021
Commodity Swaps
Derivative [Line Items]
Total Current Assets	168,532	21,759
Total Other Non-Current Assets	166,701	42,786
Total Current Liabilities	47,279	732,717
Total Non-Current Liabilities	484,357	1,466,124
Propane Swaps
Derivative [Line Items]
Total Current Assets	1,003	0
Basis Only Swaps
Derivative [Line Items]
Total Current Assets	77,540	118,115
Total Other Non-Current Assets	113,829	197,280
Total Current Liabilities	9,473	38,559
Total Non-Current Liabilities	42,197	47,370
Interest Rate Swaps
Derivative [Line Items]
Total Current Assets	5,449	14,600
Total Other Non-Current Assets	0	4,865
Total Current Liabilities	4,350	11,377
Total Non-Current Liabilities	$ 0	$ 3,527

Derivative Instruments - Effect

Derivative Instruments - Effect of Derivative Instrument on Statement of Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Realized Gain (Loss) on Commodity Derivative Instruments:	$ 163,026	$ (1,812,777)	$ (539,016)
Unrealized Gain (Loss) on Commodity Derivative Instruments:	1,765,626	(850,998)	(1,093,717)
Gain (Loss) on Commodity Derivative Instruments	1,928,652	(2,663,775)	(1,632,733)
Cash Received (Paid) in Settlement of Interest Rate Swaps	4,207	(1,572)	(5,574)
Unrealized (Loss) Gain on Interest Rate Swaps	(3,463)	10,348	8,485
Natural Gas Basis Swaps
Derivative [Line Items]
Realized Gain (Loss) on Commodity Derivative Instruments:	98,582	158,510	57,603
Unrealized Gain (Loss) on Commodity Derivative Instruments:	(93,222)	71,426	147,110
Gain (Loss) on Commodity Derivative Instruments	5,360	229,936	204,713
Interest Rate Swaps
Derivative [Line Items]
Gain (Loss) on Commodity Derivative Instruments	744	8,776	2,911
Commodity Derivatives
Derivative [Line Items]
Derivative Asset	6,741
Gas derivatives settled not paid	(900)	77,662
Natural Gas Revenue | Commodity Swaps
Derivative [Line Items]
Realized Gain (Loss) on Commodity Derivative Instruments:	62,567	(1,971,287)	(596,619)
Unrealized Gain (Loss) on Commodity Derivative Instruments:	1,858,060	(922,424)	(1,240,827)
Gain (Loss) on Commodity Derivative Instruments	1,920,627	(2,893,711)	(1,837,446)
Propane Commodity Swaps (Mbbls) | Propane Swaps
Derivative [Line Items]
Realized Gain (Loss) on Commodity Derivative Instruments:	1,877	0	0
Unrealized Gain (Loss) on Commodity Derivative Instruments:	788	0	0
Gain (Loss) on Commodity Derivative Instruments	$ 2,665	$ 0	$ 0

Commitments and Contingent Li_3

Commitments and Contingent Liabilities - Narrative (Details)	May 01, 2020 employee
Murray | Settlement Agreement Between Murray And UMWA
Loss Contingencies [Line Items]
Number of retirees	2,159

Commitments and Contingent Li_4

Commitments and Contingent Liabilities - Maximum Potential Total of Future Payments Under Commitment Instruments (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	$ 265,121
Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	43,684
Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	221,437
Less Than 1  Year
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	265,121
Less Than 1  Year | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	43,684
Less Than 1  Year | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	221,437
1-3 Years
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
1-3 Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
1-3 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
3-5 Years
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
3-5 Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
3-5 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond 5  Years
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond 5  Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond 5  Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Firm Transportation | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	40,331
Firm Transportation | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	126,336
Firm Transportation | Less Than 1  Year | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	40,331
Firm Transportation | Less Than 1  Year | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	126,336
Firm Transportation | 1-3 Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Firm Transportation | 1-3 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Firm Transportation | 3-5 Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Firm Transportation | 3-5 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Firm Transportation | Beyond 5  Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Firm Transportation | Beyond 5  Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Other | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	3,353
Other | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	8,682
Other | Less Than 1  Year | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	3,353
Other | Less Than 1  Year | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	8,682
Other | 1-3 Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Other | 1-3 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Other | 3-5 Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Other | 3-5 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Other | Beyond 5  Years | Letters of Credit:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Other | Beyond 5  Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Employee-Related | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	2,250
Employee-Related | Less Than 1  Year | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	2,250
Employee-Related | 1-3 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Employee-Related | 3-5 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Employee-Related | Beyond 5  Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Environmental | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	11,449
Environmental | Less Than 1  Year | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	11,449
Environmental | 1-3 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Environmental | 3-5 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Environmental | Beyond 5  Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Financial Guarantees | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	72,720
Financial Guarantees | Less Than 1  Year | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	72,720
Financial Guarantees | 1-3 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Financial Guarantees | 3-5 Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Financial Guarantees | Beyond 5  Years | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	$ 0

Commitments and Contingent Li_5

Commitments and Contingent Liabilities - Unrecorded Unconditional Purchase Obligation (Details) - Purchase Commitment $ in Thousands	Dec. 31, 2023 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Less than 1 year	$ 247,586
1 - 3 years	446,255
3 - 5 years	373,180
More than 5 years	581,370
Total Purchase Obligations	$ 1,648,391

Segment Information - Industry

Segment Information - Industry Segment Results (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) segment	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Segment Reporting [Abstract]
Number of reportable segments | segment	2
Segment Reporting Information [Line Items]
Loss on Commodity Derivative Instruments	$ 1,928,652	$ (2,663,775)	$ (1,632,733)
Other Revenue and Operating Income	129,860	87,322	105,883
Total Revenue and Other Operating Income	3,434,948	1,261,211	756,792
Total Operating Expense	1,192,109	1,321,641	1,234,874
Earnings Before Income Tax	2,222,925	(211,947)	(636,513)
Segment Assets	8,626,657	8,515,773	8,100,751
Depreciation, Depletion and Amortization	433,586	461,215	515,118
Capital Expenditures	679,404	565,754	465,861
Natural Gas, NGLs and Oil Revenue
Segment Reporting Information [Line Items]
Revenue	1,302,218	3,652,112	2,183,929
Purchased Gas Revenue
Segment Reporting Information [Line Items]
Revenue	74,218	185,552	99,713
Citadel Energy Marketing LLC
Segment Reporting Information [Line Items]
Revenue	180,039		334,407
Total Revenue and Other Operating Income	$ 180,039		$ 334,407
Citadel Energy Marketing LLC | Revenue from Contract with Customer Benchmark | Customer Concentration Risk
Segment Reporting Information [Line Items]
Percentage of revenue (more than)	10%		10%
Direct Energy Business Marketing LLC
Segment Reporting Information [Line Items]
Revenue	$ 165,465	453,501	$ 235,760
Total Revenue and Other Operating Income	$ 165,465	$ 453,501	$ 235,760
Direct Energy Business Marketing LLC | Revenue from Contract with Customer Benchmark | Customer Concentration Risk
Segment Reporting Information [Line Items]
Percentage of revenue (more than)	10%	10%	10%
Operating Segments
Segment Reporting Information [Line Items]
Revenue	$ 1,442,995	$ 3,907,282	$ 2,364,909
Investments in unconsolidated equity affiliates	13,682	11,714	17,301
Reportable Subsegments | Exploration and Production | Operating Segments
Segment Reporting Information [Line Items]
Total Operating Expense			312,970
Segment Assets			981,405
Depreciation, Depletion and Amortization			16,492
Capital Expenditures			1,378
Reportable Subsegments | Exploration and Production | Operating Segments | Shale
Segment Reporting Information [Line Items]
Loss on Commodity Derivative Instruments	151,408	(1,672,974)	(492,526)
Other Revenue and Operating Income	66,559	69,618	81,267
Total Revenue and Other Operating Income	1,388,360	1,731,321	1,577,734
Total Operating Expense	746,050	790,960	804,004
Earnings Before Income Tax	642,310	940,361	773,730
Segment Assets	6,656,655	6,452,075	6,071,495
Depreciation, Depletion and Amortization	365,020	388,641	440,024
Capital Expenditures	629,631	544,914	453,603
Reportable Subsegments | Exploration and Production | Operating Segments | Coalbed Methane
Segment Reporting Information [Line Items]
Loss on Commodity Derivative Instruments	11,554	(139,131)	(46,304)
Other Revenue and Operating Income	0	0	0
Total Revenue and Other Operating Income	142,317	175,564	147,274
Total Operating Expense	141,708	131,426	117,900
Earnings Before Income Tax	609	44,138	29,374
Segment Assets	948,795	959,126	1,047,851
Depreciation, Depletion and Amortization	50,052	53,201	58,602
Capital Expenditures	36,804	15,043	10,880
Reportable Subsegments | Exploration and Production | Operating Segments | Other
Segment Reporting Information [Line Items]
Loss on Commodity Derivative Instruments	1,765,690	(851,670)	(1,093,903)
Other Revenue and Operating Income	63,301	17,704	24,616
Total Revenue and Other Operating Income	1,904,271	(645,674)	(968,216)
Total Operating Expense	304,351	399,255
Earnings Before Income Tax	1,580,006	(1,196,446)	(1,439,617)
Segment Assets	1,021,207	1,104,572
Depreciation, Depletion and Amortization	18,514	19,373
Capital Expenditures	12,969	5,797
Reportable Subsegments | Exploration and Production | Operating Segments | Shale and Other
Segment Reporting Information [Line Items]
Equity in earnings (loss) of affiliates	2,942	1,412	5,780
Reportable Subsegments | Exploration and Production | Operating Segments | Environmental Attributes
Segment Reporting Information [Line Items]
Other Revenue and Operating Income	40,685
Reportable Subsegments | Exploration and Production | Operating Segments | Natural Gas, NGLs and Oil Revenue | Shale
Segment Reporting Information [Line Items]
Revenue	1,170,393	3,334,677	1,988,993
Reportable Subsegments | Exploration and Production | Operating Segments | Natural Gas, NGLs and Oil Revenue | Coalbed Methane
Segment Reporting Information [Line Items]
Revenue	130,763	314,695	193,578
Reportable Subsegments | Exploration and Production | Operating Segments | Natural Gas, NGLs and Oil Revenue | Other
Segment Reporting Information [Line Items]
Revenue	1,062	2,740	1,358
Reportable Subsegments | Exploration and Production | Operating Segments | Purchased Gas Revenue | Shale
Segment Reporting Information [Line Items]
Revenue	0	0	0
Reportable Subsegments | Exploration and Production | Operating Segments | Purchased Gas Revenue | Coalbed Methane
Segment Reporting Information [Line Items]
Revenue	0	0	0
Reportable Subsegments | Exploration and Production | Operating Segments | Purchased Gas Revenue | Other
Segment Reporting Information [Line Items]
Revenue	$ 74,218	$ 185,552	$ 99,713

Segment Information - Reconcili

Segment Information - Reconciliation of Segment Information, Revenue and Other Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting, Revenue Reconciling Item [Line Items]
Gain (Loss) on Commodity Derivative Instruments	$ 1,928,652	$ (2,663,775)	$ (1,632,733)
Other Operating Income	63,301	17,704	24,616
Total Consolidated Revenue and Other Operating Income	3,434,948	1,261,211	756,792
Operating Segments
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Segment Revenue from Contracts with External Customers	$ 1,442,995	$ 3,907,282	$ 2,364,909

Supplemental Gas Data (unaudi_3

Supplemental Gas Data (unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Intangible Drilling Cost	$ 5,902,498	$ 5,554,021
Gas Gathering Assets	2,631,110	2,542,587
Proved Gas Properties	1,374,685	1,345,114
Unproved Gas Properties	724,401	734,890
Gas Wells and Related Equipment	1,513,945	1,342,719
Other Gas Assets	119,163	99,457
Total Property, Plant and Equipment	12,265,802	11,618,788
Accumulated Depreciation, Depletion and Amortization	(5,110,938)	(4,710,684)
Net Capitalized Costs	$ 7,154,864	$ 6,908,104

Supplemental Gas Data (unaudi_4

Supplemental Gas Data (unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property Acquisitions:
Proved Properties	$ 2,319	$ 19,766	$ 32,355
Unproved Properties	26,405	14,802	20,568
Development	637,711	526,092	393,641
Exploration	4,257	6,806	30,927
Total	670,692	567,466	477,491
Midstream
Property Acquisitions:
Development	$ 47,000	$ 38,000	$ 35,000

Supplemental Gas Data (unaudi_5

Supplemental Gas Data (unaudited) - Results of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Natural Gas, NGLs and Oil Revenue	$ 1,302,218	$ 3,652,112	$ 2,183,929
Realized Gain (Loss) on Commodity Derivative Instruments	163,026	(1,812,777)	(539,016)
Unrealized Gain (Loss) on Commodity Derivative Instruments	1,765,626	(850,998)	(1,093,717)
Purchased Gas Revenue	74,218	185,552	99,713
Total Revenue	3,305,088	1,173,889	650,909
Lease Operating Expense	63,333	66,658	46,256
Production, Ad Valorem and Other Fees	27,946	44,965	34,051
Transportation, Gathering and Compression	381,934	369,660	343,635
Purchased Gas Costs	69,924	185,383	93,776
Exploration Costs	10,447	8,298	20,626
Depreciation, Depletion and Amortization	433,586	461,215	515,118
Total Costs	987,170	1,136,179	1,053,462
Pre-tax Operating Income (Loss)	2,317,918	37,710	(402,553)
Income Tax Expense (Benefit)	523,849	12,444	(87,354)
Results of Operations for Producing Activities excluding Corporate and Interest Costs	$ 1,794,069	$ 25,266	$ (315,199)

Supplemental Gas Data (unaudi_6

Supplemental Gas Data (unaudited) - Average Unit Prices and Average Production Costs (Details) Mcfe in Thousands	12 Months Ended
	Dec. 31, 2023 dollarsPerMcfe Mcfe	Dec. 31, 2022 dollarsPerMcfe Mcfe	Dec. 31, 2021 dollarsPerMcfe Mcfe
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Production (MMcfe) | Mcfe	560,366	580,169	590,248
Natural Gas, Per Thousand Cubic Feet
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)	2.32	6.29	3.70
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)	0.32	(3.35)	(0.98)
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)	2.61	3.17	2.79
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)	0.11	0.11	0.08

Supplemental Gas Data (unaudi_7

Supplemental Gas Data (unaudited) - Narrative (Details) $ in Thousands, Mcf in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) well Mcf	Dec. 31, 2022 USD ($) well	Dec. 31, 2021 USD ($) well	Dec. 31, 2020 USD ($)
Extractive Industries [Abstract]
Net development wells drilled	30.8	37	33
Net dry development wells drilled	0	0
Net exploratory wells drilled	0	0
Number of net dry exploratory wells	0	0	0
Net development wells drilled but uncompleted	13.8
Exploratory wells, drilled uncompleted	0
Gas delivery commitment, remaining contractual volume | Mcf	470.9
Period from reserves booking for proved undeveloped locations to be fully developed	5 years
Oil and Gas, Development Well Drilled [Line Items]
Capitalized exploratory well costs | $	$ 0	$ 0	$ 0	$ 9,062

Supplemental Gas Data (unaudi_8

Supplemental Gas Data (unaudited) - Producing Wells, Developed Acreage and Undeveloped Acreage (Details)	Dec. 31, 2023 a well
Extractive Industries [Abstract]
Working interest percentage	100%
Gross
Proved Developed Acreage | a	385,087
Proved Undeveloped Acreage | a	40,811
Unproved Acreage | a	4,704,922
Total Acreage | a	5,130,820
Net
Proved Developed Acreage | a	385,087
Proved Undeveloped Acreage | a	40,811
Unproved Acreage | a	3,392,132
Total Acreage | a	3,818,030
Working Interest
Gross
Producing Gas Wells | well	4,499
Producing Oil Wells | well	2
Net
Producing Gas Wells | well	4,425
Producing Oil Wells | well	0
Royalty Interest
Gross
Producing Gas Wells | well	320
Producing Oil Wells | well	126
Net
Producing Gas Wells | well	0
Producing Oil Wells | well	0

Supplemental Gas Data (unaudi_9

Supplemental Gas Data (unaudited) - Proved Undeveloped Reserves (Details) bbl in Thousands, Mcfe in Thousands, Mcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) Mcfe well bbl Mcf	Dec. 31, 2022 USD ($) Mcfe Mcf bbl	Dec. 31, 2021 USD ($) Mcfe Mcf bbl
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Beginning balance (energy)	9,806,890	9,625,730	9,549,758
Revisions (energy)	(454,409)	(387,320)	(327,050)
Price changes (energy)	(465,314)	24,904	86,532
Extensions and Discoveries (energy)	582,229	1,123,745	906,738
Production (MMcfe)	(560,366)	(580,169)	(590,248)
Sales of Reserves In-Place (MMcfe)	(168,288)
Ending balance (energy)	8,740,742	9,806,890	9,625,730
Proved developed resources (energy)	6,027,762	6,221,422	5,905,611
Proved undeveloped resources (energy)	2,712,980	3,585,468	3,720,119
Downward revision due to plan changes (energy)	710,000	24,000	356,000
Upward revision from increased performance (energy)	467,000		331,000
Proved and unproved resources, extensions and discoveries (energy)	42,000	23,000	26,000
Downward revision for acreage consolidation (energy)	169,000		267,000
Downward revision due to 5 year rule (energy)			60,000
Revision due to mining and performance	43,000
Performance revision associated with proved developed producing assets (energy)	467,000		46,000
Revision for fallen wells	146,000
Capital spent related to undeveloped reserves transferred to developed | $	$ 679,404	$ 565,754	$ 465,861
Downward revision due to risk in well development (energy)			20,000
Reserves reported for more than five years	290,000
Utica | Central Pennsylvania and Southwest Pennsylvania
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved and unproved resources, extensions and discoveries (energy)	204,000
Number of dry gas wells added | well	9
Marcellus | Southwest Pennsylvania and West Virginia
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved and unproved resources, extensions and discoveries (energy)	336,000
Number of dry gas wells added | well	16
Shale
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Downward revision due to plan changes (energy)		66,000
Downward revision for acreage consolidation (energy)		298,000
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance (volume) | Mcf	9,187,278	8,987,807	9,034,066
Revisions (volume) | Mcf	(698,397)	(339,878)	(409,215)
Price Changes (volume) | Mcf	(382,311)	24,795	82,248
Extension and Discoveries (volume) | Mcf	478,026	1,055,250	832,696
Production (volume) | Mcf	(514,668)	(540,696)	(551,988)
Sales of Reserves In-Place (volume) | Mcf	(146,936)
Ending balance (volume) | Mcf	7,922,992	9,187,278	8,987,807
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved developed resources (volume) | Mcf	5,521,437	5,788,814	5,569,332
Proved undeveloped resources (volume) | Mcf	2,401,555	3,398,464	3,418,475
NGLs
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance (volume) | bbl	100,153	102,285	81,867
Revisions (volume) | bbl	41,119	(6,140)	13,655
Price Changes (volume) | bbl	(12,733)	17	692
Extension and Discoveries (volume) | bbl	16,778	10,324	12,047
Production (volume) | bbl	(7,410)	(6,333)	(5,976)
Sales of Reserves In-Place (volume) | bbl	(3,196)
Ending balance (volume) | bbl	134,711	100,153	102,285
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved developed resources (volume) | bbl	83,682	70,063	53,204
Proved undeveloped resources (volume) | bbl	51,029	30,090	49,081
Condensate & Crude Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance (volume) | bbl	3,115	4,036	4,081
Revisions (volume) | bbl	(453)	(1,768)	39
Price Changes (volume) | bbl	(1,101)	1	22
Extension and Discoveries (volume) | bbl	589	1,092	294
Production (volume) | bbl	(206)	(246)	(400)
Sales of Reserves In-Place (volume) | bbl	(363)
Ending balance (volume) | bbl	1,581	3,115	4,036
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved developed resources (volume) | bbl	706	2,038	2,843
Proved undeveloped resources (volume) | bbl	875	1,077	1,193
Proved Undeveloped
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Beginning balance (energy)	3,585,468
Undeveloped Reserves Transferred to Developed (energy)	(819,365)
Extensions and Discoveries (energy)	540,345
Ending balance (energy)	2,712,980	3,585,468
Capital spent related to undeveloped reserves transferred to developed | $	$ 319,475
Proved Undeveloped | Price Revisions
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Revisions (energy)	(181,837)
Proved Undeveloped | Revisions Due to Plan Changes
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Revisions (energy)	(168,800)
Proved Undeveloped | Revisions Due to Changes Related to Well Performance
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Revisions (energy)	466,730
Proved Undeveloped | Revisions Due to 5 Year Rule
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Revisions (energy)	(709,561)

Supplemental Gas Data (unaud_10

Supplemental Gas Data (unaudited) - Capitalized Exploratory Well Cost Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance, Beginning of Period	$ 0	$ 0	$ 9,062
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves	0	0	0
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves	0	0	0
Capitalized Exploratory Well Costs Charged to Expense	0	0	(9,062)
Balance, End of Period	$ 0	$ 0	$ 0

Supplemental Gas Data (unaud_11

Supplemental Gas Data (unaudited) - Future Cash Flow of Proved Reserves (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) usd_per_mcf usd_per_bbl	Dec. 31, 2022 USD ($) usd_per_bbl usd_per_mcf	Dec. 31, 2021 USD ($) usd_per_bbl usd_per_mcf	Dec. 31, 2020 USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Revenues	$ 20,281,496	$ 54,713,692	$ 31,838,532
Production Costs	(8,515,152)	(10,225,451)	(8,246,671)
Development Costs	(1,903,477)	(2,233,706)	(1,735,784)
Income Tax Expense	(2,507,151)	(10,695,511)	(5,838,632)
Future Net Cash Flows	7,355,716	31,559,024	16,017,445
Discounted to Present Value at a 10% Annual Rate	(4,245,681)	(20,796,325)	(10,135,869)
Total Standardized Measure of Discounted Net Cash Flows	3,110,035	10,762,699	5,881,576	$ 2,635,736
Development costs, plugging and abandonment costs	534,853	441,980	405,700
Pre-tax discounted basis, plugging and abandonment costs	48,538	7,861	7,166
Midstream
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Development costs relating to capital	210,322	292,937	234,761
Pre-tax discounted basis, development costs relating to capital	$ 172,885	$ 241,782	$ 197,980
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Adjusted oil price (in usd per unit) | usd_per_mcf	2.23	5.48	3.19
Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Adjusted oil price (in usd per unit) | usd_per_bbl	65.41	85.71	55.72
NGL
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Adjusted oil price (in usd per unit) | usd_per_bbl	18.54	41.05	28.44

Supplemental Gas Data (unaud_12

Supplemental Gas Data (unaudited) - Change in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	$ 10,762,699	$ 5,881,576	$ 2,635,736
Net Changes in Sales Prices and Production Costs	(10,722,238)	6,774,652	5,272,386
Sales Net of Production Costs	(992,030)	(1,358,052)	(1,220,971)
Net Change Due to Revisions in Quantity Estimates	(155,807)	(472,831)	(334,660)
Net Change Due to Extensions, Discoveries and Improved Recovery	32,876	1,853,496	699,710
Development Costs Incurred During the Period	637,711	526,092	393,641
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period	(149,770)	(167,298)	(33,175)
Changes in Estimated Future Development Costs	(211,592)	(257,458)	31,406
Net Change in Future Income Taxes	2,647,842	(1,539,146)	(1,231,883)
Accretion	1,403,417	766,899	329,782
Timing and Other	(143,073)	(1,245,231)	(660,396)
Total Discounted Cash Flow at End of Period	$ 3,110,035	$ 10,762,699	$ 5,881,576

Schedule II - Valuation and Q_2

Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of period	$ 84,609	$ 151,798	$ 123,098
Charged to expense - additions	0	10,815	41,300
Release of valuation allowance - deductions	(7,738)	(31,762)	(12,600)
Charged to expense - deductions	(37,607)	(46,242)	0
Balance at end of period	39,264	84,609	151,798
State Operating Loss Carry-Forwards
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of period	76,871	112,298	79,198
Charged to expense - additions	0	10,815	41,300
Release of valuation allowance - deductions	0	0	(8,200)
Charged to expense - deductions	(37,607)	(46,242)	0
Balance at end of period	39,264	76,871	112,298
Charitable Contributions
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of period	0	96	706
Charged to expense - additions		0	0
Release of valuation allowance - deductions		(96)	(610)
Charged to expense - deductions		0	0
Balance at end of period		0	96
Foreign Tax Credits
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of period	7,738	39,404	43,194
Charged to expense - additions	0	0	0
Release of valuation allowance - deductions	(7,738)	(31,666)	(3,790)
Charged to expense - deductions	0	0	0
Balance at end of period	$ 0	$ 7,738	$ 39,404