v3.25.4
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2025
Feb. 04, 2026
Jun. 30, 2025
Document Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
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     $ 3,582,679,149
Entity Common Stock, Shares Outstanding   142,368,170  
Documents Incorporated by Reference
Part III incorporates information by reference to the registrant’s definitive proxy statement, to be filed with the Securities and Exchange Commission within 120 days after the close of the fiscal year ended December 31, 2025.
    
Amendment Flag false    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
Entity Central Index Key 0001070412    
Common Stock      
Document Information [Line Items]      
Title of 12(b) Security Common Stock ($.01 par value)    
Trading Symbol CNX    
Security Exchange Name NYSE    
Preferred Share Purchase Rights      
Document Information [Line Items]      
Title of 12(b) Security Preferred Share Purchase Rights    
Security Exchange Name NYSE    
No Trading Symbol Flag true    
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Audit Information [Abstract]  
Auditor Firm ID 42
Auditor Name Ernst & Young LLP
Auditor Location Pittsburgh, Pennsylvania
v3.25.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Revenue and Other Operating Income:      
Gain (Loss) on Commodity Derivative Instruments $ 96,661 $ (172,405) $ 1,928,652
Other Revenue and Operating Income 183,396 193,647 129,860
Total Revenue and Other Operating Income 2,239,134 1,266,786 3,434,948
Operating Expense      
Lease Operating Expense 97,416 70,646 63,333
Production, Ad Valorem and Other Fees 31,200 27,554 27,946
Depreciation, Depletion and Amortization 574,114 485,754 433,586
Purchased Gas Costs 42,647 57,248 69,924
Selling, General and Administrative Costs 140,302 145,736 125,344
Other Operating Expense 68,912 82,748 79,595
Total Operating Expense 1,348,211 1,260,352 1,192,109
Other Expense      
Other Expense (Income) 13,716 (6,126) 9,008
Gain on Asset Sales and Abandonments, net (97,168) (24,715) (132,372)
Loss on Debt Extinguishment 842 7,043 0
Interest Expense 170,592 150,594 143,278
Total Other Expense 87,982 126,796 19,914
Total Costs and Expenses 1,436,193 1,387,148 1,212,023
Income (Loss) Before Income Tax 802,941 (120,362) 2,222,925
Income Tax Expense (Benefit) 169,779 (29,868) 502,209
Net Income (Loss) $ 633,162 $ (90,494) $ 1,720,716
Earnings (Loss) Per Share      
Basic (in usd per share) $ 4.48 $ (0.60) $ 10.59
Diluted (in usd per share) 3.98 (0.60) 8.99
Dividends Declared Per Share (in usd per share) $ 0 $ 0 $ 0
Natural Gas, NGLs and Oil Revenue      
Revenue and Other Operating Income:      
Revenue $ 1,913,728 $ 1,186,077 $ 1,302,218
Purchased Gas Revenue      
Revenue and Other Operating Income:      
Revenue 45,349 59,467 74,218
Transportation, Gathering and Compression      
Operating Expense      
Transportation, Gathering and Compression and Exploration and Production Related Other Costs 383,104 382,220 381,934
Exploration and Production Related Other Costs      
Operating Expense      
Transportation, Gathering and Compression and Exploration and Production Related Other Costs $ 10,516 $ 8,446 $ 10,447
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Net Income (Loss) $ 633,162 $ (90,494) $ 1,720,716
Other Comprehensive Income (Loss):      
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $(21), $(550), $258) 33 1,589 (788)
Comprehensive Income (Loss) $ 633,195 $ (88,905) $ 1,719,928
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parentheticals) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Other comprehensive income, tax expense $ (21) $ (550) $ 258
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Current Assets:    
Cash and Cash Equivalents $ 779 $ 17,198
Restricted Cash 12,685 37,875
Accounts and Notes Receivable:    
Trade, net (Note 17) 264,658 179,547
Other Receivables, net 61,249 17,859
Supplies Inventories 26,201 14,572
Derivative Instruments (Note 19) 106,068 87,925
Prepaid Expenses 18,697 15,659
Total Current Assets 490,337 370,635
Property, Plant and Equipment (Note 8):    
Property, Plant and Equipment 14,057,224 13,037,948
Less—Accumulated Depreciation, Depletion and Amortization 6,193,871 5,653,837
Total Property, Plant and Equipment—Net 7,863,353 7,384,111
Other Non-Current Assets:    
Operating Lease Right-of-Use Assets (Note 13) 150,310 98,713
Derivative Instruments (Note 19) 134,396 160,183
Goodwill (Note 9) 323,314 323,314
Other Intangible Assets (Note 9) 57,333 63,885
Other 75,403 111,062
Total Other Non-Current Assets 740,756 757,157
TOTAL ASSETS 9,094,446 8,511,903
Current Liabilities:    
Accounts Payable 158,811 123,249
Derivative Instruments (Note 19) 377,945 354,621
Current Portion of Finance Lease Obligations (Note 13) 5,095 4,236
Current Portion of Long-Term Debt (Note 12) 208,095 327,766
Current Portion of Operating Lease Obligations (Note 13) 48,453 51,474
Other Accrued Liabilities (Note 11) 325,976 261,232
Total Current Liabilities 1,124,375 1,122,578
Non-Current Liabilities:    
Long-Term Debt (Note 12) 2,213,264 1,838,234
Finance Lease Obligations (Note 13) 24,991 21,040
Operating Lease Obligations (Note 13) 104,955 49,519
Derivative Instruments (Note 19) 158,368 429,533
Deferred Income Taxes (Note 6) 857,367 696,136
Asset Retirement Obligations (Note 7) 163,051 119,189
Other 111,059 137,644
Total Non-Current Liabilities 3,633,055 3,291,295
TOTAL LIABILITIES 4,757,430 4,413,873
Stockholders’ Equity:    
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 142,590,509 Issued and Outstanding at December 31, 2025; 148,879,640 Issued and Outstanding at December 31, 2024 1,427 1,490
Capital in Excess of Par Value 2,357,039 2,348,959
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding 0 0
Retained Earnings 1,984,229 1,753,293
Accumulated Other Comprehensive Loss (5,679) (5,712)
TOTAL STOCKHOLDERS' EQUITY 4,337,016 4,098,030
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 9,094,446 $ 8,511,903
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares
Dec. 31, 2025
Dec. 31, 2024
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) 142,590,509 148,879,640
Common stock, outstanding (in shares) 142,590,509 148,879,640
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
v3.25.4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Capital in Excess of Par Value
Retained Earnings
Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2022 $ 2,950,461 $ 1,712 $ 2,506,269 $ 448,993 $ (6,513)
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
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 (Loss) (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]          
Net Income (Loss) (90,494)     (90,494)  
Issuance of Common Stock 2,689 4 2,685    
Purchase and Retirement of Common Stock (178,583) (72) (58,717) (119,794)  
Shares Withheld for Taxes (18,279)     (18,279)  
Amortization of Stock-Based Compensation Awards 20,091 10 20,081    
Other Comprehensive Income (Loss) 1,589       1,589
Ending balance at Dec. 31, 2024 4,098,030 1,490 2,348,959 1,753,293 (5,712)
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Net Income (Loss) 633,162     633,162  
Issuance of Common Stock 2,094 3 2,091    
Purchase and Retirement of Common Stock (528,073) (169) (139,685) (388,219)  
Convertible Debt Exchange for Shares 122,098 95 122,003    
Shares Withheld for Taxes (14,007)     (14,007)  
Amortization of Stock-Based Compensation Awards 23,679 8 23,671    
Other Comprehensive Income (Loss) 33       33
Ending balance at Dec. 31, 2025 $ 4,337,016 $ 1,427 $ 2,357,039 $ 1,984,229 $ (5,679)
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Flows from Operating Activities:      
Net Income (Loss) $ 633,162 $ (90,494) $ 1,720,716
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:      
Depreciation, Depletion and Amortization 574,114 485,754 433,586
Amortization of Deferred Financing Costs 10,732 11,345 9,275
Stock-Based Compensation 23,679 20,091 20,235
Gain on Asset Sales and Abandonments, net (97,168) (24,715) (132,372)
Loss on Debt Extinguishment 842 7,043 0
(Gain) Loss on Commodity Derivative Instruments (96,661) 172,405 (1,928,652)
Loss on Other Derivative Instruments 0 1,099 3,463
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments (143,536) 307,939 79,523
Deferred Income Taxes 161,210 (33,869) 497,432
Other 1,839 1,345 (1,967)
Changes in Operating Assets:      
Accounts and Notes Receivable (66,641) (59,996) 222,751
Supplies Inventories (11,629) 5,274 7,310
Prepaid Expenses (3,038) (675) 1,227
Changes in Other Assets 22,533 (47,084) 75
Changes in Operating Liabilities:      
Accounts Payable 21,609 (4,194) (55,309)
Accrued Interest 5,059 1,585 7,483
Other Operating Liabilities 18,870 21,000 (67,140)
Changes in Other Liabilities (26,019) 41,926 (3,048)
Net Cash Provided by Operating Activities 1,028,957 815,779 814,588
Cash Flows from Investing Activities:      
Capital Expenditures (494,988) (540,332) (679,404)
Proceeds from Asset Sales 107,655 60,734 170,027
Investment in Equity Affiliates 4,019 (4,871) 0
Apex Acquisition (Net of Cash Acquired) (517,599) 0 0
Net Cash Used in Investing Activities (900,913) (484,469) (509,377)
Cash Flows from Financing Activities:      
Payments on Long-Term Notes 0 (356,504) 0
Payments on Other Debt (4,464) (2,409) (1,627)
Proceeds from Issuance of Common Stock 2,094 2,689 1,760
Shares Withheld for Taxes (14,007) (18,279) (9,500)
Purchases of Common Stock (523,561) (184,203) (319,866)
Debt Issuance and Financing Fees (1,465) (15,274) (356)
Net Cash Used in Financing Activities (169,653) (276,680) (326,089)
Net (Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash (41,609) 54,630 (20,878)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period 55,073 443 21,321
Cash, Cash Equivalents, and Restricted Cash at End of Period 13,464 55,073 443
CNXM Revolving Credit Facility      
Cash Flows from Financing Activities:      
Net Proceeds from Revolving Credit Facility Borrowings 339,225 265,250 333,575
Net Payments on Revolving Credit Facility Borrowings (322,525) (354,350) (382,125)
CNX Revolving Credit Facility      
Cash Flows from Financing Activities:      
Net Proceeds from Revolving Credit Facility Borrowings 1,927,100 1,134,500 1,588,350
Net Payments on Revolving Credit Facility Borrowings (1,770,550) (1,143,100) (1,536,300)
CNX Senior Notes      
Cash Flows from Financing Activities:      
Proceeds from Issuance of CNX Senior Notes $ 198,500 $ 395,000 $ 0
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES
 12 Months Ended
Dec. 31, 2025
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, and the fair value of derivative instruments.
Cash and Cash Equivalents:
Cash and cash equivalents of $779 and $17,198 as of December 31, 2025 and 2024, respectively, includes 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.
Restricted Cash:
Restricted cash of $12,685 and $37,875 as of December 31, 2025 and 2024, respectively, consists of funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire the natural gas upstream and associated midstream business of Apex Energy II, LLC, as well as, funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire various rights-of-way, surface acreage and other oil and gas royalty interests from a third party. See Note 4 – Acquisitions and Dispositions for more information.
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, 2025 or 2024.
The following represents activity related to the allowance for credit losses for the years ended:

December 31,
20252024
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$1,233 $2,847 
Recoveries Collected— (1,692)
Provision for Expected Credit Losses131 186 
Write-off of Uncollectible Accounts(327)(108)
Allowance for Credit Losses - Other Receivables, End of Period$1,037 $1,233 

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 $458,335, $378,646, and $332,596 for the years ended December 31, 2025, 2024 and 2023, 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 ImprovementsLife 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. There were no indicators of impairment related to long-lived assets in the years ended December 31, 2025 or 2024.

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. There were no indicators of impairment related to the Company's proved oil and gas properties in the years ended December 31, 2025 or 2024.
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. There were no indicators of impairment related to the Company’s unproved properties in the years ended December 31, 2025 or 2024.

Exploration expense, which is associated primarily with lease expirations, was $10,516, $8,446 and $10,447 for the years ended December 31, 2025, 2024 and 2023, 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 2025, 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, 2025, 2024 and 2023, 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, 2025, 2024 and 2023. Total matching contribution payments and costs were $3,201, $3,603 and $3,509 for the years ended December 31, 2025, 2024 and 2023, 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 2025, the FASB issued Accounting Standards Update (ASU) 2025-11 - Interim Reporting - Narrow-Scope Improvements. The amendments in this ASU clarify interim disclosure requirements and the applicability of Topic 270. It does not fundamentally change the nature of interim reporting or expand/reduce disclosure requirements but makes the guidance easier to navigate and apply. This ASU compiles as list of required interim disclosures from across the GAAP Codification into ASC 270, making it easier for preparers to identify what disclosures are required for interim periods. The amendments in this ASU are effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. The Company is still evaluating the impact of the adoption of this ASU.

In July 2025, the FASB issued ASU 2025-05 Financial Instruments - Credit Losses- Measurement of Credit Losses for Accounts Receivable and Contract Assets. This ASU amends the current expected credit loss (CECL) model for current accounts receivable and contract assets arising from transactions accounted for under Topic 606. In developing reasonable and supportable forecasts as part of estimating expected credit losses, a practical expedient may be elected that assumes the current conditions of the balance sheet date do not change for the remaining life of the asset. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods. The Company is still evaluating the impact of the adoption of this ASU and does not expect this ASU to have a material impact on our consolidated financial statements.

In November 2024, the FASB issued ASU 2024-04 - Debt with Conversion and Other Options (Subtopic 470-20). This ASU clarifies the requirements related to accounting for the settlement of a debt instrument as an induced conversion. An induced conversion is when a Company induces debt holders to convert their debt into equity shares under changed terms and involved additional consideration. The amendments in this ASU are effective for all entities for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. Early adoption is permitted for all entities that have adopted the amendments in ASU 2020-06. The Company does not anticipate a material impact from this ASU given the maturity schedule of CNX’s Convertible Notes. See Note 12 – Long-Term Debt for more information.

In November 2024, the FASB issued ASU 2024-03 - Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40). This ASU requires entities to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations into the following required natural expense categories within the footnotes, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) DD&A recognized as part of oil- and gas-producing activities or other depletion expenses. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is still evaluating the impact of the adoption of this ASU.

See Note 6 – Income Taxes for the impact of adoption of ASU 2023-09 - Income Taxes (Topic 740): Improvements to Income Tax Disclosures.

Reclassifications:

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2025, with no effect on previously reported net income, stockholders' equity or statement of cash flows.
Subsequent Events:
The Company has evaluated all subsequent events through the date the financial statements were issued.
v3.25.4
EARNINGS PER SHARE
 12 Months Ended
Dec. 31, 2025
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,
 202520242023
Anti-Dilutive Options— 947,257 21,650 
Anti-Dilutive Restricted Stock Units243,629 2,043,947 25,156 
Anti-Dilutive Performance Share Units— 1,469,703 — 
243,629 4,460,907 46,806 

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. On January 28, 2026, in accordance with the indenture governing the Convertible Notes, CNX issued a notice of settlement method election for all of the outstanding Convertible Notes providing that CNX would settle any of the Convertible Notes outstanding by issuing shares of the company's common stock, together, if applicable, with cash in lieu of fractional shares, as provided for in the indenture.

Accounting Standards Update (“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 Convertible Notes have been excluded from the computation of diluted earnings per share for the year ended December 31, 2024 as the effect of including these shares in the calculation would have been anti-dilutive. When the convertible notes are dilutive, interest on Convertible Notes, net of tax, is added back to net income in order to calculate diluted earnings available to shareholders.

The table below sets forth the potential common shares issuable upon conversion of the Convertible Notes that were excluded from the calculation of diluted earnings per share because their effect would be anti-dilutive:

For the Years Ended December 31,
2025
2024
2023
Convertible Notes
— 25,751,869 — 
The computations for basic and diluted loss per share are as follows:
For the Years Ended December 31,
 202520242023
Net Income (Loss)$633,162 $(90,494)$1,720,716 
Basic Earnings (Loss) Available to Shareholders$633,162 $(90,494)$1,720,716 
Effect of Dilutive Securities:
Add Back Interest on Convertible Notes (Net of Tax)5,782 — 5,758 
Diluted Earnings (Loss) Available to Shareholders$638,944 $(90,494)$1,726,474 
Weighted-Average Shares of Common Stock Outstanding141,453,847 151,306,438 162,490,245 
Effect of Diluted Shares:*
Options560,895 — 1,168,526 
Restricted Stock Units1,181,954 — 1,349,299 
Performance Share Units913,146 — 1,254,050 
Convertible Notes16,242,679 — 25,751,869 
Weighted-Average Diluted Shares of Common Stock Outstanding160,352,521 151,306,438 192,013,989 
Earnings (Loss) Per Share:
Basic$4.48 $(0.60)$10.59 
Diluted$3.98 $(0.60)$8.99 
*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,
 202520242023
Balance, Beginning of Year148,879,640 154,382,880 170,841,164 
Issuance Related to Stock-Based Compensation (1)1,071,390 1,672,434 1,106,240 
Retirement of Common Stock (2)(16,869,709)(7,175,674)(17,564,524)
Issuance related to Convertible Debt (3)9,509,188 — — 
Balance, End of Year142,590,509 148,879,640 154,382,880 
(1) See Note 15 – Stock-Based Compensation for additional information.
(2) See Note 5 – Stock Repurchase for additional information.
(3) See Note 12 – Long-Term Debt for additional information.
v3.25.4
REVENUE FROM CONTRACTS WITH CUSTOMERS
 12 Months Ended
Dec. 31, 2025
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) are 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,
202520242023
Revenue from Contracts with Customers:
Natural Gas Revenue$1,736,693 $986,028 $1,131,068 
NGL Revenue168,574 190,374 157,573 
Oil/Condensate Revenue8,461 9,675 13,577 
Total Natural Gas, NGL and Oil Revenue1,913,728 1,186,077 1,302,218 
Purchased Gas Revenue45,349 59,467 74,218 
Other Sources of Revenue and Other Operating Income:
Gain (Loss) on Commodity Derivative Instruments 96,661 (172,405)1,928,652 
Other Revenue and Operating Income183,396 193,647 129,860 
Total Revenue and Other Operating Income$2,239,134 $1,266,786 $3,434,948 
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 $20,074 as of December 31, 2025. The Company expects to recognize net revenue of $16,246 in the next 12 months and $2,600 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
CNX records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas, NGL and oil revenue may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. CNX records the differences between the estimate and the actual amounts received in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and the related accruals, and any identified differences between its revenue estimates and the actual revenue received historically have not been significant. For each of the years ended December 31, 2025, 2024 and 2023, revenue recognized in the current reporting period related to performance obligations satisfied in a prior reporting period was not material.
v3.25.4
ACQUISITIONS AND DISPOSITIONS
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
ACQUISITIONS AND DISPOSITIONS ACQUISITIONS AND DISPOSITIONS:
On January 27, 2025, the Company completed the acquisition of Apex Energy II, LLC ("the Apex Transaction") for total cash consideration of approximately $517,599, net of $1,588 of cash received. In May 2025, CNX finalized the initial post-closing adjustments and based on the outcome and the expectation of no further material adjustments, recorded a short-term payable of $10,100. This payable represents the estimated final settlement amount due under the terms of the purchase agreement. The restricted cash balance will be used to satisfy this obligation. The Apex Transaction was classified as an asset acquisition under GAAP as substantially all the fair value of the acquired assets is concentrated in a group of similar identifiable assets, which are primarily oil and gas properties, wells, and well-related equipment. Therefore, the properties were recorded at the total consideration paid, including purchase price adjustments and capitalized transaction costs. The purchase price was allocated to the assets and liabilities acquired based on their estimated relative fair value as of the acquisition date, with approximately $523,256 of the purchase price allocated to proved oil and gas properties, wells, and well-related equipment. The Apex Transaction expands CNX's existing Shale undeveloped leasehold in the central Pennsylvania region and provides an existing infrastructure footprint that can be leveraged for future development.
During the year ended December 31, 2025, CNX acquired various rights-of-way, surface acreage and other oil and gas royalty interests from a third party for net cash proceeds of $24,250 and subject to certain post-closing adjustments. The net cash proceeds are included in Capital Expenditures in the Consolidated Statements of Cash Flows.
During the year ended December 31, 2025, CNX sold approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio to a third party for net cash proceeds of $57,086 and subject to certain post-closing adjustments. The net cash proceeds are included in Proceeds from Asset Sales in the Consolidated Statements of Cash Flows. The net gain on the transaction of $57,086 is included in the Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
During the year ended December 31, 2024, CNX closed on the sale of a non-core pipeline to a third party. The net cash proceeds of $2,017 are included in Proceeds from Asset Sales in the Consolidated Statements of Cash Flows and the net loss on the transaction of $26,150 is included in the Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
During the year ended December 31, 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 net cash proceeds of $124,600 are included in Proceeds from Asset Sale in the Consolidated Statements of Cash Flows and the net gain on the transaction of $99,516 is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
Additionally, Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income and Proceeds from Asset Sales in the Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023 include the sale of various non-core assets (rights-of-way, surface acreage and other non-operated oil and gas interests and assets), none of which were individually material.
v3.25.4
STOCK REPURCHASE
 12 Months Ended
Dec. 31, 2025
Equity [Abstract]  
STOCK REPURCHASE STOCK REPURCHASE:
The Company’s stock repurchase program was initially announced on September 5, 2017, pursuant to authorization from the Company’s Board of Directors. The Board has periodically increased the authorized dollar amount under the program since its inception. As of December 31, 2025, total authorized repurchases were $2,900,000 of which $428,014 remained available.

On January 29, 2026, the Company announced that its Board of Directors approved a $2,000,000 increase to the Company's existing stock repurchase program. This approval increased the dollar amount of common stock currently available to be repurchased under the Company’s existing stock repurchase program to approximately $2,400,000 on the date of announcement. The stock repurchase program is not subject to a termination date or 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, 2025, 16,869,709 shares were repurchased and retired at an average price of $31.00 per share for a total cost of $528,073, including excise taxes.

During the year ended December 31, 2024, 7,175,674 shares were repurchased and retired at an average price of $24.68 per share for a total cost of $178,583, including excise taxes.
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, including excise taxes.
v3.25.4
INCOME TAXES
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
INCOME TAXES INCOME TAXES:
In December 2023, the FASB issued 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 and may be applied prospectively or retrospectively. Effective for the year ended December 31, 2025, we have retrospectively adopted this guidance, which did not have an impact on our financial statements, although it did result in expanded income tax-related disclosures, which are included below.

Income tax expense (benefit) provided on earnings consisted of:
For the Years Ended December 31,
202520242023
Current:
U.S. Federal
$421 $756 $— 
U.S. State
8,148 3,245 4,777 
8,569 4,001 4,777 
Deferred:
U.S. Federal
132,228 (27,917)455,224 
U.S. State
28,982 (5,952)42,208 
161,210 (33,869)497,432 
Total Income Tax Expense (Benefit)$169,779 $(29,868)$502,209 
The components of the net deferred taxes are as follows:
December 31,
20252024
Deferred Tax Assets:
Net Operating Loss- Federal
$149,684 $137,476 
Federal Tax Credits79,118 44,457 
Section 174 Expenses65,566 91,342 
Gas Well Closing61,234 33,541 
   Gas Derivatives60,306 130,834 
Net Operating Loss - State
53,679 70,689 
Operating Lease Liabilities38,960 25,650 
Interest Limitation25,623 62,271 
State Deferred Tax Adjustment15,983 15,983 
Salary Retirement8,073 8,037 
Equity Compensation4,670 6,659 
Convertible Note Amortization360 2,121 
Other
3,649 2,687 
Total Deferred Tax Assets
566,905 631,747 
Valuation Allowance
(32,262)(36,879)
Net Deferred Tax Assets
534,643 594,868 
Deferred Tax Liabilities:
Property, Plant and Equipment
(1,350,179)(1,261,971)
   Operating Lease Right-of-Use Assets(38,173)(25,071)
Investment in Partnerships(3,110)(2,825)
   Advance Gas Royalties(437)(515)
Other
(111)(622)
Total Deferred Tax Liabilities
(1,392,010)(1,291,004)
Net Deferred Tax Liability
$(857,367)$(696,136)

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.

As of December 31, 2025, the Company has a deferred tax asset related to federal net operating losses of $149,684. 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 - 2025 do not expire but may only offset 80% of taxable income in any tax years beginning after 2020.

As of December 31, 2025 and 2024, the Company has $79,118 and $44,457, respectively, of Federal Tax Credits available to offset future federal tax. These credits expire between 2036 and 2045.

CNX has, on an after federal tax basis, a deferred tax asset related to state operating losses of $53,679 with a related valuation allowance of $32,262 at December 31, 2025. The deferred tax asset related to state operating losses, on an after-tax adjusted basis, was $70,689 with a related valuation allowance of $36,879 at December 31, 2024. A review of positive and negative evidence regarding these state tax attributes concluded that the valuation allowances for various CNX subsidiaries was warranted.
On July 4, 2025, the United States enacted into law the One, Big, Beautiful Bill Act ("OBBBA"). The OBBBA, which, among other things, allows for 100% bonus depreciation on a permanent basis for property acquired and placed in service on or after January 19, 2025, permanently reinstates the EBITDA limitation for the calculation of the deduction for interest expense after December 31, 2024, and allows permanent expensing rather than a five-year amortization period for domestic R&D amounts paid or incurred in tax years beginning after December 31, 2024. The OBBBA primarily impacts CNX's taxable temporary differences and certain deferred tax assets and liabilities with no material impact to the estimated annual effective tax rate.

On November 12, 2025, Pennsylvania enacted legislation that effectively decoupled from the provision of the OBBBA that allows for permanent expensing rather than a 5-year amortization period for domestic R&D amounts paid or incurred in tax years beginning after December 31, 2024. West Virginia and Virginia have yet to update its Internal Revenue Code fixed date conformity date to a period post enactment of OBBBA, thereby also decoupling from the OBBBA provision discussed above in their entirety.

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. Beginning in 2022 and in each year thereafter, the Company revised the deferred state income tax rates and apportionment factors for several states to reflect, among other things, the 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,
 202520242023
 AmountPercentAmountPercentAmountPercent
U.S. Federal Statutory Tax Rate$168,618 21.0 %$(25,276)21.0 %$466,814 21.0 %
State Income Taxes, Net of Federal
Income Tax Effect (1)37,330 4.7 (4,610)3.8 83,379 3.8 
Effect of Changes in Tax Laws or Rates
Enacted in the Current Period2,706 0.3 2,806 (2.3)297 — 
Tax Credits
Research and development tax credits(14,251)(1.8)850 (0.7)(28,974)(1.3)
Energy-related tax credits(36,217)(4.5)(15,266)12.7 — — 
Foreign Tax Credits— — — — 7,738 0.3 
Changes in Valuation Allowances(4,617)(0.6)(2,385)2.0 (45,345)(2.0)
Nontaxable or Nondeductible Items
Share-based payment awards1,098 0.1 (40)— 1,036 — 
Other356 — 515 (0.4)428 — 
Changes in Unrecognized Tax Benefits15,807 2.0 13,309 (11.1)17,673 0.8 
Other Adjustments(1,051)(0.1)229 (0.2)(837)— 
Effective Tax Rate$169,779 21.1 %$(29,868)24.8 %$502,209 22.6 %
(1) State taxes in Pennsylvania, Virginia and West Virginia made up the majority (greater than 50 percent) of the tax effect in this category.

The effective tax rate for the year ended December 31, 2025 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.
The effective tax rate for the year ended December 31, 2024 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.

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.

CNX files income tax returns in the U.S. federal and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state, or local income tax examinations by tax authorities for the years before 2022.

A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:
For the Years Ended
December 31,
20252024
Balance at Beginning of Period$113,227 $99,918 
Additions based on tax positions related to the current year17,341 18,224 
Additions for tax positions of prior years1,821 — 
Reductions for tax positions of prior years(3,355)(4,915)
Balance at End of Period$129,034 $113,227 

If these unrecognized tax benefits were recognized, $129,034 and $113,227 would affect CNX’s effective tax rate for 2025 and 2024, respectively.

In 2025 and 2024, CNX recognized an increase in unrecognized tax benefits of $17,341 and $18,224, respectively, for tax benefits resulting from tax positions expected to be taken on our 2025 federal tax return for federal tax credits. CNX also recognized a change in unrecognized tax benefits of $(1,534) and $(4,915), respectively, for tax benefits resulting from tax positions taken during prior period federal tax returns for federal tax credits.

CNX recognizes accrued interest related to unrecognized tax benefits in its interest expense. As of December 31, 2025 and 2024, the Company reported no accrued liability relating to interest in Other Liabilities in the Consolidated Balance Sheets. During the years ended December 31, 2025 and 2024, 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, 2025 and 2024.

The following table summarizes income taxes paid (net of refunds received). All jurisdictions in which income taxes paid (net of refunds received) were equal to or greater than five percent of total income taxes paid are included below (if the noted jurisdiction did not meet the five percent threshold for a particular year, the amount for that year is not included below).
For the Years Ended December 31,
202520242023
U.S. Federal$2,500 $650 $— 
Pennsylvania4,898 5,402 7,327 
Total Income Taxes Paid$7,398 $6,052 $7,327 
v3.25.4
ASSET RETIREMENT OBLIGATIONS
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation [Abstract]  
ASSET RETIREMENT OBLIGATIONS ASSET RETIREMENT OBLIGATIONS:
The reconciliation of changes in asset retirement obligations is as follows:
December 31,
20252024
Balance, Beginning of Year$132,064 $113,212 
Obligations Divested(1,778)(134)
Accretion Expense11,703 9,486 
Obligations Incurred9,540 2,172 
Obligations Settled(8,072)(7,475)
Revisions in Estimated Cash Flows40,669 14,803 
Balance, End of Year$184,126 $132,064 
v3.25.4
PROPERTY, PLANT AND EQUIPMENT
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
PROPERTY, PLANT AND EQUIPMENT PROPERTY, PLANT AND EQUIPMENT:
December 31,
20252024
Intangible Drilling Cost$6,755,849 $6,171,177 
Gas Gathering Equipment2,771,747 2,660,668 
Gas Wells and Related Equipment1,833,856 1,657,272 
Proved Gas Properties1,457,919 1,396,631 
Unproved Gas Properties747,528 721,692 
Surface Land and Other Equipment179,676 180,408 
Other 310,649 250,100 
Total Property, Plant and Equipment14,057,224 13,037,948 
Less: Accumulated Depreciation, Depletion and Amortization6,193,871 5,653,837 
Total Property, Plant and Equipment - Net$7,863,353 $7,384,111 

Amounts below reflect properties where drilling operations have not yet commenced and therefore were not being amortized for the years ended December 31, 2025 and 2024, respectively. These assets will be amortized using the units-of-production method and reclassified to proved gas properties when placed in service.
December 31,
20252024
Unproved Gas Properties$747,528 $721,692 
Advance Royalties1,721 2,026 
     Total$749,249 $723,718 
v3.25.4
GOODWILL AND OTHER INTANGIBLE ASSETS
 12 Months Ended
Dec. 31, 2025
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 2025, 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, 2025 and 2024.

Other Intangible Assets:

The carrying amount and accumulated amortization of other intangible assets consist of the following:
December 31,
20252024
Other Intangible Assets:
Gross Amortizable Asset - Customer Relationships$109,752 $109,752 
Less: Accumulated Amortization - Customer Relationships52,419 45,867 
Total Other Intangible Assets, net$57,333 $63,885 
The customer relationship intangible asset is being amortized on a straight-line basis over approximately 17 years. Amortization expense related to other intangible assets was $6,552 for the year ended December 31, 2025, $6,553 for the year ended December 31, 2024, and $6,552 for the year ended December 31, 2023. The estimated annual amortization expense is expected to approximate $6,552 per year for each of the next five years.
v3.25.4
REVOLVING CREDIT FACILITIES
 12 Months Ended
Dec. 31, 2025
Short-Term Debt, Other Disclosure [Abstract]  
REVOLVING CREDIT FACILITIES REVOLVING CREDIT FACILITIES:
CNX:
CNX as borrower and certain of its subsidiaries (not including CNX Midstream Partners LP (CNXM)) as guarantor loan parties entered into a Fourth Amended and Restated Credit Agreement for a senior secured revolving credit facility (the “CNX Credit Facility”), dated as of May 17, 2024 and maturing on May 17, 2029, subject to the terms described below. On May 14, 2025, the CNX Credit Facility borrowing base increased from $2,250,000 to $2,400,000 borrowing base as part of the semi-annual redetermination. Elected commitments remained unchanged at $1,400,000.

The availability under the CNX Credit Facility, 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.

In addition to refinancing all outstanding amounts under the prior CNX Credit Facility, borrowings under the CNX Credit Facility may be used by CNX for general corporate purposes.
Interest on outstanding indebtedness under the CNX Credit Facility currently accrues, at the Company’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 0.75% to 1.75%; or
•the SOFR rate plus a margin ranging from 1.85% to 2.85%.

The CNX Credit Facility matures on May 17, 2029, provided that if at any time on or after (1) January 30, 2026 (or October 31, 2025, if any debt (as defined in the CNX Credit Facility) is outstanding with a springing maturity date), if any of the Company’s 2.25% Convertible Senior Notes due 2026 are outstanding and (a) availability under the CNX Credit Facility minus (b) the aggregate principal amount of all such outstanding Convertible Senior Notes is less than 20% of the aggregate commitments under the CNX Credit Facility, or (2) October 16, 2028 (or July 17, 2028, if any debt (as defined in the CNX Credit Facility) is outstanding with a springing maturity date), if any of the Company’s 6.0% Senior Notes due 2029 are outstanding and (a) availability under the CNX Credit Facility minus (b) the aggregate principal amount of all such outstanding Senior Notes is less than 20% of the aggregate commitments under the CNX Credit Facility (the first such date, the "Springing Maturity Date”), then the CNX Credit Facility will mature on the Springing Maturity Date.

The CNX Credit Facility 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 CNXM, its subsidiaries, and its general partner. CNX was in compliance with all financial covenants as of December 31, 2025.

At December 31, 2025, the CNX Credit Facility had $200,000 of borrowings outstanding, with a weighted average interest rate of 5.69% and $27,997 of letters of credit outstanding, leaving $1,172,003 of unused capacity. At December 31, 2024, the prior CNX Credit Facility had $43,450 of borrowings outstanding with a weighted average interest rate of 6.45%, and $27,156 of letters of credit outstanding, leaving $1,329,394 of unused capacity.

CNXM:

CNXM as borrower and certain of its subsidiaries as guarantor loan parties entered into a Second Amended and Restated Credit Agreement for a senior secured revolving credit facility (the “CNXM Credit Facility"), dated as of May 17, 2024 and maturing on May 17, 2029. The CNXM Credit Facility has $600,000 of elected commitments and is not subject to semi-annual redetermination. CNX is not a guarantor under the CNXM Credit Facility.

In addition to refinancing all outstanding amounts under the prior CNXM Credit Facility, borrowings under the CNXM Credit Facility may be used by CNXM for general corporate purposes.

Interest on outstanding indebtedness under the CNXM Credit Facility 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 0.75% to 2.00%; or
•the SOFR rate plus a margin ranging from 1.85% 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 Facility. CNXM was in compliance with all financial covenants as of December 31, 2025.
At December 31, 2025, the CNXM Credit Facility had $32,750 of borrowings outstanding, with a weighted average interest rate of 5.58% and no letters of credit outstanding, leaving $567,250 of unused capacity. At December 31, 2024, the prior CNXM Credit Facility had $16,050 of borrowings outstanding, with a weighted average interest rate of 6.75% and no letters of credit outstanding, leaving $583,950 of unused capacity.
v3.25.4
OTHER ACCRUED LIABILITIES
 12 Months Ended
Dec. 31, 2025
Other Liabilities Disclosure [Abstract]  
OTHER ACCRUED LIABILITIES OTHER ACCRUED LIABILITIES:
December 31,
20252024
Royalties$121,078 $100,518 
Accrued Interest50,871 45,812 
Current Portion Settlement - See Note 1123,216 7,080 
Short-Term Incentive Compensation22,658 22,580 
Transportation Charges21,706 17,922 
Deferred Revenue14,589 20,696 
Accrued Other Taxes8,084 9,216 
Accrued Payroll & Benefits6,884 7,357 
Purchased Gas Payable554 143 
Other32,614 15,125 
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations21,075 12,875 
Salary Retirement2,647 1,908 
Total Other Accrued Liabilities$325,976 $261,232 
v3.25.4
LONG-TERM DEBT
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
LONG-TERM DEBT LONG-TERM DEBT:
December 31,
20252024
Senior Notes due March 2032 at 7.25% (Principal of $600,000 and $400,000 less Unamortized Discount of $5,160 and $4,479, respectively)
$594,840 $395,521 
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 $3,800 and $4,554, respectively)
496,200 495,446 
CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $2,500 and $3,077, respectively)*
397,500 396,923 
Convertible Senior Notes due May 2026 at 2.25% (Principal of $208,556 and $330,654 less Unamortized Discount and Issuance Costs of $425 and $2,658, respectively)
208,131 327,996 
CNX Revolving Credit Facility200,000 43,450 
CNX Midstream Partners LP Revolving Credit Facility*32,750 16,050 
Less: Unamortized Debt Issuance Costs8,062 9,386 
$2,421,359 $2,166,000 
Less: Current Portion208,095 327,766 
Long-Term Debt$2,213,264 $1,838,234 
*CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or the CNXM Credit Facility.

At December 31, 2025, 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
2026$208,556 
2027— 
2028— 
2029732,750 
2030400,000 
Thereafter1,100,000 
      Total Long-Term Debt Maturities$2,441,306 
On December 15, 2025, CNX entered into a privately negotiated exchange agreement (the “exchange agreement”) with a limited number of holders of its 2.25% Convertible Notes due May 2026 ("Convertible Notes") to exchange approximately $122,098 principal amount of Convertible Notes conversion right exercises by issuing an aggregate 9,509,188 shares of CNX common stock to the converting holders representing an average conversion price of $12.84 per share. The shares of CNX common stock issued in the transaction were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), afforded by Section 4(a)(2) of the Securities Act in transactions not involving any public offering. The exchange agreement also included additional cash consideration of approximately $855, including accrued interest. As part of the transaction, a loss of $842 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income during the year ended December 31, 2025.

During the year ended December 31, 2025, CNX issued $200,000 aggregate principal amount of additional 7.25% senior notes due 2032 (the "New Notes") at a price of 100.5% of par, plus accrued interest from September 1, 2024 to the date of closing less an underwriter discount and other issuance costs of $1,500. The New Notes were issued as additional notes under that certain indenture, dated February 23, 2024 (the "Indenture"), pursuant to which CNX previously issued $400,000 aggregate principal amount of 7.25% senior notes due 2032 (the "Initial Notes"). The New Notes are guaranteed by all of CNX's restricted subsidiaries that guarantee the CNX Credit Facility (see Note 10 – Revolving Credit Facilities) and will have identical terms as the Initial Notes, other than the issue date, the initial offering price and the first interest payment date, and the New Notes and the Initial Notes will be treated as a single class of securities under the Indenture and will vote together as a single class.

During the year ended December 31, 2024, CNX completed a private offering of $400,000 aggregate principal amount of 7.25% CNX Senior Notes due March 2032 (the "CNX Senior Notes due March 2032") less an underwriter discount and other issuance costs of $5,000. The CNX Senior Notes due March 2032, along with the related guarantees, were issued pursuant to an indenture dated February 23, 2024 and accrue interest from February 23, 2024 at a rate of 7.25% per year. Interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning on September 1, 2024. The CNX Senior Notes due March 2032 mature on March 1, 2032. Payment of the principal and interest on the notes is guaranteed by most of CNX’s subsidiaries but does not include CNXM (or its subsidiaries or general partner).

During the year ended December 31, 2024, CNX purchased and retired $350,000 aggregate principal amount of its outstanding 7.25% Senior Notes due March 2027. As part of the transaction, a loss of $7,043 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income during the year ended December 31, 2024.

In 2020, CNX issued $345,000 in aggregate principal amount of Convertible Notes due May 2026 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). In addition to the December 15, 2025 exchange discussed above, CNX had previously purchased approximately $14,346 of its outstanding Convertible Notes during the year ended December 31, 2022.

The initial conversion rate of the Convertible Notes 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. 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.

On January 28, 2026, in accordance with the indenture governing the Convertible Notes, CNX issued a notice of settlement method election for all of the outstanding Convertible Notes providing that CNX would settle any of the Convertible Notes outstanding by issuing shares of the company's common stock, together, if applicable, with cash in lieu of fractional shares, as provided for in the indenture. 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.
Before February 1, 2026, note holders had 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 called 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.

If certain corporate events that constituted a “Fundamental Change” (as defined in the indenture governing the Convertible Notes) had occurred, the noteholders may have been required by 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 included certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock.

The reported interest expense for the Convertible Notes is equal to the 2.25% cash coupon rate. Also, the Company uses the if-converted method for the assumed conversion of the Convertible Notes when calculating diluted earnings per share.

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,
20252024
Liability Component:
Principal$208,556 $330,654 
Unamortized Issuance Costs$(425)$(2,658)
Net Carrying Amount$208,131 $327,996 
Fair Value$596,798 $953,613 
Fair Value HierarchyLevel 2Level 2


Interest expense related to the Convertible Notes is as follows:
For the Years Ended December 31,
20252024
Contractual Interest Expense $7,333 $7,440 
Amortization of Issuance Costs1,922 1,928 
Total Interest Expense $9,255 $9,368 
In connection with the offering of the Convertible Notes, the Company entered into privately negotiated capped call transactions with certain counterparties (the “Capped Calls”). The Capped Calls each have an initial strike price of $12.84 per share, subject to certain adjustments, which correspond to the initial conversion price of the Convertible Notes. The Capped Calls have an initial cap price of $18.19 per share, subject to certain adjustments. The Capped Calls cover, subject to anti-dilution adjustments, the aggregate number of shares of the Company’s common stock that initially underlie the Convertible Notes, and are expected generally to reduce potential dilution to the Company’s common stock upon any conversion of Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of converted Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap, based on the cap price of the Capped Call Transactions. The conditions that cause adjustments to the initial strike price of the Capped Calls mirror the conditions that result in corresponding adjustments for the Convertible Notes. For accounting purposes, the Capped Calls are separate transactions, and not part of the terms of the Convertible Notes. As these transactions meet certain accounting criteria, the Capped Calls are recorded in stockholders’ equity and are not accounted for as derivatives. The cost of $35,673 incurred in connection with the Capped Calls was recorded as a reduction to Capital in Excess of Par Value.
v3.25.4
LEASES
 12 Months Ended
Dec. 31, 2025
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 5 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 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 2026, which is when the lease is expected to commence.
The components of lease cost were as follows:
For the Years Ended December 31,
202520242023
Operating Lease Cost$58,694 $60,572 $63,087 
Finance Lease Cost:
Amortization of Right-of-Use Assets
7,054 2,898 1,628 
Interest on Lease Liabilities
1,703 814 429 
Short-term Lease Cost3,950 1,533 2,357 
Variable Lease Cost*— 4,517 12,401 
Total Lease Cost$71,401 $70,334 $79,902 
*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. For the year ended December 31, 2025, actual utilization was below the minimum payment, resulting in no additional variable lease expense.
Amounts recognized in the Consolidated Balance Sheets are as follows:
December 31,
20252024
Operating Leases:
Operating Lease Right-of-Use Assets$150,310 $98,713 
Current Portion of Operating Lease Obligations$48,453 $51,474 
Operating Lease Obligations104,955 49,519 
Total Operating Lease Liabilities
$153,408 $100,993 
Finance Leases:
Property, Plant and Equipment$40,615 $31,751 
Less—Accumulated Depreciation, Depletion and Amortization11,735 5,539 
Property, Plant and Equipment—Net
$28,880 $26,212 
Current Portion of Finance Lease Obligations$5,095 $4,236 
Finance Lease Obligations24,991 21,040 
Total Finance Lease Liabilities
$30,086 $25,276 

Supplemental cash flow information related to leases was as follows:
For the Years Ended December 31,
202520242023
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating Cash Flows for Operating Leases$58,644 $61,475 $64,139 
Operating Cash Flows for Finance Leases$1,703 $814 $429 
Financing Cash Flows for Finance Leases$4,465 $2,409 $1,627 
Right-of-Use Assets Obtained in Exchange for Lease Obligations:
Operating Leases
$103,296 $13,996 $19,477 
Finance Leases
$9,568 $20,407 $6,178 

Maturities of lease liabilities are as follows:
OperatingFinance
LeasesLeases
Year Ended December 31,
2026$56,399 $6,874 
202749,306 6,772 
202844,983 11,158 
20296,620 2,810 
20306,624 2,293 
Thereafter7,225 6,271 
Total Lease Payments171,157 36,178 
Less: Interest17,749 6,092 
Present Value of Lease Liabilities$153,408 $30,086 
Lease terms and discount rates are as follows:
For the Years Ended December 31,
202520242023
Weighted Average Remaining Lease Term (years):
Operating Leases
3.633.663.59
Finance Leases
4.354.354.08
Weighted Average Discount Rate:
Operating Leases
6.16 %5.04 %4.84 %
Finance Leases
6.08 %6.32 %7.35 %
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 5 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 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 2026, which is when the lease is expected to commence.
The components of lease cost were as follows:
For the Years Ended December 31,
202520242023
Operating Lease Cost$58,694 $60,572 $63,087 
Finance Lease Cost:
Amortization of Right-of-Use Assets
7,054 2,898 1,628 
Interest on Lease Liabilities
1,703 814 429 
Short-term Lease Cost3,950 1,533 2,357 
Variable Lease Cost*— 4,517 12,401 
Total Lease Cost$71,401 $70,334 $79,902 
*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. For the year ended December 31, 2025, actual utilization was below the minimum payment, resulting in no additional variable lease expense.
Amounts recognized in the Consolidated Balance Sheets are as follows:
December 31,
20252024
Operating Leases:
Operating Lease Right-of-Use Assets$150,310 $98,713 
Current Portion of Operating Lease Obligations$48,453 $51,474 
Operating Lease Obligations104,955 49,519 
Total Operating Lease Liabilities
$153,408 $100,993 
Finance Leases:
Property, Plant and Equipment$40,615 $31,751 
Less—Accumulated Depreciation, Depletion and Amortization11,735 5,539 
Property, Plant and Equipment—Net
$28,880 $26,212 
Current Portion of Finance Lease Obligations$5,095 $4,236 
Finance Lease Obligations24,991 21,040 
Total Finance Lease Liabilities
$30,086 $25,276 

Supplemental cash flow information related to leases was as follows:
For the Years Ended December 31,
202520242023
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating Cash Flows for Operating Leases$58,644 $61,475 $64,139 
Operating Cash Flows for Finance Leases$1,703 $814 $429 
Financing Cash Flows for Finance Leases$4,465 $2,409 $1,627 
Right-of-Use Assets Obtained in Exchange for Lease Obligations:
Operating Leases
$103,296 $13,996 $19,477 
Finance Leases
$9,568 $20,407 $6,178 

Maturities of lease liabilities are as follows:
OperatingFinance
LeasesLeases
Year Ended December 31,
2026$56,399 $6,874 
202749,306 6,772 
202844,983 11,158 
20296,620 2,810 
20306,624 2,293 
Thereafter7,225 6,271 
Total Lease Payments171,157 36,178 
Less: Interest17,749 6,092 
Present Value of Lease Liabilities$153,408 $30,086 
Lease terms and discount rates are as follows:
For the Years Ended December 31,
202520242023
Weighted Average Remaining Lease Term (years):
Operating Leases
3.633.663.59
Finance Leases
4.354.354.08
Weighted Average Discount Rate:
Operating Leases
6.16 %5.04 %4.84 %
Finance Leases
6.08 %6.32 %7.35 %
v3.25.4
PENSION
 12 Months Ended
Dec. 31, 2025
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,
20252024
Change in Benefit Obligation:
Benefit Obligation at Beginning of Period
$31,699 $33,541 
Interest Cost
1,653 1,657 
Actuarial Loss (Gain)328 (1,696)
Benefits and Other Payments
(1,809)(1,803)
Benefit Obligation at End of Period$31,871 $31,699 
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Period
$— $— 
Company Contributions
1,809 1,803 
Benefits and Other Payments
(1,809)(1,803)
Fair Value of Plan Assets at End of Period$— $— 
Funded Status:
Current Liabilities
$(2,647)$(1,908)
Noncurrent Liabilities
(29,224)(29,791)
Net Obligation Recognized$(31,871)$(31,699)
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss
$7,402 $7,235 
Prior Service Cost399 620 
Total
7,801 7,855 
Less: Tax Benefit
2,122 2,143 
Net Amount Recognized$5,679 $5,712 
The components of the net periodic benefit cost are as follows:
For the Years Ended December 31,
 202520242023
Components of Net Periodic Benefit Cost:
Interest Cost
1,653 1,657 1,675 
Amortization of Prior Service Cost221 221 222 
Recognized Net Actuarial Loss
161 223 173 
Net Periodic Benefit Cost$2,035 $2,101 $2,070 

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,
20252024
Projected Benefit Obligation$31,871 $31,699 
Accumulated Benefit Obligation$31,871 $31,699 
Fair Value of Plan Assets$— $— 
Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:
As of December 31,
20252024
Discount Rate5.35 %5.65 %
Rate of Compensation Increase— %— %
Interest Credited Rate5.31 %5.20 %

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 weighted-average assumptions used to determine net periodic benefit cost are as follows:
For the Years ended December 31,
202520242023
Discount Rate5.65 %5.15 %5.43 %
Rate of Compensation Increase— %— %— %
Interest Credited Rate5.35 %5.04 %4.81 %
Cash Flows:
The following benefit payments, which reflect expected future service, are expected to be paid:
Pension
Year ended December 31,Benefits
2026$2,647 
2027$2,649 
2028$2,651 
2029$2,655 
2030$2,662 
Year 2031-2035$13,155 
v3.25.4
STOCK-BASED COMPENSATION
 12 Months Ended
Dec. 31, 2025
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, 2025, 3,833,203 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. RSUs vest over a three-year term. PSUs typically vest over a three-year cliff term unless otherwise noted. Special PSUs granted in August 2023 and January 2025 vest over a seven-year term. All PSUs are subject to specific performance conditions. 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, 2025, 2024 and 2023 was $23,679, $20,091 and $20,235, respectively. The related deferred tax benefit totaled $12,200, $14,243 and $6,983, respectively.

As of December 31, 2025, CNX has $37,009 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 2.48 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.
There were no options granted during the year ended December 31, 2025. The total fair value of options granted during the years ended December 31, 2024 and 2023 was $115 based on the following assumptions and weighted average fair values.
December 31,
202520242023
Weighted Average Fair Value of Grants$— $10.40 $7.06 
Risk-free Interest Rate— %4.49 %3.24 %
Expected Dividend Yield— %— %— %
Expected Forfeiture Rate— %— %— %
Expected Volatility— %41.00 %48.70 %
Expected Term in Years— 5.505.50
A summary of the status of stock options granted is presented below:
Weighted
Average
WeightedRemainingAggregate
AverageContractualIntrinsic
ExerciseTerm (inValue (in
SharesPriceyears)thousands)
Outstanding at December 31, 2024947,257 $10.48 
Exercised(267,347)$7.83 
Outstanding at December 31, 2025679,910 $11.53 2.04$17,163 
Exercisable at December 31, 2025679,910 $11.53 2.04$17,163 
At December 31, 2025, there were 311,015 employee stock options outstanding under the Equity Incentive Plan. Non-employee director stock options vest one year after the grant date. There are 368,895 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, 2025 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, 2025. 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, 2025, 2024 and 2023 was $7,362, $19,608 and $2,015, respectively.

Cash received from option exercises for the years ended December 31, 2025, 2024 and 2023 was $2,094, $2,689 and $1,760, respectively. The tax impact from option exercises totaled $1,871, $5,196 and $529 for the years ended December 31, 2025, 2024 and 2023, 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, 2025, 2024 and 2023 was $15,892, $15,810 and $16,194, respectively. The total fair value of restricted stock units vested during the years ended December 31, 2025, 2024 and 2023 was $14,607, $12,671 and $12,321, 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 ofWeighted Average
SharesGrant Date Fair Value
Nonvested at December 31, 20241,430,084 $18.60
Granted485,203 $32.75
Vested(772,947)$18.09
Forfeited(46,282)$27.68
Nonvested at December 31, 20251,096,058 $24.84
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, 2025, 2024 and 2023 was $17,951, $9,713 and $18,383, respectively. The total fair value of performance share units vested during the years ended December 31, 2025, 2024 and 2023 was $6,069, $8,002 and $4,563, 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 ofWeighted Average
SharesGrant Date Fair Value
Nonvested at December 31, 20242,655,861 $11.98
Granted760,635 $23.60
Vested(495,622)$12.25
Forfeited(58,199)$21.45
Nonvested at December 31, 20252,862,675 $14.63
v3.25.4
SUPPLEMENTAL CASH FLOW INFORMATION
 12 Months Ended
Dec. 31, 2025
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, 2025, 2024 and 2023, CNX purchased goods and services related to capital projects in the amount of $59,814, $30,905 and $28,198, respectively, which are included in accounts payable.

The following table shows cash paid:
For the Years Ended December 31,
202520242023
Interest (Net of Amounts Capitalized)$154,598 $136,263 $122,279 

As part of the acquisition of Apex Energy II, LLC (see Note 4 – Acquisitions and Dispositions for additional information), CNX was contractually required to maintain an escrow account in accordance with the terms of the purchase agreement. The escrow was established to facilitate the settlement of certain post-closing adjustments related to the transaction. As of December 31, 2025, the amount in escrow was classified as Restricted Cash on the Company’s Consolidated Balance Sheets.

In May 2025, CNX finalized the initial post-closing adjustments and based on the outcome and the expectation of no further material adjustments, recorded a short-term payable of $10,100. This payable represents the estimated final settlement amount due under the terms of the purchase agreement. The restricted cash balance will be used to satisfy this obligation. This transaction did not result in a cash outflow during the period.
v3.25.4
CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
 12 Months Ended
Dec. 31, 2025
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,
20252024
Gas Wholesalers$244,102 $151,031 
NGL, Condensate & Processing Facilities
14,665 22,404 
Other5,975 6,196 
Allowance for Credit Losses(84)(84)
Total Accounts Receivable Trade
$264,658 $179,547 
As of December 31, 2025, a receivable of $34,293 due from NRG Business Marketing LLC was included in the Gas Wholesalers balance above. As of December 31, 2024, a receivable of $15,018 due from NRG Business Marketing LLC was included. No other customers made up more than 10% of the total balances.
During the year ended December 31, 2025, sales to NRG Business Marketing LLC were $223,210, sales to DTE Energy Trading, Inc were $208,775, and sales to Citadel Energy Marketing LLC were $205,993, 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, 2024, sales to Citadel Energy Marketing LLC were $134,909 and sales to NRG Business Marketing LLC were $132,935, 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, 2023, sales to Citadel Energy Marketing LLC were $180,039 and sales to NRG 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.
v3.25.4
FAIR VALUE OF FINANCIAL INSTRUMENTS
 12 Months Ended
Dec. 31, 2025
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, 2025Fair Value Measurements at December 31, 2024
DescriptionLevel 1Level 2Level 3Level 1Level 2Level 3
Commodity Derivatives$— $(295,849)*$— $— $(536,046)**$— 
*Includes $58,387 of commodity derivatives that have been settled but not paid at December 31, 2025.
**Includes $2,309 of commodity derivatives that have been settled but not received and $23,212 that have been settled but not paid at December 31, 2024.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
 December 31, 2025December 31, 2024
 Carrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
Cash and Cash Equivalents $779 $779 $17,198 $17,198 
Restricted Cash*$12,685 $12,685 $37,875 $37,875 
Long-Term Debt (Excluding Debt Issuance Costs)$2,429,421 $2,850,144 $2,175,386 $2,785,556 
*The December 31, 2025 and 2024 restricted cash balances are located in current assets in the Consolidated Balance Sheets.

Cash and cash equivalents and restricted cash 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.
v3.25.4
DERIVATIVE INSTRUMENTS
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
DERIVATIVE INSTRUMENTS DERIVATIVE INSTRUMENTS:
CNX may enter 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. This agreement expired in March 2024.

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. In December 2020, CNX executed an offsetting $250,000 interest rate swap. 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. This agreement expired in April 2024.

CNX enters into financial derivative instruments (over-the-counter swaps) to manage its exposure to natural gas and NGL price fluctuations. 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 CNX 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
20252024Settle Through
Natural Gas Commodity Swaps (Bcf)929.8 1,163.7 2028
Natural Gas Basis Swaps (Bcf)585.5 688.7 2028
NGL Commodity Swaps (Mbbls)180.0351.02026

The gross fair value of CNX's derivative instruments was as follows:
December 31,
20252024
Current Assets:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$74,064 $45,336 
     NGL Commodity Swaps 1,730 90 
     Natural Gas Basis Swaps30,274 42,499 
Total Current Assets$106,068 $87,925 
Other Non-Current Assets:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$117,524 $117,875 
     Natural Gas Basis Swaps16,872 42,308 
Total Other Non-Current Assets$134,396 $160,183 
Current Liabilities:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$323,169 $300,994 
     NGL Commodity Swaps— 839 
     Natural Gas Basis Swaps54,776 52,788 
Total Current Liabilities$377,945 $354,621 
Non-Current Liabilities:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$101,387 $364,662 
     Natural Gas Basis Swaps56,981 64,871 
Total Non-Current Liabilities$158,368 $429,533 
The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows:
For the Years Ended December 31,
202520242023
Realized (Loss) Gain on Commodity Derivative Instruments:
   Natural Gas Commodity Swaps$(188,791)$275,672 $62,567 
   Natural Gas Basis Swaps7,208 4,900 98,582 
   NGL Commodity Swaps563 623 1,877 
Total Realized (Loss) Gain on Commodity Derivative Instruments(181,020)*281,195 **163,026 ***
Unrealized Gain (Loss) on Commodity Derivative Instruments:
   Natural Gas Commodity Swaps306,779 (286,567)1,858,060 
   Natural Gas Basis Swaps(31,180)(165,566)(93,222)
   NGL Commodity Swaps2,082 (1,467)788 
Total Unrealized Gain (Loss) on Commodity Derivative Instruments277,681 (453,600)1,765,626 
Gain (Loss) on Commodity Derivative Instruments:
   Natural Gas Commodity Swaps117,988 (10,895)1,920,627 
   Natural Gas Basis Swaps(23,972)(160,666)5,360 
   NGL Commodity Swaps2,645 (844)2,665 
Total Gain (Loss) on Commodity Derivative Instruments$96,661 $(172,405)$1,928,652 
*Includes $58,387 that have been settled but not paid at December 31, 2025, and excludes $2,309 of commodity derivatives that have been settled but not received and $23,212 that have been settled but not paid at December 31, 2024.
**Includes $2,309 of commodity derivatives that have been settled but not received and $23,212 that have been settled but not paid at December 31, 2024, and excludes $6,741 of commodity derivatives that have been settled but not received and $900 that have been settled but not paid at December 31, 2023.
***Includes $6,741 of commodity derivatives that were settled but not received and $900 that have been settled but not paid at December 31, 2023, and excludes $77,662 of commodity 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,
202520242023
Cash Received in Settlement of Interest Rate Swaps$— $1,103 $4,207 
Unrealized Loss on Interest Rate Swaps— (1,099)(3,463)
Gain on Interest Rate Swaps$— $4 $744 
    
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.
v3.25.4
COMMITMENTS AND CONTINGENT LIABILITIES
 12 Months Ended
Dec. 31, 2025
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 Core Natural Resources, Inc., the successor by merger to CONSOL Energy (“Core”) 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 Core in federal court contending that the Sold Subsidiaries were last signatory operators and that CNX and Core are related persons to the Sold Subsidiaries and, as such, CNX and Core are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The 1992 Benefit Plan seeks, among other relief, a declaration that CNX and Core are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 plan; that CNX and Core are liable to post the security required by Section 9712; and, that CNX and Core 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 CNX and Core are now defending this action on the merits. Further, under the Separation and Distribution Agreement ("SDA") that was entered into at the time CNX spun-out its coal business in 2017, Core 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 ("1974 Plan") requesting information related to the facts and circumstances surrounding the 2013 sale of certain of its coal subsidiaries to Murray Energy. The letter indicated that litigation related to potential withdrawal liabilities from the plan created by the 2019 bankruptcy of Murray Energy was reasonably foreseeable and at that time, no liability had been assessed. The 1974 Plan never issued an assessment to CNX. Following a period of discovery, CNX and the 1974 Plan mediated the claim in February 2024. By agreement dated March 4, 2024, CNX settled the 1974 Plan claim for $75,000 which is payable over five-years with the initial payment made at the end of March 2024. Under the SDA, Core became successor-in-interest to the “Coal Business” and accepted and agreed to assume and be responsible for all “Coal Liabilities.” The assumed “Coal Liabilities” are defined broadly in the SDA and specifically include claims, like the 1974 Plan claim, arising under ERISA; involving contributions or other obligations pursuant to any Benefits Plan; and any withdraw liabilities. Core also unequivocally agreed to defend and indemnify CNX for all liabilities relating to, arising out of or resulting from any “Coal Liabilities.” CNX timely tendered the 1974 Plan claim to Core for defense and indemnity in July 2021, which it denied. CNX continued to demand indemnity from Core including prior to, during and after the March 2024 mediation. After Core repudiated its contractual obligations to CNX, and after having timely fulfilled all SDA prerequisites for bringing the action, on March 7, 2024, CNX sued Core for breach of contract seeking an order requiring Core to indemnify CNX for the 1974 Plan claim settlement. On November 8, 2024, the court granted CNX’s Motion for Partial Summary Judgment (the “Summary Judgment Grant”), finding that Core is obligated to indemnify CNX for its settlement of the 1974 Plan claim and to reimburse CNX for its attorney’s fees and costs to defend and resolve the underlying 1974 Plan claim. As of December 31, 2025, Core has reimbursed CNX for all settlement payments made to the 1974 Plan, plus interest. The present value of the $75,000 settlement, less payments made, is recognized in Other Liabilities in the Consolidated Balance Sheets as of December 31, 2025, with the current portion recognized in Other Accrued Liabilities. A corresponding receivable, less payments received, is recognized in Other Non-Current assets in the Consolidated Balance Sheets as of December 31, 2025, with the current portion recognized in Other Receivables, net. These balances may be adjusted from time to time, as appropriate, to reflect changes in circumstances.

At December 31, 2025, 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
Amounts
Committed		Less Than
1  Year		1-3 Years3-5 YearsBeyond
5  Years
Letters of Credit:
Firm Transportation$25,077 $25,077 $— $— $— 
Other2,920 2,920 — — — 
Total Letters of Credit27,997 27,997 — — — 
Surety Bonds:
Employee-Related2,250 2,250 — — — 
Environmental40,005 40,005 — — — 
Firm Transportation129,336 129,336 — — — 
Financial Guarantees93,000 93,000 — — — 
Other12,957 12,957 — — — 
Total Surety Bonds277,548 277,548 — — — 
Other Guarantees2,887 707 1,414 766 — 
Total Commitments$308,432 $306,252 $1,414 $766 $— 

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 Core 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 Core 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, 2025, the purchase obligations for each of the next five years and beyond are as follows:
Obligations DueAmount
Less than 1 year$270,869 
1 - 3 years479,607 
3 - 5 years273,803 
More than 5 years457,473 
Total Purchase Obligations$1,481,752 
v3.25.4
SEGMENT INFORMATION
 12 Months Ended
Dec. 31, 2025
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.
Operating segments are components of an enterprise for which discrete financial information is available and regularly evaluated by the Chief Operating Decision Maker (CODM) for resource allocation and performance assessment. The Company's CODM is its Chief Executive Officer. The Company’s segment structure reflects the financial information and reports used by the CODM to make decisions regarding the Company’s business, including resource allocations and performance assessments, as well as the current operating focus.
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 conduct 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, sales of environmental attributes, as well as various other expenses that are managed outside the reportable segments as discussed below.
The CODM evaluates the performance of the Company’s reportable segments using Income (Loss) Before Income Tax to assess segment performance primarily by comparing it across segments for the current period as well as for prior periods. Income (Loss) Before Income Tax for each segment is based on revenue less identifiable operating and non-operating expenses. Certain expenses are managed outside the reportable segments and therefore are not allocated. These expenses include, but are not limited to, interest expense, other operating expense, and other corporate expenses such as selling, general and administrative costs.
Reportable segment results for the year ended December 31, 2025 are:
For the year ended December 31, 2025
ShaleCoalbed
Methane		OtherConsolidated
Natural Gas, NGLs and Oil Revenue$1,763,961 $148,017 $1,750 $1,913,728 (A)
(Loss) Gain on Commodity Derivative Instruments(169,598)(11,354)277,613 96,661 
Purchased Gas Revenue— — 45,349 45,349 
Other Revenue and Operating Income69,169 — 114,227 183,396 (B)
Total Revenue and Other Operating Income $1,663,532 $136,663 $438,939 $2,239,134 
Lease Operating Expense73,302 24,043 71 97,416 
Transportation, Gathering and Compression317,424 63,869 1,811 383,104 
Production, Ad Valorem, and Other Fees24,749 6,412 39 31,200 
Depreciation, Depletion and Amortization488,021 59,188 26,905 574,114 
Interest Expense— — 170,592 170,592 
Other Segment Items — — 179,767 179,767 
Total Costs and Expenses$903,496 $153,512 $379,185 $1,436,193 
Income (Loss) Before Income Tax$760,036 $(16,849)$59,754 $802,941 
(A) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $223,210 to NRG Business Marketing LLC, $208,775 to DTE Energy Trading, Inc, and $205,993 to Citadel Energy Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(B) Includes midstream revenue of $69,169 and equity in loss of unconsolidated affiliates of $740 for Shale and Other, respectively. Other also includes sales of environmental attributes of $77,829.
Other Segment Disclosures
For the year ended December 31, 2025
ShaleCoalbed
Methane		OtherConsolidated
Segment Assets$7,218,019 $909,304 $967,123 $9,094,446 (C)
Capital Expenditures$443,714 $44,628 $6,646 $494,988 
(C) Includes investments in unconsolidated equity affiliates of $5,709.
Reportable segment results for the year ended December 31, 2024 are:
For the year ended December 31, 2024
ShaleCoalbed
Methane		OtherConsolidated
Natural Gas, NGLs and Oil Revenue$1,080,044 $105,119 $914 $1,186,077 (D)
Gain (Loss) on Commodity Derivative Instruments260,395 20,675 (453,475)(172,405)
Purchased Gas Revenue— — 59,467 59,467 
Other Revenue and Operating Income68,308 — 125,339 193,647 (E)
Total Revenue and Other Operating Income (Loss)$1,408,747 $125,794 $(267,755)$1,266,786 
Lease Operating Expense48,079 21,997 570 70,646 
Transportation, Gathering and Compression316,167 64,620 1,433 382,220 
Production, Ad Valorem, and Other Fees22,036 5,459 59 27,554 
Depreciation, Depletion and Amortization405,292 59,590 20,872 485,754 
Interest Expense— — 150,594 150,594 
Other Segment Items — — 270,380 270,380 
Total Costs and Expenses$791,574 $151,666 $443,908 $1,387,148 
Income (Loss) Before Income Tax$617,173 $(25,872)$(711,663)$(120,362)
(D) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $134,909 to Citadel Energy Marketing LLC and $132,935 to NRG Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(E) Includes midstream revenue of $68,308 and equity in loss of unconsolidated affiliates of $1,314 for Shale and Other, respectively. Other also
includes sales of environmental attributes of $95,490.
For the year ended December 31, 2024
Other Segment DisclosuresShaleCoalbed
Methane		OtherConsolidated
Segment Assets$6,669,076 $920,742 $922,085 $8,511,903 (F)
Capital Expenditures$495,538 $29,329 $15,465 $540,332 
(F) Includes investments in unconsolidated equity affiliates of $18,380.

Reportable segment results for the year ended December 31, 2023 are:

For the year ended December 31, 2023
ShaleCoalbed
Methane		OtherConsolidated
Natural Gas, NGLs and Oil Revenue$1,170,393 $130,763 $1,062 $1,302,218 (G)
Gain on Commodity Derivative Instruments151,408 11,554 1,765,690 1,928,652 
Purchased Gas Revenue— — 74,218 74,218 
Other Revenue and Operating Income66,559 — 63,301 129,860 (H)
Total Revenue and Other Operating Income$1,388,360 $142,317 $1,904,271 $3,434,948 
Lease Operating Expense43,740 19,942 (349)63,333 
Transportation, Gathering and Compression315,653 65,470 811 381,934 
Production, Ad Valorem, and Other Fees21,636 6,244 66 27,946 
Depreciation, Depletion and Amortization365,020 50,052 18,514 433,586 
Interest Expense— — 143,278 143,278 
Other Segment Items — — 161,946 161,946 
Total Costs and Expenses$746,049 $141,708 $324,266 $1,212,023 
Income Before Income Tax$642,311 $609 $1,580,005 $2,222,925 
(G) 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, each of which comprises over 10% of revenue from contracts with external customers for the period.
(H) 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.
For the year ended December 31, 2023
Other Segment DisclosuresShaleCoalbed
Methane		OtherConsolidated
Segment Assets$6,656,655 $948,795 $1,021,207 $8,626,657 (I)
Capital Expenditures$629,631 $36,804 $12,969 $679,404 
(I) Includes investments in unconsolidated equity affiliates of $13,682.
Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Operating Income:
For the Years Ended December 31,
202520242023
Total Segment Revenue from Contracts with External Customers$2,028,246 $1,313,852 $1,442,995 
Gain (Loss) on Commodity Derivative Instruments96,661 (172,405)1,928,652 
Other Operating Income114,227 125,339 63,301 
Total Consolidated Revenue and Other Operating Income
$2,239,134 $1,266,786 $3,434,948 
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited)
 12 Months Ended
Dec. 31, 2025
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,
20252024
Intangible Drilling Costs$6,755,849 $6,171,177 
Gas Gathering Assets2,771,747 2,660,668 
Proved Gas Properties1,457,919 1,396,631 
Unproved Gas Properties747,528 721,692 
Gas Wells and Related Equipment1,833,856 1,657,272 
Other Gas Assets186,346 136,138 
Total Property, Plant and Equipment13,753,245 12,743,578 
Accumulated Depreciation, Depletion and Amortization(6,091,349)(5,561,023)
Net Capitalized Costs$7,661,896 $7,182,555 

Costs incurred for property acquisition, exploration and development (*):
For the Years Ended December 31,
202520242023
Property Acquisitions (a)
Proved Properties (b)$534,229 $10,362 $2,319 
Unproved Properties (c)49,118 15,061 26,405 
Development (d)432,082 500,402 637,711 
Exploration6,806 4,494 4,257 
Total$1,022,235 $530,319 $670,692 
__________
(a)    Includes costs incurred whether capitalized or expensed.
(b)    Amounts in 2025 include $523,256 for proved properties acquired in the Apex Transaction (See Note 4 – Acquisitions and Dispositions).
(c)    Amounts in 2025 include $3,200 for unproved properties acquired in the Apex Transaction (See Note 4 – Acquisitions and Dispositions).
(d)    Includes development costs for midstream of $37,669, $23,135 and $46,814 for the years ended December 31, 2025, 2024 and 2023, respectively.
Results of Operations for Producing Activities:
For the Years Ended December 31,
202520242023
Natural Gas, NGLs and Oil Revenue$1,913,728 $1,186,077 $1,302,218 
Realized Gain (Loss) on Commodity Derivative Instruments (181,020)281,195 163,026 
Unrealized (Loss) Gain on Commodity Derivative Instruments277,681 (453,600)1,765,626 
Purchased Gas Revenue45,349 59,467 74,218 
Total Revenue2,055,738 1,073,139 3,305,088 
Lease Operating Expense97,416 70,646 63,333 
Production, Ad Valorem and Other Fees31,200 27,554 27,946 
Transportation, Gathering and Compression383,104 382,220 381,934 
Purchased Gas Costs42,647 57,248 69,924 
Exploration Costs10,516 8,446 10,447 
Depreciation, Depletion and Amortization574,114 485,754 433,586 
Total Costs1,138,997 1,031,868 987,170 
Pre-tax Operating Income916,741 41,271 2,317,918 
Income Tax Expense193,432 10,235 523,849 
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$723,309 $31,036 $1,794,069 
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,
202520242023
Production (MMcfe)628,960 550,814 560,366 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$3.04 $2.15 $2.32 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$(0.31)$0.57 $0.32 
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$2.75 $2.66 $2.61 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.15 $0.13 $0.11 
During the years ended December 31, 2025, 2024 and 2023, the Company drilled 18.9, 25.7, and 30.8 net development wells, respectively. There were no net dry development wells in 2025, 2024 or 2023.
There were no net exploratory wells drilled during the years ended December 31, 2025, 2024 or 2023. There were no net dry exploratory wells in 2025, 2024 or 2023.
As of December 31, 2025, there were 10.00 net development wells and no exploratory wells drilled but uncompleted.
CNX is committed to provide 658.7 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, 2025, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,560 4,488 
Producing Oil Wells - Working Interest2 — 
Producing Gas Wells - Royalty Interest412 — 
Producing Oil Wells - Royalty Interest128 — 
Acreage Position:
   Proved Developed Acreage428,042 428,042 
   Proved Undeveloped Acreage26,092 26,092 
   Unproved Acreage4,946,079 3,517,208 
Total Acreage5,400,213 3,971,342 
____________
(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 oil and natural gas reserves estimates is completed in accordance with CNX prescribed internal control procedures, which include verification of input data into 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 21 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, 2025 in this 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 22 years of experience in the oil and gas industry.
The oil and gas reserves estimates are as follows:
CondensateConsolidated
Natural GasNGLs& Crude OilOperations
(MMcf)(Mbbls)(Mbbls)(MMcfe)
Balance December 31, 2022 (a)9,187,278 100,153 3,115 9,806,890 
Revisions (b)(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 
Revisions (c)(634,288)1,921 (356)(624,896)
Price Changes(237,036)(6,707)(569)(280,692)
Extensions and Discoveries (e)1,092,556 30,465 112 1,276,018 
Production(496,922)(8,825)(157)(550,814)
Sales of Reserves In-Place(18,377)(644)(29)(22,415)
Balance December 31, 2024 (a)7,628,925 150,921 582 8,537,943 
Revisions (d)28,065 6,812 20 69,057 
Price Changes167,939 466 2 170,747 
Extensions and Discoveries (e)758,540 17,816 250 866,936 
Production(580,600)(7,907)(153)(628,960)
Purchases of Reserves In-Place (f)667,993 — — 667,993 
Sales of Reserves In-Place(21,512)(8)(2)(21,572)
Balance December 31, 2025 (a)8,649,350 168,100 699 9,662,144 
Proved developed reserves:
December 31, 20235,521,437 83,682 706 6,027,762 
December 31, 20245,418,858 112,884 582 6,099,654 
December 31, 20256,263,162 117,613 595 6,972,410 
Proved undeveloped reserves:
December 31, 20232,401,555 51,029 875 2,712,980 
December 31, 20242,210,067 38,037 — 2,438,289 
December 31, 20252,386,188 50,487 104 2,689,734 
__________
(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 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.
(c)    The downward revisions in 2024 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 189 Bcfe being removed. Additional downward revisions of 284 Bcfe are due to the wells not being developed within five years of their original booking. Additionally, there were negative revisions of 65 Bcfe due to performance and 87 Bcfe due to wells that that were uneconomic.
(d)    The upward revisions in 2025 are partly due to 104 Bcfe increase as a result of performance revisions. Additional downward revisions of 1.9 Bcfe are due to wells being plugged and abandoned or are shut-in and are awaiting to be plugged and abandoned. Additionally, we removed a single well for plan changes which resulted in a decrease of 33 Bcfe.
(e)    Extensions and Discoveries in 2023, 2024, and 2025 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, operated assets and exploratory wells. In 2025, 2024, and 2023, the Company added 55 Bcfe, 252 Bcfe, and 42 Bcfe, respectively, related to exploratory and non-operated wells.
(f)    Purchases of Reserves-In-Place in 2025 are associated with our acquisition of Apex Energy which resulted in the addition of 668 Bcfe of natural gas reserves.
For the Year
Ended
December 31,
2025
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves2,438,289 
Undeveloped Reserves Transferred to Developed (a)(625,068)
Price Revisions3,298 
Revisions Due to Plan Changes (b)(33,007)
Revisions Due to Changes Related to Well Performance (c)106,465 
Revisions Due to 5 Year Rule— 
Extension and Discoveries (d)799,757 
Ending Proved Undeveloped Reserves(e)2,689,734 
_________
(a)    During 2025, various development drilling and evaluations were completed. Approximately, $183,031 of capital was spent in the year ended December 31, 2025 related to undeveloped reserves that were transferred to developed.
(b)    The downward revisions for 2025 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 33 Bcfe being removed.
(c)    The upward revision of 106 Bcfe are from positive performance revisions.
(d)    Extensions and Discoveries are due mainly to the addition of 549 Bcfe related to 20 Marcellus wells within our Southwest Pennsylvania, West Virginia and Central Pennsylvania operations and 250 Bcfe related to 13 Utica wells within our Southwest Pennsylvania and Central 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, 2025 are approximately 320 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.
During the years ended December 31, 2025, 2024 and 2023, there have been no additions, reclassifications or capitalization of suspended exploratory well costs.
CNX proved natural gas reserves are located in the United States.
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,
202520242023
Future Cash Flows (a)
Revenues
$29,123,088 $17,997,427 $20,281,496 
Production Costs
(10,413,538)(8,034,256)(8,515,152)
Development Costs (b)(2,221,264)(1,743,442)(1,903,477)
Income Tax Expense
(4,191,554)(2,083,504)(2,507,151)
Future Net Cash Flows12,296,732 6,136,225 7,355,716 
Discounted to Present Value at a 10% Annual Rate(7,230,426)(3,297,503)(4,245,681)
Total Standardized Measure of Discounted Net Cash Flows$5,066,306 $2,838,722 $3,110,035 
_________
(a)    For 2025, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2025, adjusted for energy content and a regional price differential. For 2025, this adjusted natural gas price was $2.98 per Mcf, the adjusted oil/condensate price was $53.80 per barrel and the adjusted NGL price was $19.93 per barrel.

For 2024, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2024, adjusted for energy content and a regional price differential. For 2024, this adjusted natural gas price was $2.00 per Mcf, the adjusted oil/condensate price was $63.13 per barrel and the adjusted NGL price was $17.92 per barrel.

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.

(b)    Development costs for 2025 include $1,017,263 of plugging and abandonment costs and $156,884 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $70,241 and $133,319, respectively.

Development costs for 2024 include $705,070 of plugging and abandonment costs and $160,868 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $94,169 and $131,711, respectively.

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.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202520242023
Balance at Beginning of Period$2,838,722 $3,110,035 $10,762,699 
Net Changes in Sales Prices and Production Costs3,615,935 (506,616)(10,722,238)
Sales Net of Production Costs(1,220,988)(986,852)(992,030)
Net Change Due to Revisions in Quantity Estimates46,181 (229,940)(155,807)
Net Change Due to Extensions, Discoveries and Improved Recovery432,682 197,972 32,876 
Development Costs Incurred During the Period432,082 500,402 637,711 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period(129,837)(72,232)(149,770)
Changes in Estimated Future Development Costs(249,185)(183,359)(211,592)
Net Change in Future Income Taxes(775,898)102,450 2,647,842 
Accretion351,409 395,680 1,403,417 
Timing and Other(274,797)511,182 (143,073)
     Total Discounted Cash Flow at End of Period$5,066,306 $2,838,722 $3,110,035 
Note: Table excludes unrealized gain/loss on commodity derivative instruments.
v3.25.4
Schedule II - Valuation and Qualifying Accounts
 12 Months Ended
Dec. 31, 2025
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)

AdditionsDeductions
Balance atRelease ofBalance at
BeginningCharged toValuationCharged toEnd
of PeriodExpenseAllowanceExpenseof Period
Year Ended December 31, 2025
State Operating Loss Carry-Forwards$36,879 $— $— $(4,617)$32,262 
            Total$36,879 $— $— $(4,617)$32,262 
Year Ended December 31, 2024
State Operating Loss Carry-Forwards$39,264 $— $— $(2,385)$36,879 
            Total$39,264 $— $— $(2,385)$36,879 
Year Ended December 31, 2023
State Operating Loss Carry-Forwards$76,871 $— $— $(37,607)$39,264 
Foreign Tax Credits7,738 — (7,738)— — 
            Total$84,609 $— $(7,738)$(37,607)$39,264 
v3.25.4
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2025
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
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
Risk Management and Strategy

The Company recognizes the risk that cybersecurity threats pose to our operations and considers cybersecurity an integral component of our overall risk management strategy. We have adopted the U.S. Department of Commerce’s National Institute of Standards and Technology (NIST) Cybersecurity Framework to guide our cybersecurity program.

CNX’s cybersecurity team includes executive officers and dedicated cybersecurity personnel. The team is led by our Vice President Chief Information and Technology Officer, who has approximately 30 years of technical leadership and cybersecurity expertise, and multiple cybersecurity engineers. The team is staffed by professionals with deep cybersecurity expertise across multiple industries, the team takes a cross-functional approach to addressing risks and engages in discussions with the Board of Directors and executive management as needed.

We have developed a written incident response plan (IRP) that delineates the procedures to be followed for handling a variety of cybersecurity incidents; categorizes potential cybersecurity incidents and the required timeframe for reporting each; establishes cybersecurity incident response levels; provides for the conducting of legally privileged investigations designed to enable us to meet applicable legal obligations, including possible notification requirements; and outlines the roles and responsibilities for various personnel in the event of a cybersecurity incident.

We have also established a vulnerability management program to address the identification, prioritization, and remediation of potential cybersecurity vulnerabilities. These procedures allocate responsibility among various members of our cybersecurity team to detect vulnerabilities, assess their urgency, backup appropriate systems, and prioritize, select, test, and verify remediation methods. We hold vulnerability management meetings with our internal technical and business partners and regularly review these procedures.

Third parties also play a role in the Company’s cybersecurity processes and its associated risk management framework. CNX leverages substantial technological tools and partners to augment and enable the efforts of its internal cybersecurity team. Separately, management and oversight of the risks from cybersecurity threats associated with our engagement of third-party service providers are currently included in our internal auditing procedures and we have plans to further mature these procedures in the current fiscal year.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] The Company recognizes the risk that cybersecurity threats pose to our operations and considers cybersecurity an integral component of our overall risk management strategy. We have adopted the U.S. Department of Commerce’s National Institute of Standards and Technology (NIST) Cybersecurity Framework to guide our cybersecurity program.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
The Board, in coordination with the ESCR Committee, is responsible for the oversight of risks from cybersecurity threats. The responsibilities of the ESCR Committee include overseeing policies and management systems for cybersecurity matters and reviewing CNX’s strategy, objectives, and policies relative to cybersecurity. In addition, the Board and the ESCR Committee receive regular presentations and reports on cybersecurity risks that address a wide range of topics, including recent developments, personnel changes, discussion of testing and vulnerability assessment efforts, technological trends or tools, third party updates, and regulatory standards. The CNX IRP calls for prompt and timely direct notifications and updates to the Board (or its committees) as necessary in connection with potentially significant cybersecurity incidents that may occur. On a periodic basis, the Board and the ESCR Committee discuss our approach to cybersecurity with our Vice President - Chief Information and Technology Officer.

Management’s role in assessing and managing our material risks from cybersecurity threats, as well as making final materiality determinations and disclosures and other compliance decisions, is documented in the CNX IRP, and our processes for identifying, prioritizing, and remediating vulnerabilities are documented via the Company’s vulnerability management program procedures. In connection with and pursuant to the IRP, our dedicated incident response team works collaboratively
across CNX to carry out a program that has been designed to protect our information system from cybersecurity threats, assess and manage risks arising from any such threats, and to promptly respond to potential cybersecurity incidents.
To date, there have been no risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, which have materially affected, or have been reasonably likely to materially affect, the Company, including our business strategy, results of operations or financial condition. Notwithstanding the approach we take to cybersecurity, we may not be successful in preventing or mitigating a cybersecurity incident that could have a material adverse effect on us. While CNX maintains cybersecurity insurance, the costs related to cybersecurity threats or incidents may not be fully insured. For more information on our cybersecurity related risks, see Item 1A. Risk Factors of this Form 10-K.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Board, in coordination with the ESCR Committee, is responsible for the oversight of risks from cybersecurity threats.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] The responsibilities of the ESCR Committee include overseeing policies and management systems for cybersecurity matters and reviewing CNX’s strategy, objectives, and policies relative to cybersecurity. In addition, the Board and the ESCR Committee receive regular presentations and reports on cybersecurity risks that address a wide range of topics, including recent developments, personnel changes, discussion of testing and vulnerability assessment efforts, technological trends or tools, third party updates, and regulatory standards. The CNX IRP calls for prompt and timely direct notifications and updates to the Board (or its committees) as necessary in connection with potentially significant cybersecurity incidents that may occur. On a periodic basis, the Board and the ESCR Committee discuss our approach to cybersecurity with our Vice President - Chief Information and Technology Officer.
Cybersecurity Risk Role of Management [Text Block] The responsibilities of the ESCR Committee include overseeing policies and management systems for cybersecurity matters and reviewing CNX’s strategy, objectives, and policies relative to cybersecurity. In addition, the Board and the ESCR Committee receive regular presentations and reports on cybersecurity risks that address a wide range of topics, including recent developments, personnel changes, discussion of testing and vulnerability assessment efforts, technological trends or tools, third party updates, and regulatory standards. The CNX IRP calls for prompt and timely direct notifications and updates to the Board (or its committees) as necessary in connection with potentially significant cybersecurity incidents that may occur. On a periodic basis, the Board and the ESCR Committee discuss our approach to cybersecurity with our Vice President - Chief Information and Technology Officer.
Management’s role in assessing and managing our material risks from cybersecurity threats, as well as making final materiality determinations and disclosures and other compliance decisions, is documented in the CNX IRP, and our processes for identifying, prioritizing, and remediating vulnerabilities are documented via the Company’s vulnerability management program procedures. In connection with and pursuant to the IRP, our dedicated incident response team works collaboratively
across CNX to carry out a program that has been designed to protect our information system from cybersecurity threats, assess and manage risks arising from any such threats, and to promptly respond to potential cybersecurity incidents.
To date, there have been no risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, which have materially affected, or have been reasonably likely to materially affect, the Company, including our business strategy, results of operations or financial condition. Notwithstanding the approach we take to cybersecurity, we may not be successful in preventing or mitigating a cybersecurity incident that could have a material adverse effect on us. While CNX maintains cybersecurity insurance, the costs related to cybersecurity threats or incidents may not be fully insured. For more information on our cybersecurity related risks, see Item 1A. Risk Factors of this Form 10-K.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
The Board, in coordination with the ESCR Committee, is responsible for the oversight of risks from cybersecurity threats. The responsibilities of the ESCR Committee include overseeing policies and management systems for cybersecurity matters and reviewing CNX’s strategy, objectives, and policies relative to cybersecurity. In addition, the Board and the ESCR Committee receive regular presentations and reports on cybersecurity risks that address a wide range of topics, including recent developments, personnel changes, discussion of testing and vulnerability assessment efforts, technological trends or tools, third party updates, and regulatory standards. The CNX IRP calls for prompt and timely direct notifications and updates to the Board (or its committees) as necessary in connection with potentially significant cybersecurity incidents that may occur. On a periodic basis, the Board and the ESCR Committee discuss our approach to cybersecurity with our Vice President - Chief Information and Technology Officer.

Management’s role in assessing and managing our material risks from cybersecurity threats, as well as making final materiality determinations and disclosures and other compliance decisions, is documented in the CNX IRP, and our processes for identifying, prioritizing, and remediating vulnerabilities are documented via the Company’s vulnerability management program procedures. In connection with and pursuant to the IRP, our dedicated incident response team works collaboratively
across CNX to carry out a program that has been designed to protect our information system from cybersecurity threats, assess and manage risks arising from any such threats, and to promptly respond to potential cybersecurity incidents.
To date, there have been no risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, which have materially affected, or have been reasonably likely to materially affect, the Company, including our business strategy, results of operations or financial condition. Notwithstanding the approach we take to cybersecurity, we may not be successful in preventing or mitigating a cybersecurity incident that could have a material adverse effect on us. While CNX maintains cybersecurity insurance, the costs related to cybersecurity threats or incidents may not be fully insured. For more information on our cybersecurity related risks, see Item 1A. Risk Factors of this Form 10-K.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]
CNX’s cybersecurity team includes executive officers and dedicated cybersecurity personnel. The team is led by our Vice President Chief Information and Technology Officer, who has approximately 30 years of technical leadership and cybersecurity expertise, and multiple cybersecurity engineers. The team is staffed by professionals with deep cybersecurity expertise across multiple industries, the team takes a cross-functional approach to addressing risks and engages in discussions with the Board of Directors and executive management as needed.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] In addition, the Board and the ESCR Committee receive regular presentations and reports on cybersecurity risks that address a wide range of topics, including recent developments, personnel changes, discussion of testing and vulnerability assessment efforts, technological trends or tools, third party updates, and regulatory standards.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES (Policies)
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Basis of Consolidation
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
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, and the fair value of derivative instruments.
Cash and Cash Equivalents and Restricted Cash
Cash and Cash Equivalents:
Cash and cash equivalents of $779 and $17,198 as of December 31, 2025 and 2024, respectively, includes 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.
Restricted Cash:
Restricted cash of $12,685 and $37,875 as of December 31, 2025 and 2024, respectively, consists of funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire the natural gas upstream and associated midstream business of Apex Energy II, LLC, as well as, funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire various rights-of-way, surface acreage and other oil and gas royalty interests from a third party. See Note 4 – Acquisitions and Dispositions for more information.
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:
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
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 $458,335, $378,646, and $332,596 for the years ended December 31, 2025, 2024 and 2023, 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 ImprovementsLife 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:

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. There were no indicators of impairment related to long-lived assets in the years ended December 31, 2025 or 2024.

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. There were no indicators of impairment related to the Company's proved oil and gas properties in the years ended December 31, 2025 or 2024.
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. There were no indicators of impairment related to the Company’s unproved properties in the years ended December 31, 2025 or 2024.
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 2025, 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.
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
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:
CNX has an investment plan that is available to most employees. Throughout the years ended December 31, 2025, 2024 and 2023, 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).
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:
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
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 2025, the FASB issued Accounting Standards Update (ASU) 2025-11 - Interim Reporting - Narrow-Scope Improvements. The amendments in this ASU clarify interim disclosure requirements and the applicability of Topic 270. It does not fundamentally change the nature of interim reporting or expand/reduce disclosure requirements but makes the guidance easier to navigate and apply. This ASU compiles as list of required interim disclosures from across the GAAP Codification into ASC 270, making it easier for preparers to identify what disclosures are required for interim periods. The amendments in this ASU are effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. The Company is still evaluating the impact of the adoption of this ASU.

In July 2025, the FASB issued ASU 2025-05 Financial Instruments - Credit Losses- Measurement of Credit Losses for Accounts Receivable and Contract Assets. This ASU amends the current expected credit loss (CECL) model for current accounts receivable and contract assets arising from transactions accounted for under Topic 606. In developing reasonable and supportable forecasts as part of estimating expected credit losses, a practical expedient may be elected that assumes the current conditions of the balance sheet date do not change for the remaining life of the asset. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods. The Company is still evaluating the impact of the adoption of this ASU and does not expect this ASU to have a material impact on our consolidated financial statements.

In November 2024, the FASB issued ASU 2024-04 - Debt with Conversion and Other Options (Subtopic 470-20). This ASU clarifies the requirements related to accounting for the settlement of a debt instrument as an induced conversion. An induced conversion is when a Company induces debt holders to convert their debt into equity shares under changed terms and involved additional consideration. The amendments in this ASU are effective for all entities for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. Early adoption is permitted for all entities that have adopted the amendments in ASU 2020-06. The Company does not anticipate a material impact from this ASU given the maturity schedule of CNX’s Convertible Notes. See Note 12 – Long-Term Debt for more information.

In November 2024, the FASB issued ASU 2024-03 - Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40). This ASU requires entities to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations into the following required natural expense categories within the footnotes, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) DD&A recognized as part of oil- and gas-producing activities or other depletion expenses. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is still evaluating the impact of the adoption of this ASU.

See Note 6 – Income Taxes for the impact of adoption of ASU 2023-09 - Income Taxes (Topic 740): Improvements to Income Tax Disclosures.
Reclassifications
Reclassifications:

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2025, with no effect on previously reported net income, stockholders' equity or statement of cash flows.
Subsequent Events
Subsequent Events:
The Company has evaluated all subsequent events through the date the financial statements were issued.
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES (Tables)
 12 Months Ended
Dec. 31, 2025
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,
20252024
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$1,233 $2,847 
Recoveries Collected— (1,692)
Provision for Expected Credit Losses131 186 
Write-off of Uncollectible Accounts(327)(108)
Allowance for Credit Losses - Other Receivables, End of Period$1,037 $1,233 
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 ImprovementsLife of Lease
December 31,
20252024
Intangible Drilling Cost$6,755,849 $6,171,177 
Gas Gathering Equipment2,771,747 2,660,668 
Gas Wells and Related Equipment1,833,856 1,657,272 
Proved Gas Properties1,457,919 1,396,631 
Unproved Gas Properties747,528 721,692 
Surface Land and Other Equipment179,676 180,408 
Other 310,649 250,100 
Total Property, Plant and Equipment14,057,224 13,037,948 
Less: Accumulated Depreciation, Depletion and Amortization6,193,871 5,653,837 
Total Property, Plant and Equipment - Net$7,863,353 $7,384,111 
v3.25.4
EARNINGS PER SHARE (Tables)
 12 Months Ended
Dec. 31, 2025
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,
 202520242023
Anti-Dilutive Options— 947,257 21,650 
Anti-Dilutive Restricted Stock Units243,629 2,043,947 25,156 
Anti-Dilutive Performance Share Units— 1,469,703 — 
243,629 4,460,907 46,806 
The table below sets forth the potential common shares issuable upon conversion of the Convertible Notes that were excluded from the calculation of diluted earnings per share because their effect would be anti-dilutive:

For the Years Ended December 31,
2025
2024
2023
Convertible Notes
— 25,751,869 — 
Schedule of Losses Per Share, Basic and Diluted
The computations for basic and diluted loss per share are as follows:
For the Years Ended December 31,
 202520242023
Net Income (Loss)$633,162 $(90,494)$1,720,716 
Basic Earnings (Loss) Available to Shareholders$633,162 $(90,494)$1,720,716 
Effect of Dilutive Securities:
Add Back Interest on Convertible Notes (Net of Tax)5,782 — 5,758 
Diluted Earnings (Loss) Available to Shareholders$638,944 $(90,494)$1,726,474 
Weighted-Average Shares of Common Stock Outstanding141,453,847 151,306,438 162,490,245 
Effect of Diluted Shares:*
Options560,895 — 1,168,526 
Restricted Stock Units1,181,954 — 1,349,299 
Performance Share Units913,146 — 1,254,050 
Convertible Notes16,242,679 — 25,751,869 
Weighted-Average Diluted Shares of Common Stock Outstanding160,352,521 151,306,438 192,013,989 
Earnings (Loss) Per Share:
Basic$4.48 $(0.60)$10.59 
Diluted$3.98 $(0.60)$8.99 
*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,
 202520242023
Balance, Beginning of Year148,879,640 154,382,880 170,841,164 
Issuance Related to Stock-Based Compensation (1)1,071,390 1,672,434 1,106,240 
Retirement of Common Stock (2)(16,869,709)(7,175,674)(17,564,524)
Issuance related to Convertible Debt (3)9,509,188 — — 
Balance, End of Year142,590,509 148,879,640 154,382,880 
(1) See Note 15 – Stock-Based Compensation for additional information.
(2) See Note 5 – Stock Repurchase for additional information.
(3) See Note 12 – Long-Term Debt for additional information.
v3.25.4
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of Revenue
The following table is a disaggregation of revenue by major source:
For the Years Ended December 31,
202520242023
Revenue from Contracts with Customers:
Natural Gas Revenue$1,736,693 $986,028 $1,131,068 
NGL Revenue168,574 190,374 157,573 
Oil/Condensate Revenue8,461 9,675 13,577 
Total Natural Gas, NGL and Oil Revenue1,913,728 1,186,077 1,302,218 
Purchased Gas Revenue45,349 59,467 74,218 
Other Sources of Revenue and Other Operating Income:
Gain (Loss) on Commodity Derivative Instruments 96,661 (172,405)1,928,652 
Other Revenue and Operating Income183,396 193,647 129,860 
Total Revenue and Other Operating Income$2,239,134 $1,266,786 $3,434,948 
v3.25.4
INCOME TAXES (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of Components of Income Tax (Benefit) Expense
Income tax expense (benefit) provided on earnings consisted of:
For the Years Ended December 31,
202520242023
Current:
U.S. Federal
$421 $756 $— 
U.S. State
8,148 3,245 4,777 
8,569 4,001 4,777 
Deferred:
U.S. Federal
132,228 (27,917)455,224 
U.S. State
28,982 (5,952)42,208 
161,210 (33,869)497,432 
Total Income Tax Expense (Benefit)$169,779 $(29,868)$502,209 
Schedule of Deferred Tax Assets and Liabilities
The components of the net deferred taxes are as follows:
December 31,
20252024
Deferred Tax Assets:
Net Operating Loss- Federal
$149,684 $137,476 
Federal Tax Credits79,118 44,457 
Section 174 Expenses65,566 91,342 
Gas Well Closing61,234 33,541 
   Gas Derivatives60,306 130,834 
Net Operating Loss - State
53,679 70,689 
Operating Lease Liabilities38,960 25,650 
Interest Limitation25,623 62,271 
State Deferred Tax Adjustment15,983 15,983 
Salary Retirement8,073 8,037 
Equity Compensation4,670 6,659 
Convertible Note Amortization360 2,121 
Other
3,649 2,687 
Total Deferred Tax Assets
566,905 631,747 
Valuation Allowance
(32,262)(36,879)
Net Deferred Tax Assets
534,643 594,868 
Deferred Tax Liabilities:
Property, Plant and Equipment
(1,350,179)(1,261,971)
   Operating Lease Right-of-Use Assets(38,173)(25,071)
Investment in Partnerships(3,110)(2,825)
   Advance Gas Royalties(437)(515)
Other
(111)(622)
Total Deferred Tax Liabilities
(1,392,010)(1,291,004)
Net Deferred Tax Liability
$(857,367)$(696,136)
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,
 202520242023
 AmountPercentAmountPercentAmountPercent
U.S. Federal Statutory Tax Rate$168,618 21.0 %$(25,276)21.0 %$466,814 21.0 %
State Income Taxes, Net of Federal
Income Tax Effect (1)37,330 4.7 (4,610)3.8 83,379 3.8 
Effect of Changes in Tax Laws or Rates
Enacted in the Current Period2,706 0.3 2,806 (2.3)297 — 
Tax Credits
Research and development tax credits(14,251)(1.8)850 (0.7)(28,974)(1.3)
Energy-related tax credits(36,217)(4.5)(15,266)12.7 — — 
Foreign Tax Credits— — — — 7,738 0.3 
Changes in Valuation Allowances(4,617)(0.6)(2,385)2.0 (45,345)(2.0)
Nontaxable or Nondeductible Items
Share-based payment awards1,098 0.1 (40)— 1,036 — 
Other356 — 515 (0.4)428 — 
Changes in Unrecognized Tax Benefits15,807 2.0 13,309 (11.1)17,673 0.8 
Other Adjustments(1,051)(0.1)229 (0.2)(837)— 
Effective Tax Rate$169,779 21.1 %$(29,868)24.8 %$502,209 22.6 %
(1) State taxes in Pennsylvania, Virginia and West Virginia made up the majority (greater than 50 percent) of the tax effect in this category.
Schedule of 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,
20252024
Balance at Beginning of Period$113,227 $99,918 
Additions based on tax positions related to the current year17,341 18,224 
Additions for tax positions of prior years1,821 — 
Reductions for tax positions of prior years(3,355)(4,915)
Balance at End of Period$129,034 $113,227 
Schedule of Cash Flow, Supplemental Disclosures
The following table summarizes income taxes paid (net of refunds received). All jurisdictions in which income taxes paid (net of refunds received) were equal to or greater than five percent of total income taxes paid are included below (if the noted jurisdiction did not meet the five percent threshold for a particular year, the amount for that year is not included below).
For the Years Ended December 31,
202520242023
U.S. Federal$2,500 $650 $— 
Pennsylvania4,898 5,402 7,327 
Total Income Taxes Paid$7,398 $6,052 $7,327 
The following table shows cash paid:
For the Years Ended December 31,
202520242023
Interest (Net of Amounts Capitalized)$154,598 $136,263 $122,279 
v3.25.4
ASSET RETIREMENT OBLIGATIONS (Tables)
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation [Abstract]  
Schedule of Change in Asset Retirement Obligation
The reconciliation of changes in asset retirement obligations is as follows:
December 31,
20252024
Balance, Beginning of Year$132,064 $113,212 
Obligations Divested(1,778)(134)
Accretion Expense11,703 9,486 
Obligations Incurred9,540 2,172 
Obligations Settled(8,072)(7,475)
Revisions in Estimated Cash Flows40,669 14,803 
Balance, End of Year$184,126 $132,064 
v3.25.4
PROPERTY, PLANT AND EQUIPMENT (Tables)
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Schedule of 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 ImprovementsLife of Lease
December 31,
20252024
Intangible Drilling Cost$6,755,849 $6,171,177 
Gas Gathering Equipment2,771,747 2,660,668 
Gas Wells and Related Equipment1,833,856 1,657,272 
Proved Gas Properties1,457,919 1,396,631 
Unproved Gas Properties747,528 721,692 
Surface Land and Other Equipment179,676 180,408 
Other 310,649 250,100 
Total Property, Plant and Equipment14,057,224 13,037,948 
Less: Accumulated Depreciation, Depletion and Amortization6,193,871 5,653,837 
Total Property, Plant and Equipment - Net$7,863,353 $7,384,111 
Schedule of Oil and Gas, Full Cost Method, Amortization Expense
December 31,
20252024
Unproved Gas Properties$747,528 $721,692 
Advance Royalties1,721 2,026 
     Total$749,249 $723,718 
v3.25.4
GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)
 12 Months Ended
Dec. 31, 2025
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,
20252024
Other Intangible Assets:
Gross Amortizable Asset - Customer Relationships$109,752 $109,752 
Less: Accumulated Amortization - Customer Relationships52,419 45,867 
Total Other Intangible Assets, net$57,333 $63,885 
v3.25.4
OTHER ACCRUED LIABILITIES (Tables)
 12 Months Ended
Dec. 31, 2025
Other Liabilities Disclosure [Abstract]  
Schedule of Accrued Liabilities
December 31,
20252024
Royalties$121,078 $100,518 
Accrued Interest50,871 45,812 
Current Portion Settlement - See Note 1123,216 7,080 
Short-Term Incentive Compensation22,658 22,580 
Transportation Charges21,706 17,922 
Deferred Revenue14,589 20,696 
Accrued Other Taxes8,084 9,216 
Accrued Payroll & Benefits6,884 7,357 
Purchased Gas Payable554 143 
Other32,614 15,125 
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations21,075 12,875 
Salary Retirement2,647 1,908 
Total Other Accrued Liabilities$325,976 $261,232 
v3.25.4
LONG-TERM DEBT (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Schedule of Long-Term Debt
December 31,
20252024
Senior Notes due March 2032 at 7.25% (Principal of $600,000 and $400,000 less Unamortized Discount of $5,160 and $4,479, respectively)
$594,840 $395,521 
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 $3,800 and $4,554, respectively)
496,200 495,446 
CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $2,500 and $3,077, respectively)*
397,500 396,923 
Convertible Senior Notes due May 2026 at 2.25% (Principal of $208,556 and $330,654 less Unamortized Discount and Issuance Costs of $425 and $2,658, respectively)
208,131 327,996 
CNX Revolving Credit Facility200,000 43,450 
CNX Midstream Partners LP Revolving Credit Facility*32,750 16,050 
Less: Unamortized Debt Issuance Costs8,062 9,386 
$2,421,359 $2,166,000 
Less: Current Portion208,095 327,766 
Long-Term Debt$2,213,264 $1,838,234 
*CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or the CNXM Credit Facility.
Schedule of Maturities of Long-Term Debt
At December 31, 2025, 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
2026$208,556 
2027— 
2028— 
2029732,750 
2030400,000 
Thereafter1,100,000 
      Total Long-Term Debt Maturities$2,441,306 
Schedule of Convertible Debt
The net carrying amount of the liability and equity components of the Convertible Notes was as follows:
December 31,
20252024
Liability Component:
Principal$208,556 $330,654 
Unamortized Issuance Costs$(425)$(2,658)
Net Carrying Amount$208,131 $327,996 
Fair Value$596,798 $953,613 
Fair Value HierarchyLevel 2Level 2


Interest expense related to the Convertible Notes is as follows:
For the Years Ended December 31,
20252024
Contractual Interest Expense $7,333 $7,440 
Amortization of Issuance Costs1,922 1,928 
Total Interest Expense $9,255 $9,368 
v3.25.4
LEASES (Tables)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Schedule of Lease Cost
The components of lease cost were as follows:
For the Years Ended December 31,
202520242023
Operating Lease Cost$58,694 $60,572 $63,087 
Finance Lease Cost:
Amortization of Right-of-Use Assets
7,054 2,898 1,628 
Interest on Lease Liabilities
1,703 814 429 
Short-term Lease Cost3,950 1,533 2,357 
Variable Lease Cost*— 4,517 12,401 
Total Lease Cost$71,401 $70,334 $79,902 
*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. For the year ended December 31, 2025, actual utilization was below the minimum payment, resulting in no additional variable lease expense.
Lease terms and discount rates are as follows:
For the Years Ended December 31,
202520242023
Weighted Average Remaining Lease Term (years):
Operating Leases
3.633.663.59
Finance Leases
4.354.354.08
Weighted Average Discount Rate:
Operating Leases
6.16 %5.04 %4.84 %
Finance Leases
6.08 %6.32 %7.35 %
Schedule of Balance Sheet Information
Amounts recognized in the Consolidated Balance Sheets are as follows:
December 31,
20252024
Operating Leases:
Operating Lease Right-of-Use Assets$150,310 $98,713 
Current Portion of Operating Lease Obligations$48,453 $51,474 
Operating Lease Obligations104,955 49,519 
Total Operating Lease Liabilities
$153,408 $100,993 
Finance Leases:
Property, Plant and Equipment$40,615 $31,751 
Less—Accumulated Depreciation, Depletion and Amortization11,735 5,539 
Property, Plant and Equipment—Net
$28,880 $26,212 
Current Portion of Finance Lease Obligations$5,095 $4,236 
Finance Lease Obligations24,991 21,040 
Total Finance Lease Liabilities
$30,086 $25,276 

Supplemental cash flow information related to leases was as follows:
For the Years Ended December 31,
202520242023
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating Cash Flows for Operating Leases$58,644 $61,475 $64,139 
Operating Cash Flows for Finance Leases$1,703 $814 $429 
Financing Cash Flows for Finance Leases$4,465 $2,409 $1,627 
Right-of-Use Assets Obtained in Exchange for Lease Obligations:
Operating Leases
$103,296 $13,996 $19,477 
Finance Leases
$9,568 $20,407 $6,178 
Schedule of Maturity of Lease Liability, Operating
Maturities of lease liabilities are as follows:
OperatingFinance
LeasesLeases
Year Ended December 31,
2026$56,399 $6,874 
202749,306 6,772 
202844,983 11,158 
20296,620 2,810 
20306,624 2,293 
Thereafter7,225 6,271 
Total Lease Payments171,157 36,178 
Less: Interest17,749 6,092 
Present Value of Lease Liabilities$153,408 $30,086 
Schedule of Maturity of Lease Liability, Financing
Maturities of lease liabilities are as follows:
OperatingFinance
LeasesLeases
Year Ended December 31,
2026$56,399 $6,874 
202749,306 6,772 
202844,983 11,158 
20296,620 2,810 
20306,624 2,293 
Thereafter7,225 6,271 
Total Lease Payments171,157 36,178 
Less: Interest17,749 6,092 
Present Value of Lease Liabilities$153,408 $30,086 
v3.25.4
PENSION (Tables)
 12 Months Ended
Dec. 31, 2025
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,
20252024
Change in Benefit Obligation:
Benefit Obligation at Beginning of Period
$31,699 $33,541 
Interest Cost
1,653 1,657 
Actuarial Loss (Gain)328 (1,696)
Benefits and Other Payments
(1,809)(1,803)
Benefit Obligation at End of Period$31,871 $31,699 
Change in Plan Assets:
Fair Value of Plan Assets at Beginning of Period
$— $— 
Company Contributions
1,809 1,803 
Benefits and Other Payments
(1,809)(1,803)
Fair Value of Plan Assets at End of Period$— $— 
Funded Status:
Current Liabilities
$(2,647)$(1,908)
Noncurrent Liabilities
(29,224)(29,791)
Net Obligation Recognized$(31,871)$(31,699)
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:
Net Actuarial Loss
$7,402 $7,235 
Prior Service Cost399 620 
Total
7,801 7,855 
Less: Tax Benefit
2,122 2,143 
Net Amount Recognized$5,679 $5,712 
Schedule of Defined Benefit Plans Disclosures
The components of the net periodic benefit cost are as follows:
For the Years Ended December 31,
 202520242023
Components of Net Periodic Benefit Cost:
Interest Cost
1,653 1,657 1,675 
Amortization of Prior Service Cost221 221 222 
Recognized Net Actuarial Loss
161 223 173 
Net Periodic Benefit Cost$2,035 $2,101 $2,070 
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,
20252024
Projected Benefit Obligation$31,871 $31,699 
Accumulated Benefit Obligation$31,871 $31,699 
Fair Value of Plan Assets$— $— 
Schedule of Assumptions Used
The weighted-average assumptions used to determine benefit obligations are as follows:
As of December 31,
20252024
Discount Rate5.35 %5.65 %
Rate of Compensation Increase— %— %
Interest Credited Rate5.31 %5.20 %

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 weighted-average assumptions used to determine net periodic benefit cost are as follows:
For the Years ended December 31,
202520242023
Discount Rate5.65 %5.15 %5.43 %
Rate of Compensation Increase— %— %— %
Interest Credited Rate5.35 %5.04 %4.81 %
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
2026$2,647 
2027$2,649 
2028$2,651 
2029$2,655 
2030$2,662 
Year 2031-2035$13,155 
v3.25.4
STOCK-BASED COMPENSATION (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Schedule of Share-based Payment Award, Options Granted, Assumptions and Weighted Average Fair Value
December 31,
202520242023
Weighted Average Fair Value of Grants$— $10.40 $7.06 
Risk-free Interest Rate— %4.49 %3.24 %
Expected Dividend Yield— %— %— %
Expected Forfeiture Rate— %— %— %
Expected Volatility— %41.00 %48.70 %
Expected Term in Years— 5.505.50
Schedule of Share-based Compensation, Stock and Performance Options Rollforward
A summary of the status of stock options granted is presented below:
Weighted
Average
WeightedRemainingAggregate
AverageContractualIntrinsic
ExerciseTerm (inValue (in
SharesPriceyears)thousands)
Outstanding at December 31, 2024947,257 $10.48 
Exercised(267,347)$7.83 
Outstanding at December 31, 2025679,910 $11.53 2.04$17,163 
Exercisable at December 31, 2025679,910 $11.53 2.04$17,163 
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 ofWeighted Average
SharesGrant Date Fair Value
Nonvested at December 31, 20241,430,084 $18.60
Granted485,203 $32.75
Vested(772,947)$18.09
Forfeited(46,282)$27.68
Nonvested at December 31, 20251,096,058 $24.84
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 ofWeighted Average
SharesGrant Date Fair Value
Nonvested at December 31, 20242,655,861 $11.98
Granted760,635 $23.60
Vested(495,622)$12.25
Forfeited(58,199)$21.45
Nonvested at December 31, 20252,862,675 $14.63
v3.25.4
SUPPLEMENTAL CASH FLOW INFORMATION (Tables)
 12 Months Ended
Dec. 31, 2025
Supplemental Cash Flow Information [Abstract]  
Schedule of Cash Flow, Supplemental Disclosures
The following table summarizes income taxes paid (net of refunds received). All jurisdictions in which income taxes paid (net of refunds received) were equal to or greater than five percent of total income taxes paid are included below (if the noted jurisdiction did not meet the five percent threshold for a particular year, the amount for that year is not included below).
For the Years Ended December 31,
202520242023
U.S. Federal$2,500 $650 $— 
Pennsylvania4,898 5,402 7,327 
Total Income Taxes Paid$7,398 $6,052 $7,327 
The following table shows cash paid:
For the Years Ended December 31,
202520242023
Interest (Net of Amounts Capitalized)$154,598 $136,263 $122,279 
v3.25.4
CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS - (Tables)
 12 Months Ended
Dec. 31, 2025
Risks and Uncertainties [Abstract]  
Schedules of Concentration of Risk, by Risk Factor Concentration of credit risk is summarized below:
December 31,
20252024
Gas Wholesalers$244,102 $151,031 
NGL, Condensate & Processing Facilities
14,665 22,404 
Other5,975 6,196 
Allowance for Credit Losses(84)(84)
Total Accounts Receivable Trade
$264,658 $179,547 
v3.25.4
FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets Measured on Recurring Basis
The financial instrument measured at fair value on a recurring basis is summarized below:
 Fair Value Measurements at December 31, 2025Fair Value Measurements at December 31, 2024
DescriptionLevel 1Level 2Level 3Level 1Level 2Level 3
Commodity Derivatives$— $(295,849)*$— $— $(536,046)**$— 
*Includes $58,387 of commodity derivatives that have been settled but not paid at December 31, 2025.
**Includes $2,309 of commodity derivatives that have been settled but not received and $23,212 that have been settled but not paid at December 31, 2024.
Schedule of Fair Value, Assets and Liabilities Measured on Nonrecurring Basis
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
 December 31, 2025December 31, 2024
 Carrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
Cash and Cash Equivalents $779 $779 $17,198 $17,198 
Restricted Cash*$12,685 $12,685 $37,875 $37,875 
Long-Term Debt (Excluding Debt Issuance Costs)$2,429,421 $2,850,144 $2,175,386 $2,785,556 
*The December 31, 2025 and 2024 restricted cash balances are located in current assets in the Consolidated Balance Sheets.
v3.25.4
DERIVATIVE INSTRUMENTS (Tables)
 12 Months Ended
Dec. 31, 2025
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
20252024Settle Through
Natural Gas Commodity Swaps (Bcf)929.8 1,163.7 2028
Natural Gas Basis Swaps (Bcf)585.5 688.7 2028
NGL Commodity Swaps (Mbbls)180.0351.02026
Schedule of Derivative Assets at Fair Value
The gross fair value of CNX's derivative instruments was as follows:
December 31,
20252024
Current Assets:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$74,064 $45,336 
     NGL Commodity Swaps 1,730 90 
     Natural Gas Basis Swaps30,274 42,499 
Total Current Assets$106,068 $87,925 
Other Non-Current Assets:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$117,524 $117,875 
     Natural Gas Basis Swaps16,872 42,308 
Total Other Non-Current Assets$134,396 $160,183 
Current Liabilities:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$323,169 $300,994 
     NGL Commodity Swaps— 839 
     Natural Gas Basis Swaps54,776 52,788 
Total Current Liabilities$377,945 $354,621 
Non-Current Liabilities:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$101,387 $364,662 
     Natural Gas Basis Swaps56,981 64,871 
Total Non-Current Liabilities$158,368 $429,533 
Schedule of Derivative Liabilities at Fair Value
The gross fair value of CNX's derivative instruments was as follows:
December 31,
20252024
Current Assets:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$74,064 $45,336 
     NGL Commodity Swaps 1,730 90 
     Natural Gas Basis Swaps30,274 42,499 
Total Current Assets$106,068 $87,925 
Other Non-Current Assets:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$117,524 $117,875 
     Natural Gas Basis Swaps16,872 42,308 
Total Other Non-Current Assets$134,396 $160,183 
Current Liabilities:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$323,169 $300,994 
     NGL Commodity Swaps— 839 
     Natural Gas Basis Swaps54,776 52,788 
Total Current Liabilities$377,945 $354,621 
Non-Current Liabilities:
  Commodity Derivative Instruments:
     Natural Gas Commodity Swaps$101,387 $364,662 
     Natural Gas Basis Swaps56,981 64,871 
Total Non-Current Liabilities$158,368 $429,533 
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value
The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows:
For the Years Ended December 31,
202520242023
Realized (Loss) Gain on Commodity Derivative Instruments:
   Natural Gas Commodity Swaps$(188,791)$275,672 $62,567 
   Natural Gas Basis Swaps7,208 4,900 98,582 
   NGL Commodity Swaps563 623 1,877 
Total Realized (Loss) Gain on Commodity Derivative Instruments(181,020)*281,195 **163,026 ***
Unrealized Gain (Loss) on Commodity Derivative Instruments:
   Natural Gas Commodity Swaps306,779 (286,567)1,858,060 
   Natural Gas Basis Swaps(31,180)(165,566)(93,222)
   NGL Commodity Swaps2,082 (1,467)788 
Total Unrealized Gain (Loss) on Commodity Derivative Instruments277,681 (453,600)1,765,626 
Gain (Loss) on Commodity Derivative Instruments:
   Natural Gas Commodity Swaps117,988 (10,895)1,920,627 
   Natural Gas Basis Swaps(23,972)(160,666)5,360 
   NGL Commodity Swaps2,645 (844)2,665 
Total Gain (Loss) on Commodity Derivative Instruments$96,661 $(172,405)$1,928,652 
*Includes $58,387 that have been settled but not paid at December 31, 2025, and excludes $2,309 of commodity derivatives that have been settled but not received and $23,212 that have been settled but not paid at December 31, 2024.
**Includes $2,309 of commodity derivatives that have been settled but not received and $23,212 that have been settled but not paid at December 31, 2024, and excludes $6,741 of commodity derivatives that have been settled but not received and $900 that have been settled but not paid at December 31, 2023.
***Includes $6,741 of commodity derivatives that were settled but not received and $900 that have been settled but not paid at December 31, 2023, and excludes $77,662 of commodity 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,
202520242023
Cash Received in Settlement of Interest Rate Swaps$— $1,103 $4,207 
Unrealized Loss on Interest Rate Swaps— (1,099)(3,463)
Gain on Interest Rate Swaps$— $4 $744 
v3.25.4
COMMITMENTS AND CONTINGENT LIABILITIES (Tables)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Schedule of Long-term Purchase Commitment
At December 31, 2025, 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
Amounts
Committed		Less Than
1  Year		1-3 Years3-5 YearsBeyond
5  Years
Letters of Credit:
Firm Transportation$25,077 $25,077 $— $— $— 
Other2,920 2,920 — — — 
Total Letters of Credit27,997 27,997 — — — 
Surety Bonds:
Employee-Related2,250 2,250 — — — 
Environmental40,005 40,005 — — — 
Firm Transportation129,336 129,336 — — — 
Financial Guarantees93,000 93,000 — — — 
Other12,957 12,957 — — — 
Total Surety Bonds277,548 277,548 — — — 
Other Guarantees2,887 707 1,414 766 — 
Total Commitments$308,432 $306,252 $1,414 $766 $— 
Schedule of Unrecorded Unconditional Purchase Obligations Disclosure As of December 31, 2025, the purchase obligations for each of the next five years and beyond are as follows:
Obligations DueAmount
Less than 1 year$270,869 
1 - 3 years479,607 
3 - 5 years273,803 
More than 5 years457,473 
Total Purchase Obligations$1,481,752 
v3.25.4
SEGMENT INFORMATION (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Schedule of Segment Reporting Information, by Segment
Reportable segment results for the year ended December 31, 2025 are:
For the year ended December 31, 2025
ShaleCoalbed
Methane		OtherConsolidated
Natural Gas, NGLs and Oil Revenue$1,763,961 $148,017 $1,750 $1,913,728 (A)
(Loss) Gain on Commodity Derivative Instruments(169,598)(11,354)277,613 96,661 
Purchased Gas Revenue— — 45,349 45,349 
Other Revenue and Operating Income69,169 — 114,227 183,396 (B)
Total Revenue and Other Operating Income $1,663,532 $136,663 $438,939 $2,239,134 
Lease Operating Expense73,302 24,043 71 97,416 
Transportation, Gathering and Compression317,424 63,869 1,811 383,104 
Production, Ad Valorem, and Other Fees24,749 6,412 39 31,200 
Depreciation, Depletion and Amortization488,021 59,188 26,905 574,114 
Interest Expense— — 170,592 170,592 
Other Segment Items — — 179,767 179,767 
Total Costs and Expenses$903,496 $153,512 $379,185 $1,436,193 
Income (Loss) Before Income Tax$760,036 $(16,849)$59,754 $802,941 
(A) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $223,210 to NRG Business Marketing LLC, $208,775 to DTE Energy Trading, Inc, and $205,993 to Citadel Energy Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(B) Includes midstream revenue of $69,169 and equity in loss of unconsolidated affiliates of $740 for Shale and Other, respectively. Other also includes sales of environmental attributes of $77,829.
Other Segment Disclosures
For the year ended December 31, 2025
ShaleCoalbed
Methane		OtherConsolidated
Segment Assets$7,218,019 $909,304 $967,123 $9,094,446 (C)
Capital Expenditures$443,714 $44,628 $6,646 $494,988 
(C) Includes investments in unconsolidated equity affiliates of $5,709.
Reportable segment results for the year ended December 31, 2024 are:
For the year ended December 31, 2024
ShaleCoalbed
Methane		OtherConsolidated
Natural Gas, NGLs and Oil Revenue$1,080,044 $105,119 $914 $1,186,077 (D)
Gain (Loss) on Commodity Derivative Instruments260,395 20,675 (453,475)(172,405)
Purchased Gas Revenue— — 59,467 59,467 
Other Revenue and Operating Income68,308 — 125,339 193,647 (E)
Total Revenue and Other Operating Income (Loss)$1,408,747 $125,794 $(267,755)$1,266,786 
Lease Operating Expense48,079 21,997 570 70,646 
Transportation, Gathering and Compression316,167 64,620 1,433 382,220 
Production, Ad Valorem, and Other Fees22,036 5,459 59 27,554 
Depreciation, Depletion and Amortization405,292 59,590 20,872 485,754 
Interest Expense— — 150,594 150,594 
Other Segment Items — — 270,380 270,380 
Total Costs and Expenses$791,574 $151,666 $443,908 $1,387,148 
Income (Loss) Before Income Tax$617,173 $(25,872)$(711,663)$(120,362)
(D) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $134,909 to Citadel Energy Marketing LLC and $132,935 to NRG Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(E) Includes midstream revenue of $68,308 and equity in loss of unconsolidated affiliates of $1,314 for Shale and Other, respectively. Other also
includes sales of environmental attributes of $95,490.
For the year ended December 31, 2024
Other Segment DisclosuresShaleCoalbed
Methane		OtherConsolidated
Segment Assets$6,669,076 $920,742 $922,085 $8,511,903 (F)
Capital Expenditures$495,538 $29,329 $15,465 $540,332 
(F) Includes investments in unconsolidated equity affiliates of $18,380.

Reportable segment results for the year ended December 31, 2023 are:

For the year ended December 31, 2023
ShaleCoalbed
Methane		OtherConsolidated
Natural Gas, NGLs and Oil Revenue$1,170,393 $130,763 $1,062 $1,302,218 (G)
Gain on Commodity Derivative Instruments151,408 11,554 1,765,690 1,928,652 
Purchased Gas Revenue— — 74,218 74,218 
Other Revenue and Operating Income66,559 — 63,301 129,860 (H)
Total Revenue and Other Operating Income$1,388,360 $142,317 $1,904,271 $3,434,948 
Lease Operating Expense43,740 19,942 (349)63,333 
Transportation, Gathering and Compression315,653 65,470 811 381,934 
Production, Ad Valorem, and Other Fees21,636 6,244 66 27,946 
Depreciation, Depletion and Amortization365,020 50,052 18,514 433,586 
Interest Expense— — 143,278 143,278 
Other Segment Items — — 161,946 161,946 
Total Costs and Expenses$746,049 $141,708 $324,266 $1,212,023 
Income Before Income Tax$642,311 $609 $1,580,005 $2,222,925 
(G) 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, each of which comprises over 10% of revenue from contracts with external customers for the period.
(H) 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.
For the year ended December 31, 2023
Other Segment DisclosuresShaleCoalbed
Methane		OtherConsolidated
Segment Assets$6,656,655 $948,795 $1,021,207 $8,626,657 (I)
Capital Expenditures$629,631 $36,804 $12,969 $679,404 
(I) Includes investments in unconsolidated equity affiliates of $13,682.
Schedule of Reconciliation of Revenue from Segments to Consolidated
Revenue and Other Operating Income:
For the Years Ended December 31,
202520242023
Total Segment Revenue from Contracts with External Customers$2,028,246 $1,313,852 $1,442,995 
Gain (Loss) on Commodity Derivative Instruments96,661 (172,405)1,928,652 
Other Operating Income114,227 125,339 63,301 
Total Consolidated Revenue and Other Operating Income
$2,239,134 $1,266,786 $3,434,948 
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) (Tables)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
Schedule of Oil and Gas, Capitalized Cost
Capitalized Costs:
As of December 31,
20252024
Intangible Drilling Costs$6,755,849 $6,171,177 
Gas Gathering Assets2,771,747 2,660,668 
Proved Gas Properties1,457,919 1,396,631 
Unproved Gas Properties747,528 721,692 
Gas Wells and Related Equipment1,833,856 1,657,272 
Other Gas Assets186,346 136,138 
Total Property, Plant and Equipment13,753,245 12,743,578 
Accumulated Depreciation, Depletion and Amortization(6,091,349)(5,561,023)
Net Capitalized Costs$7,661,896 $7,182,555 
Schedule of Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development
Costs incurred for property acquisition, exploration and development (*):
For the Years Ended December 31,
202520242023
Property Acquisitions (a)
Proved Properties (b)$534,229 $10,362 $2,319 
Unproved Properties (c)49,118 15,061 26,405 
Development (d)432,082 500,402 637,711 
Exploration6,806 4,494 4,257 
Total$1,022,235 $530,319 $670,692 
__________
(a)    Includes costs incurred whether capitalized or expensed.
(b)    Amounts in 2025 include $523,256 for proved properties acquired in the Apex Transaction (See Note 4 – Acquisitions and Dispositions).
(c)    Amounts in 2025 include $3,200 for unproved properties acquired in the Apex Transaction (See Note 4 – Acquisitions and Dispositions).
(d)    Includes development costs for midstream of $37,669, $23,135 and $46,814 for the years ended December 31, 2025, 2024 and 2023, respectively.
Schedule of Oil and Gas, Result of Operation, Producing Activity
Results of Operations for Producing Activities:
For the Years Ended December 31,
202520242023
Natural Gas, NGLs and Oil Revenue$1,913,728 $1,186,077 $1,302,218 
Realized Gain (Loss) on Commodity Derivative Instruments (181,020)281,195 163,026 
Unrealized (Loss) Gain on Commodity Derivative Instruments277,681 (453,600)1,765,626 
Purchased Gas Revenue45,349 59,467 74,218 
Total Revenue2,055,738 1,073,139 3,305,088 
Lease Operating Expense97,416 70,646 63,333 
Production, Ad Valorem and Other Fees31,200 27,554 27,946 
Transportation, Gathering and Compression383,104 382,220 381,934 
Purchased Gas Costs42,647 57,248 69,924 
Exploration Costs10,516 8,446 10,447 
Depreciation, Depletion and Amortization574,114 485,754 433,586 
Total Costs1,138,997 1,031,868 987,170 
Pre-tax Operating Income916,741 41,271 2,317,918 
Income Tax Expense193,432 10,235 523,849 
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$723,309 $31,036 $1,794,069 
Schedule of 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,
202520242023
Production (MMcfe)628,960 550,814 560,366 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$3.04 $2.15 $2.32 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$(0.31)$0.57 $0.32 
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$2.75 $2.66 $2.61 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.15 $0.13 $0.11 
Schedule of Gas and Oil Acreage
The following table sets forth, at December 31, 2025, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,560 4,488 
Producing Oil Wells - Working Interest2 — 
Producing Gas Wells - Royalty Interest412 — 
Producing Oil Wells - Royalty Interest128 — 
Acreage Position:
   Proved Developed Acreage428,042 428,042 
   Proved Undeveloped Acreage26,092 26,092 
   Unproved Acreage4,946,079 3,517,208 
Total Acreage5,400,213 3,971,342 
____________
(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.
Schedule of Oil and Gas, Proved Reserve, Quantity
The oil and gas reserves estimates are as follows:
CondensateConsolidated
Natural GasNGLs& Crude OilOperations
(MMcf)(Mbbls)(Mbbls)(MMcfe)
Balance December 31, 2022 (a)9,187,278 100,153 3,115 9,806,890 
Revisions (b)(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 
Revisions (c)(634,288)1,921 (356)(624,896)
Price Changes(237,036)(6,707)(569)(280,692)
Extensions and Discoveries (e)1,092,556 30,465 112 1,276,018 
Production(496,922)(8,825)(157)(550,814)
Sales of Reserves In-Place(18,377)(644)(29)(22,415)
Balance December 31, 2024 (a)7,628,925 150,921 582 8,537,943 
Revisions (d)28,065 6,812 20 69,057 
Price Changes167,939 466 2 170,747 
Extensions and Discoveries (e)758,540 17,816 250 866,936 
Production(580,600)(7,907)(153)(628,960)
Purchases of Reserves In-Place (f)667,993 — — 667,993 
Sales of Reserves In-Place(21,512)(8)(2)(21,572)
Balance December 31, 2025 (a)8,649,350 168,100 699 9,662,144 
Proved developed reserves:
December 31, 20235,521,437 83,682 706 6,027,762 
December 31, 20245,418,858 112,884 582 6,099,654 
December 31, 20256,263,162 117,613 595 6,972,410 
Proved undeveloped reserves:
December 31, 20232,401,555 51,029 875 2,712,980 
December 31, 20242,210,067 38,037 — 2,438,289 
December 31, 20252,386,188 50,487 104 2,689,734 
__________
(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 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.
(c)    The downward revisions in 2024 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 189 Bcfe being removed. Additional downward revisions of 284 Bcfe are due to the wells not being developed within five years of their original booking. Additionally, there were negative revisions of 65 Bcfe due to performance and 87 Bcfe due to wells that that were uneconomic.
(d)    The upward revisions in 2025 are partly due to 104 Bcfe increase as a result of performance revisions. Additional downward revisions of 1.9 Bcfe are due to wells being plugged and abandoned or are shut-in and are awaiting to be plugged and abandoned. Additionally, we removed a single well for plan changes which resulted in a decrease of 33 Bcfe.
(e)    Extensions and Discoveries in 2023, 2024, and 2025 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, operated assets and exploratory wells. In 2025, 2024, and 2023, the Company added 55 Bcfe, 252 Bcfe, and 42 Bcfe, respectively, related to exploratory and non-operated wells.
(f)    Purchases of Reserves-In-Place in 2025 are associated with our acquisition of Apex Energy which resulted in the addition of 668 Bcfe of natural gas reserves.
For the Year
Ended
December 31,
2025
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves2,438,289 
Undeveloped Reserves Transferred to Developed (a)(625,068)
Price Revisions3,298 
Revisions Due to Plan Changes (b)(33,007)
Revisions Due to Changes Related to Well Performance (c)106,465 
Revisions Due to 5 Year Rule— 
Extension and Discoveries (d)799,757 
Ending Proved Undeveloped Reserves(e)2,689,734 
_________
(a)    During 2025, various development drilling and evaluations were completed. Approximately, $183,031 of capital was spent in the year ended December 31, 2025 related to undeveloped reserves that were transferred to developed.
(b)    The downward revisions for 2025 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 33 Bcfe being removed.
(c)    The upward revision of 106 Bcfe are from positive performance revisions.
(d)    Extensions and Discoveries are due mainly to the addition of 549 Bcfe related to 20 Marcellus wells within our Southwest Pennsylvania, West Virginia and Central Pennsylvania operations and 250 Bcfe related to 13 Utica wells within our Southwest Pennsylvania and Central 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, 2025 are approximately 320 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.
Schedule of Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow
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,
202520242023
Future Cash Flows (a)
Revenues
$29,123,088 $17,997,427 $20,281,496 
Production Costs
(10,413,538)(8,034,256)(8,515,152)
Development Costs (b)(2,221,264)(1,743,442)(1,903,477)
Income Tax Expense
(4,191,554)(2,083,504)(2,507,151)
Future Net Cash Flows12,296,732 6,136,225 7,355,716 
Discounted to Present Value at a 10% Annual Rate(7,230,426)(3,297,503)(4,245,681)
Total Standardized Measure of Discounted Net Cash Flows$5,066,306 $2,838,722 $3,110,035 
_________
(a)    For 2025, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2025, adjusted for energy content and a regional price differential. For 2025, this adjusted natural gas price was $2.98 per Mcf, the adjusted oil/condensate price was $53.80 per barrel and the adjusted NGL price was $19.93 per barrel.

For 2024, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2024, adjusted for energy content and a regional price differential. For 2024, this adjusted natural gas price was $2.00 per Mcf, the adjusted oil/condensate price was $63.13 per barrel and the adjusted NGL price was $17.92 per barrel.

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.

(b)    Development costs for 2025 include $1,017,263 of plugging and abandonment costs and $156,884 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $70,241 and $133,319, respectively.

Development costs for 2024 include $705,070 of plugging and abandonment costs and $160,868 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $94,169 and $131,711, respectively.

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.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202520242023
Balance at Beginning of Period$2,838,722 $3,110,035 $10,762,699 
Net Changes in Sales Prices and Production Costs3,615,935 (506,616)(10,722,238)
Sales Net of Production Costs(1,220,988)(986,852)(992,030)
Net Change Due to Revisions in Quantity Estimates46,181 (229,940)(155,807)
Net Change Due to Extensions, Discoveries and Improved Recovery432,682 197,972 32,876 
Development Costs Incurred During the Period432,082 500,402 637,711 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period(129,837)(72,232)(149,770)
Changes in Estimated Future Development Costs(249,185)(183,359)(211,592)
Net Change in Future Income Taxes(775,898)102,450 2,647,842 
Accretion351,409 395,680 1,403,417 
Timing and Other(274,797)511,182 (143,073)
     Total Discounted Cash Flow at End of Period$5,066,306 $2,838,722 $3,110,035 
Note: Table excludes unrealized gain/loss on commodity derivative instruments.
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
May 31, 2025
Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]      
Cash and Cash Equivalents $ 779   $ 17,198
Restricted Cash $ 12,685 $ 10,100 $ 37,875
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES - Schedule of Allowance for Credit Losses (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
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 - Trade, End of Period 84 84
Other Receivables    
Accounts Receivable, Allowance for Credit Loss [Roll Forward]    
Allowance for Credit Losses - Trade, Beginning of Year 1,233 2,847
Recoveries Collected 0 (1,692)
Provision for Expected Credit Losses 131 186
Write-off of Uncollectible Accounts (327) (108)
Allowance for Credit Losses - Trade, End of Period $ 1,037 $ 1,233
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Property, Plant and Equipment [Line Items]      
Depreciation, depletion and amortization $ 574,114 $ 485,754 $ 433,586
Gas Properties      
Property, Plant and Equipment [Line Items]      
Depreciation, depletion and amortization $ 458,335 $ 378,646 $ 332,596
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    
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES - Impairment of Proved and Unproved Properties (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Exploration and Production Related Other Costs      
Productive Wells [Line Items]      
Transportation, Gathering and Compression $ 10,516 $ 8,446 $ 10,447
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES - Impairment of Goodwill and Definite-Lived Intangible Assets (Details)
Dec. 31, 2025
Property, Plant and Equipment [Line Items]  
Useful life, customer relationship intangible assets 17 years
Customer Relationships  
Property, Plant and Equipment [Line Items]  
Useful life, customer relationship intangible assets 17 years
v3.25.4
SIGNIFICANT ACCOUNTING POLICIES - Investment Plan (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Contribution Plan Disclosure [Line Items]      
Company's matching contribution, percentage 6.00% 6.00% 6.00%
Discretionary contributions to the plan, amount $ 0 $ 0 $ 0
Total payment and cost to the plan $ 3,201,000 $ 3,603,000 $ 3,509,000
Minimum      
Defined Contribution Plan Disclosure [Line Items]      
Discretionary contributions to the plan, percentage 1.00%    
Maximum      
Defined Contribution Plan Disclosure [Line Items]      
Discretionary contributions to the plan, percentage 6.00%    
v3.25.4
EARNINGS PER SHARE - Narrative (Details) - Convertible 2.25% Senior Notes Due 2026 - $ / shares
Dec. 31, 2025
Dec. 15, 2025
Dec. 31, 2020
Business Combination [Line Items]      
Stated rate, debt instrument 2.25%    
Convertible Notes      
Business Combination [Line Items]      
Stated rate, debt instrument   2.25% 2.25%
Conversion price (in usd per share)   $ 12.84 $ 12.84
v3.25.4
EARNINGS PER SHARE - Schedule of Anti-Dilutive Options and Units Excluded from Earnings Per Share (Details) - shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]      
Antidilutive securities excluded from the computation of diluted earnings per share (in shares) 243,629 4,460,907 46,806
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) 0 947,257 21,650
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) 243,629 2,043,947 25,156
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 1,469,703 0
v3.25.4
EARNINGS PER SHARE - Schedule of Antidilutive Securities (Details) - shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]      
Antidilutive securities excluded from the computation of diluted earnings per share (in shares) 243,629 4,460,907 46,806
Convertible Notes      
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 25,751,869 0
v3.25.4
EARNINGS PER SHARE - Schedule of Computation of Basic and Diluted (Loss) (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]      
Net Income (Loss) $ 633,162 $ (90,494) $ 1,720,716
Basic Earnings (Loss) Available to Shareholders 633,162 (90,494) 1,720,716
Effect of Dilutive Securities:      
Add Back Interest on Convertible Notes (Net of Tax) 5,782 0 5,758
Diluted Earnings (Loss) Available to Shareholders $ 638,944 $ (90,494) $ 1,726,474
Weighted-Average Shares of Common Stock Outstanding (in shares) 141,453,847 151,306,438 162,490,245
Weighted-Average Diluted Shares of Common Stock Outstanding (in shares) 160,352,521 151,306,438 192,013,989
Earnings (Loss) Per Share:      
Basic (in usd per share) $ 4.48 $ (0.60) $ 10.59
Diluted (in usd per share) $ 3.98 $ (0.60) $ 8.99
Convertible Notes      
Effect of Dilutive Securities:      
Effect of Diluted Shares (in shares) 16,242,679 0 25,751,869
Options      
Effect of Dilutive Securities:      
Effect of Diluted Shares (in shares) 560,895 0 1,168,526
Restricted Stock Units      
Effect of Dilutive Securities:      
Effect of Diluted Shares (in shares) 1,181,954 0 1,349,299
Performance Share Units      
Effect of Dilutive Securities:      
Effect of Diluted Shares (in shares) 913,146 0 1,254,050
v3.25.4
EARNINGS PER SHARE - Schedule of Shares of Common Stock Outstanding (Details) - shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Common Stock Outstanding [Roll Forward]      
Balance, beginning of year (in shares) 148,879,640    
Balance, end of year (in shares) 142,590,509 148,879,640  
Common Stock      
Common Stock Outstanding [Roll Forward]      
Balance, beginning of year (in shares) 148,879,640 154,382,880 170,841,164
Issuance Related to Stock-Based Compensation (in shares) 1,071,390 1,672,434 1,106,240
Retirement of Common Stock (in shares) (16,869,709) (7,175,674) (17,564,524)
Issuance related to Convertible Debt (in shares) 9,509,188 0 0
Balance, end of year (in shares) 142,590,509 148,879,640 154,382,880
v3.25.4
REVENUE FROM CONTRACTS WITH CUSTOMERS - Narrative (Details)
 12 Months Ended
Dec. 31, 2025
USD ($)
Disaggregation of Revenue [Line Items]  
Payment terms for contract with customers 25 days
Contract asset $ 0
Remaining performance obligations 20,074,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Disaggregation of Revenue [Line Items]  
Remaining performance obligations $ 16,246,000
Remaining performance obligations, expected timing of satisfaction 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01  
Disaggregation of Revenue [Line Items]  
Remaining performance obligations $ 2,600,000
Remaining performance obligations, expected timing of satisfaction 1 year
v3.25.4
REVENUE FROM CONTRACTS WITH CUSTOMERS - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Gain (Loss) on Commodity Derivative Instruments $ 96,661 $ (172,405) $ 1,928,652
Other Revenue and Operating Income 183,396 193,647 129,860
Total Revenue and Other Operating Income 2,239,134 1,266,786 3,434,948
Total Natural Gas, NGL and Oil Revenue      
Disaggregation of Revenue [Line Items]      
Revenue 1,913,728 1,186,077 1,302,218
Natural Gas Revenue      
Disaggregation of Revenue [Line Items]      
Revenue 1,736,693 986,028 1,131,068
NGL Revenue      
Disaggregation of Revenue [Line Items]      
Revenue 168,574 190,374 157,573
Oil/Condensate Revenue      
Disaggregation of Revenue [Line Items]      
Revenue 8,461 9,675 13,577
Purchased Gas Revenue      
Disaggregation of Revenue [Line Items]      
Revenue $ 45,349 $ 59,467 $ 74,218
v3.25.4
ACQUISITIONS AND DISPOSITIONS (Details)
$ in Thousands
 12 Months Ended
Jan. 27, 2025
USD ($)
Dec. 31, 2025
USD ($)
a
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
May 31, 2025
USD ($)
Business Combination [Line Items]          
Consideration   $ 517,599 $ 0 $ 0  
Restricted cash   12,685 37,875   $ 10,100
Payments to acquire interests   24,250      
Net cash proceeds   107,655 60,734 170,027  
Gain on transaction   $ 97,168 24,715 132,372  
Apex Energy II, LLC          
Business Combination [Line Items]          
Consideration $ 517,599        
Net of cash received 1,588        
Proved oil and gas properties, well, and well-related equipment $ 523,256        
Marcellus Shale Rights          
Business Combination [Line Items]          
Area of land sold (in acres) | a   7,500      
Net cash proceeds   $ 57,086      
Gain on transaction   $ 57,086      
Non-Operated Producing Oil and Gas Assets          
Business Combination [Line Items]          
Net cash proceeds     2,017 124,600  
Gain on transaction     $ (26,150) $ 99,516  
v3.25.4
STOCK REPURCHASE (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Jan. 29, 2026
Share Repurchase Program [Line Items]        
Share repurchase program, authorized amount $ 2,900,000,000      
Amount available under the current stock repurchase program $ 428,014,000      
Stock repurchased during period (in shares) 16,869,709 7,175,674 17,564,524  
Treasure stock acquired (in usd per share) $ 31.00 $ 24.68 $ 18.14  
Stock repurchased and retired $ 528,073,000 $ 178,583,000 $ 321,867,000  
Subsequent Event        
Share Repurchase Program [Line Items]        
Share repurchase program, authorized amount       $ 2,000,000,000
Amount available under the current stock repurchase program       $ 2,400,000,000
v3.25.4
INCOME TAXES - Schedule of Income Tax (Benefit) Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current:      
U.S. Federal $ 421 $ 756 $ 0
U.S. State 8,148 3,245 4,777
Current income tax (benefit) 8,569 4,001 4,777
Deferred:      
U.S. Federal 132,228 (27,917) 455,224
U.S. State 28,982 (5,952) 42,208
Deferred income tax (benefit) 161,210 (33,869) 497,432
Effective Tax Rate $ 169,779 $ (29,868) $ 502,209
v3.25.4
INCOME TAXES - Schedule of Net Deferred Tax Assets/Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Deferred Tax Assets:    
Net Operating Loss- Federal $ 149,684 $ 137,476
Federal Tax Credits 79,118 44,457
Section 174 Expenses 65,566 91,342
Gas Well Closing 61,234 33,541
Gas Derivatives 60,306 130,834
Net Operating Loss - State 53,679 70,689
Operating Lease Liabilities 38,960 25,650
Interest Limitation 25,623 62,271
State Deferred Tax Adjustment 15,983 15,983
Salary Retirement 8,073 8,037
Equity Compensation 4,670 6,659
Convertible Note Amortization 360 2,121
Other 3,649 2,687
Total Deferred Tax Assets 566,905 631,747
Valuation Allowance (32,262) (36,879)
Net Deferred Tax Assets 534,643 594,868
Deferred Tax Liabilities:    
Property, Plant and Equipment (1,350,179) (1,261,971)
Operating Lease Right-of-Use Assets (38,173) (25,071)
Investment in Partnerships (3,110) (2,825)
Advance Gas Royalties (437) (515)
Other (111) (622)
Total Deferred Tax Liabilities (1,392,010) (1,291,004)
Net Deferred Tax Liability $ (857,367) $ (696,136)
v3.25.4
INCOME TAXES - Narrative (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Valuation Allowance [Line Items]      
Federal net operating losses $ 149,684,000 $ 137,476,000  
Federal tax credits 79,118,000 44,457,000  
Deferred tax asset related to state operating losses 53,679,000 70,689,000  
Valuation allowance 32,262,000 36,879,000  
Unrecognized tax benefits that would impact effective tax rate 129,034,000 113,227,000  
Increase in unrecognized tax benefits resulting from tax positions taken during current period 17,341,000 18,224,000  
Net Decrease in unrecognized tax benefits resulting from tax position taken on prioryear return   (1,534,000)  
Decrease in unrecognized tax benefits resulting from tax position taken on prioryear return (3,355,000) (4,915,000) $ (4,915,000)
Accrued liability relating to uncertain tax positions 0 0  
Interest related to income tax deficiencies 0 0  
Accrued liabilities for tax penalties 0 0  
State Operating Losses      
Valuation Allowance [Line Items]      
Valuation allowance $ 32,262,000 $ 36,879,000  
v3.25.4
INCOME TAXES - Schedule of Effective Tax Rate Reconciliation (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Amount      
U.S. Federal Statutory Tax Rate $ 168,618 $ (25,276) $ 466,814
State Income Taxes, Net of Federal 37,330 (4,610) 83,379
Effect of Changes in Tax Laws or Rates 2,706 2,806 297
Research and development tax credits (14,251) 850 (28,974)
Energy-related tax credits (36,217) (15,266) 0
Foreign Tax Credits 0 0 7,738
Changes in Valuation Allowances (4,617) (2,385) (45,345)
Share-based payment awards 1,098 (40) 1,036
Other 356 515 428
Changes in Unrecognized Tax Benefits 15,807 13,309 17,673
Other Adjustments (1,051) 229 (837)
Effective Tax Rate $ 169,779 $ (29,868) $ 502,209
Percent      
U.S. Federal Statutory Tax Rate 21.00% 21.00% 21.00%
State Income Taxes, Net of Federal 4.70% 3.80% 3.80%
Effect of Changes in Tax Laws or Rates 0.30% (2.30%) 0.00%
Research and development tax credits (1.80%) (0.70%) (1.30%)
Energy-related tax credits (4.50%) 12.70% 0.00%
Foreign Tax Credits 0.00% 0.00% 0.30%
Changes in Valuation Allowances (0.60%) 2.00% (2.00%)
Share-based payment awards 0.10% 0.00% 0.00%
Other 0.00% (0.40%) 0.00%
Changes in Unrecognized Tax Benefits 2.00% (11.10%) 0.80%
Other Adjustments (0.10%) (0.20%) 0.00%
Effective Tax Rate 21.10% 24.80% 22.60%
Tax Jurisdiction of Domicile [Extensible Enumeration] PENNSYLVANIA    
v3.25.4
INCOME TAXES - Schedule of Reconciliation of Unrecognized Tax Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Unrecognized Tax Benefits [Roll Forward]      
Balance at Beginning of Period $ 113,227 $ 99,918  
Additions based on tax positions related to the current year 17,341 18,224  
Additions for tax positions of prior years 1,821 0  
Reductions for tax positions of prior years (3,355) (4,915) $ (4,915)
Balance at End of Period $ 129,034 $ 113,227 $ 99,918
v3.25.4
INCOME TAXES - Income Taxes Paid (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Disclosure [Abstract]      
U.S. Federal $ 2,500 $ 650 $ 0
Pennsylvania 4,898 5,402 7,327
Total Income Taxes Paid $ 7,398 $ 6,052 $ 7,327
v3.25.4
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Balance, Beginning of Year $ 132,064 $ 113,212
Obligations Divested (1,778) (134)
Accretion Expense 11,703 9,486
Obligations Incurred 9,540 2,172
Obligations Settled (8,072) (7,475)
Revisions in Estimated Cash Flows 40,669 14,803
Balance, End of Year $ 184,126 $ 132,064
v3.25.4
PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Property, Plant and Equipment [Abstract]    
Intangible Drilling Cost $ 6,755,849 $ 6,171,177
Gas Gathering Equipment 2,771,747 2,660,668
Gas Wells and Related Equipment 1,833,856 1,657,272
Proved Gas Properties 1,457,919 1,396,631
Unproved Gas Properties 747,528 721,692
Surface Land and Other Equipment 179,676 180,408
Other 310,649 250,100
Total Property, Plant and Equipment 14,057,224 13,037,948
Less: Accumulated Depreciation, Depletion and Amortization 6,193,871 5,653,837
Total Property, Plant and Equipment—Net $ 7,863,353 $ 7,384,111
v3.25.4
PROPERTY, PLANT AND EQUIPMENT - Schedule of Oil and Gas, Full Cost Method, Amortization Expense (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Property, Plant and Equipment [Line Items]    
Unproved Gas Properties $ 747,528 $ 721,692
Total Property, Plant and Equipment 14,057,224 13,037,948
Assets amortized by units of production    
Property, Plant and Equipment [Line Items]    
Unproved Gas Properties 747,528 721,692
Advance Royalties 1,721 2,026
Total Property, Plant and Equipment $ 749,249 $ 723,718
v3.25.4
GOODWILL AND OTHER INTANGIBLE ASSETS - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]      
Accumulated impairment losses on goodwill $ 473,045 $ 473,045  
Goodwill $ 323,314 323,314  
Useful life, customer relationship intangible assets 17 years    
Amortization expense $ 6,552 $ 6,553 $ 6,552
Estimated annual amortization expense, year 1 6,552    
Estimated annual amortization expense, year 2 6,552    
Estimated annual amortization expense, year 3 6,552    
Estimated annual amortization expense, year 4 6,552    
Estimated annual amortization expense, year 5 $ 6,552    
v3.25.4
GOODWILL AND OTHER INTANGIBLE ASSETS - Schedule of Carrying Amount and Accumulated Amortization of Intangible Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]    
Gross Amortizable Asset - Customer Relationships $ 109,752 $ 109,752
Less: Accumulated Amortization - Customer Relationships 52,419 45,867
Total Other Intangible Assets, net $ 57,333 $ 63,885
v3.25.4
REVOLVING CREDIT FACILITIES (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
May 14, 2025
May 13, 2025
Dec. 31, 2024
May 17, 2024
Convertible 2.25% Senior Notes Due 2026          
Short-term Debt [Line Items]          
Stated rate, debt instrument 2.25%        
Percentage of aggregate commitments available under credit facility 20.00%        
Senior Notes due January 2029          
Short-term Debt [Line Items]          
Stated rate, debt instrument 6.00%        
Percentage of aggregate commitments available under credit facility 20.00%        
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) 1.00%        
One-Month LIBOR | CNXM          
Short-term Debt [Line Items]          
Basis spread on variable rate (as a percent) 1.00%        
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) 0.75%        
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) 2.00%        
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) 1.85%        
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]          
Initial borrowing base   $ 2,400,000 $ 2,250,000    
Elected commitments         $ 1,400,000
Minimum current ratio 1.00        
Borrowings outstanding $ 200,000     $ 43,450  
Weighted average interest rate 5.69%     6.45%  
Letters of credit outstanding $ 27,997     $ 27,156  
Borrowings and issuance of letters of credit remaining capacity 1,172,003     1,329,394  
Revolving Credit Facility | CNXM          
Short-term Debt [Line Items]          
Borrowings outstanding $ 32,750     $ 16,050  
Weighted average interest rate 5.58%     6.75%  
Letters of credit outstanding $ 0     $ 0  
Letters of credit aggregate sub-limit         $ 600,000
Interest coverage ratio 2.50        
Revolving credit available for borrowing $ 567,250     $ 583,950  
Revolving Credit Facility | Minimum | CNXM          
Short-term Debt [Line Items]          
Maximum net leverage ratio 5.00        
Revolving Credit Facility | Maximum          
Short-term Debt [Line Items]          
Net leverage ratio 3.50        
Revolving Credit Facility | Maximum | CNXM          
Short-term Debt [Line Items]          
Maximum net leverage ratio 5.25        
Secured leverage ratio 3.25        
v3.25.4
OTHER ACCRUED LIABILITIES (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Other Liabilities Disclosure [Abstract]    
Royalties $ 121,078 $ 100,518
Accrued Interest 50,871 45,812
Current Portion Settlement - See Note 11 23,216 7,080
Short-Term Incentive Compensation 22,658 22,580
Transportation Charges 21,706 17,922
Deferred Revenue 14,589 20,696
Accrued Other Taxes 8,084 9,216
Accrued Payroll & Benefits 6,884 7,357
Purchased Gas Payable 554 143
Other 32,614 15,125
Current Portion of Long-Term Liabilities:    
Asset Retirement Obligations 21,075 12,875
Salary Retirement 2,647 1,908
Total Other Accrued Liabilities $ 325,976 $ 261,232
v3.25.4
LONG-TERM DEBT - Schedule of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2020
Mar. 31, 2020
Debt Instrument [Line Items]        
Principal     $ 1  
Net Carrying Amount $ 2,421,359 $ 2,166,000    
Unamortized Issuance Costs 8,062 9,386    
Less: Current Portion 208,095 327,766    
Long-Term Debt $ 2,213,264 1,838,234    
Convertible 7.25% Senior Notes Due 2032        
Debt Instrument [Line Items]        
Stated rate, debt instrument 7.25%      
Principal $ 600,000      
Debt instrument, unamortized discount 5,160 4,479    
Net Carrying Amount $ 594,840 395,521    
Senior Notes due January 2029        
Debt Instrument [Line Items]        
Stated rate, debt instrument 6.00%      
Net Carrying Amount $ 500,000 500,000    
Senior Notes due January 2031        
Debt Instrument [Line Items]        
Stated rate, debt instrument 7.375%      
Principal $ 500,000 500,000    
Debt instrument, unamortized discount 3,800 4,554    
Net Carrying Amount $ 496,200 495,446    
Senior Notes due April 2030        
Debt Instrument [Line Items]        
Stated rate, debt instrument 4.75%      
Principal $ 400,000 400,000    
Debt instrument, unamortized discount 2,500 3,077    
Net Carrying Amount $ 397,500 396,923    
Convertible Senior Notes due 2026        
Debt Instrument [Line Items]        
Stated rate, debt instrument 2.25%      
Principal $ 208,556 330,654    
Debt instrument, unamortized discount 425 2,658    
Net Carrying Amount 208,131 327,996    
Revolving Credit Facility        
Debt Instrument [Line Items]        
Principal       $ 160,000
Revolving Credit Facility | CNX Revolving Credit Facility        
Debt Instrument [Line Items]        
Net Carrying Amount 200,000 43,450    
Revolving Credit Facility | CNX Midstream Partners LP Revolving Credit Facility        
Debt Instrument [Line Items]        
Net Carrying Amount $ 32,750 $ 16,050    
v3.25.4
LONG-TERM DEBT - Maturities of Long-Term Debt (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Debt Disclosure [Abstract]  
2026 $ 208,556
2027 0
2028 0
2029 732,750
2030 400,000
Thereafter 1,100,000
Total Long-Term Debt Maturities $ 2,441,306
v3.25.4
LONG-TERM DEBT - Narrative (Details)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 15, 2025
USD ($)
$ / shares
shares
Dec. 31, 2025
USD ($)
shares
Dec. 31, 2024
USD ($)
shares
Dec. 31, 2023
USD ($)
shares
Dec. 31, 2022
USD ($)
Dec. 31, 2020
USD ($)
day
$ / shares
Debt Instrument [Line Items]            
Principal           $ 1
Loss on debt extinguishment   $ 842 $ 7,043 $ 0    
Proceeds from issuance of convertible senior notes           $ 334,650
Common Stock            
Debt Instrument [Line Items]            
Issuance related to convertible debt (in shares) | shares   9,509,188 0 0    
Convertible 2.25% Senior Notes Due 2026            
Debt Instrument [Line Items]            
Stated rate, debt instrument   2.25%        
New Notes - Convertible 7.25% Senior Notes Due 2032            
Debt Instrument [Line Items]            
Principal   $ 200,000        
Debt instrument, price, percentage of par   100.50%        
Underwriter discount and issuance costs   $ 1,500        
Convertible 7.25% Senior Notes Due 2032            
Debt Instrument [Line Items]            
Stated rate, debt instrument   7.25%        
Principal   $ 600,000        
Initial Notes - Convertible 7.25% Senior Notes Due 2032            
Debt Instrument [Line Items]            
Principal     $ 400,000      
Debt instrument, unamortized premium     $ 5,000      
Senior Notes due March 2027            
Debt Instrument [Line Items]            
Stated rate, debt instrument     7.25%      
Purchase and retirement of long term debt   350,000 $ 350,000      
Convertible Notes            
Debt Instrument [Line Items]            
Purchase of outstanding debt         $ 14,346  
Convertible Notes | Convertible 2.25% Senior Notes Due 2026            
Debt Instrument [Line Items]            
Stated rate, debt instrument 2.25%         2.25%
Principal $ 122,098 208,556 $ 330,654     $ 345,000
Conversion price (in usd per share) | $ / shares $ 12.84         $ 12.84
Additional cash consideration $ 855          
Loss on debt extinguishment   $ 842        
Conversion rate (in shares)           77.8816
Debt issuance costs gross           $ 10,350
Convertible Notes | Convertible 2.25% Senior Notes Due 2026 | Common Stock            
Debt Instrument [Line Items]            
Issuance related to convertible debt (in shares) | shares 9,509,188          
Convertible Notes | Convertible 2.25% Senior Notes Due 2026 | Debt Instrument, Redemption, Period One            
Debt Instrument [Line Items]            
Threshold percentage of stock price trigger           130.00%
Threshold trading days | day           20
Threshold consecutive trading days | day           30
Convertible Notes | Convertible 2.25% Senior Notes Due 2026 | Debt Instrument, Redemption, Period Two            
Debt Instrument [Line Items]            
Threshold percentage of stock price trigger           98.00%
Threshold trading days | day           5
Threshold consecutive trading days | day           10
Convertible Notes | Convertible 2.25% Senior Notes Due 2026, Additional Option To Initial Purchasers            
Debt Instrument [Line Items]            
Principal           $ 45,000
Convertible Notes | Convertible 2.25% Senior Notes Due 2026, Liability Component            
Debt Instrument [Line Items]            
Debt issuance costs gross           7,024
Convertible Notes | Convertible 2.25% Senior Notes Due 2026, Equity Component            
Debt Instrument [Line Items]            
Debt issuance costs gross           3,326
Capped Call Transaction            
Debt Instrument [Line Items]            
Cost incurred in connection with capped calls           $ 35,673
Capped Call Transaction | Minimum | Call Option            
Debt Instrument [Line Items]            
Strike price (in usd per share) | $ / shares           $ 12.84
Capped Call Transaction | Maximum | Call Option            
Debt Instrument [Line Items]            
Strike price (in usd per share) | $ / shares           $ 18.19
v3.25.4
LONG-TERM DEBT - Schedule of Convertible Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 15, 2025
Dec. 31, 2024
Dec. 31, 2020
Liability Component:        
Principal       $ 1
Unamortized Issuance Costs $ (8,062)   $ (9,386)  
Net Carrying Amount 2,421,359   2,166,000  
Convertible 2.25% Senior Notes Due 2026 | Convertible Notes        
Liability Component:        
Principal 208,556 $ 122,098 330,654 $ 345,000
Unamortized Issuance Costs (425)   (2,658)  
Net Carrying Amount 208,131   327,996  
Fair Value $ 596,798   $ 953,613  
v3.25.4
LONG-TERM DEBT - Schedule of Interest (Details) - Convertible Notes - Convertible 2.25% Senior Notes Due 2026 - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Debt Instrument [Line Items]    
Contractual Interest Expense $ 7,333 $ 7,440
Amortization of Issuance Costs 1,922 1,928
Total Interest Expense $ 9,255 $ 9,368
v3.25.4
LEASES - Narrative (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Jan. 02, 2024
Lessee, Lease, Description [Line Items]    
Unrecorded unconditional purchase obligation   $ 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) 5 years  
v3.25.4
LEASES - Schedule of Components of Lease Cost (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]      
Operating Lease Cost $ 58,694 $ 60,572 $ 63,087
Finance Lease Cost:      
Amortization of Right-of-Use Assets 7,054 2,898 1,628
Interest on Lease Liabilities 1,703 814 429
Short-term Lease Cost 3,950 1,533 2,357
Variable Lease Cost 0 4,517 12,401
Total Lease Cost $ 71,401 $ 70,334 $ 79,902
v3.25.4
LEASES - Schedule of Balance Sheet Information (Details) (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Operating Leases:    
Operating Lease Right-of-Use Assets $ 150,310 $ 98,713
Current Portion of Operating Lease Obligations 48,453 51,474
Operating Lease Obligations 104,955 49,519
Total Operating Lease Liabilities 153,408 100,993
Finance Leases:    
Property, Plant and Equipment 40,615 31,751
Less—Accumulated Depreciation, Depletion and Amortization 11,735 5,539
Property, Plant and Equipment—Net 28,880 26,212
Current Portion of Finance Lease Obligations 5,095 4,236
Finance Lease Obligations 24,991 21,040
Total Finance Lease Liabilities $ 30,086 $ 25,276
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] Total Property, Plant and Equipment—Net Total Property, Plant and Equipment—Net
v3.25.4
LEASES - Schedule of Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:      
Operating Cash Flows for Operating Leases $ 58,644 $ 61,475 $ 64,139
Operating Cash Flows for Finance Leases 1,703 814 429
Financing Cash Flows for Finance Leases 4,465 2,409 1,627
Right-of-Use Assets Obtained in Exchange for Lease Obligations:      
Operating Leases 103,296 13,996 19,477
Finance Leases $ 9,568 $ 20,407 $ 6,178
v3.25.4
LEASES - Schedule of Maturity of Lease Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Operating Leases    
2026 $ 56,399  
2027 49,306  
2028 44,983  
2029 6,620  
2030 6,624  
Thereafter 7,225  
Total Lease Payments 171,157  
Less: Interest 17,749  
Present Value of Lease Liabilities 153,408 $ 100,993
Finance Leases    
2026 6,874  
2027 6,772  
2028 11,158  
2029 2,810  
2030 2,293  
Thereafter 6,271  
Total Lease Payments 36,178  
Less: Interest 6,092  
Present Value of Lease Liabilities $ 30,086 $ 25,276
v3.25.4
LEASES - Schedule of Terms and Discount Rates (Details)
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]      
Operating leases, weighted average remaining lease term 3 years 7 months 17 days 3 years 7 months 28 days 3 years 7 months 2 days
Finance leases, weighted average remaining lease term 4 years 4 months 6 days 4 years 4 months 6 days 4 years 29 days
Operating leases, weighted average discount rate 6.16% 5.04% 4.84%
Finance leases, weighted average discount rate 6.08% 6.32% 7.35%
v3.25.4
PENSION - Schedule of Reconciliation of Changed in Benefit Obligations, Plan Assets, and Funded Status of Pension Benefits (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Change in Benefit Obligation:      
Benefit Obligation at Beginning of Period $ 31,699 $ 33,541  
Interest Cost 1,653 1,657 $ 1,675
Actuarial Loss (Gain) 328 (1,696)  
Benefits and Other Payments (1,809) (1,803)  
Benefit Obligation at End of Period 31,871 31,699 33,541
Change in Plan Assets:      
Fair Value of Plan Assets at Beginning of Period 0 0  
Company Contributions 1,809 1,803  
Benefits and Other Payments (1,809) (1,803)  
Fair Value of Plan Assets at End of Period 0 0 $ 0
Funded Status:      
Current Liabilities (2,647) (1,908)  
Noncurrent Liabilities (29,224) (29,791)  
Net Obligation Recognized (31,871) (31,699)  
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:      
Net Actuarial Loss 7,402 7,235  
Prior Service Cost 399 620  
Total 7,801 7,855  
Net Amount Recognized 5,679 5,712  
Accumulated Defined Benefit Plans Adjustment Attributable to Parent      
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of:      
Less: Tax Benefit $ 2,122 $ 2,143  
v3.25.4
PENSION - Schedule of Components of Net Periodic Benefit Cost (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Retirement Benefits [Abstract]      
Interest Cost $ 1,653 $ 1,657 $ 1,675
Amortization of Prior Service Cost 221 221 222
Recognized Net Actuarial Loss 161 223 173
Net Periodic Benefit Cost $ 2,035 $ 2,101 $ 2,070
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
v3.25.4
PENSION - Schedule of Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Retirement Benefits [Abstract]    
Projected Benefit Obligation $ 31,871 $ 31,699
Accumulated Benefit Obligation 31,871 31,699
Fair Value of Plan Assets $ 0 $ 0
v3.25.4
PENSION - Schedule of Weighted Average Assumptions (Details)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]      
Discount Rate 5.35% 5.65%  
Rate of Compensation Increase 0.00% 0.00%  
Interest Credited Rate 5.31% 5.20%  
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]      
Discount Rate 5.65% 5.15% 5.43%
Rate of Compensation Increase 0.00% 0.00% 0.00%
Interest Credited Rate 5.35% 5.04% 4.81%
v3.25.4
PENSION - Schedule of Expected Future Benefit Payment (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Retirement Benefits [Abstract]  
2026 $ 2,647
2027 2,649
2028 2,651
2029 2,655
2030 2,662
Year 2031-2035 $ 13,155
v3.25.4
STOCK-BASED COMPENSATION - Narrative (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
employeePopulation
shares
Dec. 31, 2024
USD ($)
shares
Dec. 31, 2023
USD ($)
May 31, 2020
shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Common stock available for grant (in shares) | shares 3,833,203      
Stock-based compensation expense $ 23,679 $ 20,091 $ 20,235  
Deferred tax benefit from stock-based compensation 12,200 $ 14,243 6,983  
Unrecognized compensation cost related to nonvested awards $ 37,009      
Recognition period, weighted average 2 years 5 months 23 days      
Number of distinct employee populations | employeePopulation 2      
Options outstanding (in shares) | shares 679,910 947,257    
Tax impact from option exercises $ 1,871 $ 5,196 529  
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      
Expiration period 10 years      
Award vesting period 3 years      
Intrinsic value of options exercised $ 7,362 19,608 2,015  
Cash received from option exercises $ 2,094 2,689 1,760  
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 368,895      
Anti-Dilutive Options | Employee        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Options outstanding (in shares) | shares 311,015      
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 $ 17,951 9,713 18,383  
Fair value of performance share units vested $ 6,069 8,002 4,563  
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      
Anti-Dilutive Restricted Stock Units        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Fair value of RSUs granted during the year $ 15,892 15,810 16,194  
Fair value of restricted stock units vested during the year $ 14,607 $ 12,671 $ 12,321  
Anti-Dilutive Restricted Stock Units | Director        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Award vesting period 1 year      
v3.25.4
STOCK-BASED COMPENSATION - Schedule of Options Granted, Assumptions and Weighted Average Fair Value (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Fair value of options granted during the year $ 23,679 $ 20,091 $ 20,235  
Stock Option        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Fair value of options granted during the year $ 115 $ 115 $ 115  
Weighted average fair value of grants (in usd per share)   $ 10.40 $ 7.06  
Risk-free interest rate (as a percent)   4.49% 3.24%  
Expected dividend yield (as a percent)   0.00% 0.00%  
Expected forfeiture rate (as a percent)   0.00% 0.00%  
Expected volatility (as a percent)   41.00% 48.70%  
Expected term in years   5 years 6 months 5 years 6 months 0 years
v3.25.4
STOCK-BASED COMPENSATION - Schedule of Stock and Performance Options Rollforward (Details)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
$ / shares
shares
Shares  
Beginning balance (in shares) | shares 947,257
Exercised (in shares) | shares (267,347)
Ending balance (in shares) | shares 679,910
Exercisable (in shares) | shares 679,910
Weighted Average Exercise Price  
Beginning balance (in usd per share) | $ / shares $ 10.48
Exercised (in usd per share) | $ / shares 7.83
Ending balance (in usd per share) | $ / shares 11.53
Exercisable (in usd per share) | $ / shares $ 11.53
Weighted average remaining contractual term (in years), outstanding 2 years 14 days
Weighted average remaining contractual term (in years), exercisable 2 years 14 days
Aggregate intrinsic value, outstanding | $ $ 17,163
Aggregate intrinsic value, exercisable | $ $ 17,163
v3.25.4
STOCK-BASED COMPENSATION - Schedule of Restricted and Performance Stock Unit Rollforward (Details) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Restricted Stock Units    
Number of Shares    
Beginning nonvested balance (in shares) 1,430,084  
Granted (in shares) 485,203  
Vested (in shares) (772,947)  
Forfeited (in shares) (46,282)  
Ending nonvested balance (in shares) 1,096,058  
Weighted Average Grant Date Fair Value    
Beginning nonvested balance (in usd per share) $ 24.84 $ 18.60
Granted (in usd per share) 32.75  
Vested (in usd per share) 18.09  
Forfeited (in usd per share) 27.68  
Ending nonvested balance (in usd per share) $ 24.84  
Performance Share Units    
Number of Shares    
Beginning nonvested balance (in shares) 2,655,861  
Granted (in shares) 760,635  
Vested (in shares) (495,622)  
Forfeited (in shares) (58,199)  
Ending nonvested balance (in shares) 2,862,675  
Weighted Average Grant Date Fair Value    
Beginning nonvested balance (in usd per share) $ 14.63 $ 11.98
Granted (in usd per share) 23.60  
Vested (in usd per share) 12.25  
Forfeited (in usd per share) 21.45  
Ending nonvested balance (in usd per share) $ 14.63  
v3.25.4
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
May 31, 2025
Other Significant Noncash Transactions [Line Items]        
Interest (Net of Amounts Capitalized) $ 154,598 $ 136,263 $ 122,279  
Restricted Cash 12,685 37,875   $ 10,100
Notes Received from Property Sales        
Other Significant Noncash Transactions [Line Items]        
Capital expenditures incurred, not yet paid $ 59,814 $ 30,905 $ 28,198  
v3.25.4
CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS - Schedules of Concentration of Risk, by Risk Factor (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Concentration Risk [Line Items]    
Total Accounts Receivable Trade $ 264,658 $ 179,547
Accounts Receivable | Customer Concentration Risk    
Concentration Risk [Line Items]    
Allowance for Credit Losses (84) (84)
Total Accounts Receivable Trade 264,658 179,547
Accounts Receivable | Customer Concentration Risk | Gas Wholesalers    
Concentration Risk [Line Items]    
Accounts receivable trade before allowance for credit losses 244,102 151,031
Accounts Receivable | Customer Concentration Risk | NGL, Condensate & Processing Facilities    
Concentration Risk [Line Items]    
Accounts receivable trade before allowance for credit losses 14,665 22,404
Accounts Receivable | Customer Concentration Risk | Other    
Concentration Risk [Line Items]    
Accounts receivable trade before allowance for credit losses $ 5,975 $ 6,196
v3.25.4
CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Concentration Risk [Line Items]      
Receivables related to contracts with customers $ 264,658 $ 179,547  
NRG Business      
Concentration Risk [Line Items]      
Revenue from contracts with customers 223,210 132,935 $ 165,465
Direct Energy Business Marketing LLC      
Concentration Risk [Line Items]      
Revenue from contracts with customers 208,775    
Citadel Energy Marketing LLC      
Concentration Risk [Line Items]      
Revenue from contracts with customers 205,993 134,909 $ 180,039
Accounts Receivable | Customer Concentration Risk      
Concentration Risk [Line Items]      
Receivables related to contracts with customers 264,658 179,547  
Accounts Receivable | Customer Concentration Risk | NRG Business      
Concentration Risk [Line Items]      
Receivables related to contracts with customers $ 34,293 $ 15,018  
Revenue from Contract with Customer Benchmark | Customer Concentration Risk | NRG Business      
Concentration Risk [Line Items]      
Percentage of revenue (more than) 10.00% 10.00% 10.00%
Revenue from Contract with Customer Benchmark | Customer Concentration Risk | Citadel Energy Marketing LLC      
Concentration Risk [Line Items]      
Percentage of revenue (more than) 10.00% 10.00% 10.00%
v3.25.4
FAIR VALUE OF FINANCIAL INSTRUMENTS - Schedule of Fair Value, Assets Measured on Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]        
Gas derivatives settled not paid $ 58,387      
Commodity Derivatives        
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]        
Derivative asset   $ 2,309    
Gas derivatives settled not paid $ 58,387 23,212 $ 6,741 $ 77,662
Level 1 | Commodity Derivatives        
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   (295,849) (536,046)  
Level 3 | Commodity Derivatives        
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]        
Derivative asset   $ 0 $ 0  
v3.25.4
FAIR VALUE OF FINANCIAL INSTRUMENTS - Schedule of Fair Value, Assets and Liabilities Measured on Nonrecurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
May 31, 2025
Dec. 31, 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]      
Cash and Cash Equivalents $ 779   $ 17,198
Restricted Cash 12,685 $ 10,100 37,875
Long-Term Debt (Excluding Debt Issuance Costs) 2,421,359   2,166,000
Carrying Amount      
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]      
Cash and Cash Equivalents 779   17,198
Restricted Cash 12,685   37,875
Long-Term Debt (Excluding Debt Issuance Costs) 2,429,421   2,175,386
Fair Value      
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]      
Cash and Cash Equivalents 779   17,198
Restricted Cash 12,685   37,875
Long-Term Debt (Excluding Debt Issuance Costs) $ 2,850,144   $ 2,785,556
v3.25.4
DERIVATIVE INSTRUMENTS - Narrative (Details) - USD ($)
$ in Thousands
 1 Months Ended
Mar. 31, 2020
Dec. 31, 2020
Derivative [Line Items]    
Principal   $ 1
Interest Rate Swap on Revolving Credit Facility | Long    
Derivative [Line Items]    
Put option, basis points (as a percent) 0.00%  
Derivative term of contract 4 years  
Derivative notional amount $ 250,000  
Revolving Credit Facility    
Derivative [Line Items]    
Principal $ 160,000  
v3.25.4
DERIVATIVE INSTRUMENTS - Schedule of Notional Amounts of Derivative Instruments (Details)
Mcf in Millions
 12 Months Ended
Dec. 31, 2025
Mcf
MBbls
Dec. 31, 2024
Mcf
MBbls
Natural Gas Commodity Swaps | Natural Gas Commodity Swaps (Bcf)    
Derivative Instruments, Gain (Loss) [Line Items]    
Derivative notional amount (in Bcf) 929.8 1,163.7
Natural Gas Commodity Swaps | NGLs    
Derivative Instruments, Gain (Loss) [Line Items]    
Derivative notional amount (in Bcf) | MBbls 180,000.0 351,000.0
Natural Gas Basis Swaps (Bcf)    
Derivative Instruments, Gain (Loss) [Line Items]    
Derivative notional amount (in Bcf) 585.5 688.7
v3.25.4
DERIVATIVE INSTRUMENTS - Schedule of Fair Value of Derivative Instruments (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Derivative [Line Items]    
Total Current Assets $ 106,068 $ 87,925
Total Other Non-Current Assets 134,396 160,183
Total Current Liabilities 377,945 354,621
Total Non-Current Liabilities 158,368 429,533
Natural Gas Commodity Swaps | Natural Gas Revenue    
Derivative [Line Items]    
Total Current Assets 74,064 45,336
Total Other Non-Current Assets 117,524 117,875
Total Current Liabilities 323,169 300,994
Total Non-Current Liabilities 101,387 364,662
Natural Gas Commodity Swaps | NGLs    
Derivative [Line Items]    
Total Current Assets 1,730 90
Total Current Liabilities 0 839
Natural Gas Basis Swaps    
Derivative [Line Items]    
Total Current Assets 30,274 42,499
Total Other Non-Current Assets 16,872 42,308
Total Current Liabilities 54,776 52,788
Total Non-Current Liabilities $ 56,981 $ 64,871
v3.25.4
DERIVATIVE INSTRUMENTS - Schedule of Effect of Derivative Instrument on Statement of Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Derivative [Line Items]        
Realized (Loss) Gain on Commodity Derivative Instruments: $ (181,020) $ 281,195 $ 163,026  
Unrealized Gain (Loss) on Commodity Derivative Instruments: 277,681 (453,600) 1,765,626  
Gain (Loss) on Commodity Derivative Instruments 96,661 (172,405) 1,928,652  
Gas derivatives settled not paid 58,387      
Natural Gas Commodity Swaps        
Derivative [Line Items]        
Derivative asset   2,309    
Gas derivatives settled not paid 58,387 23,212 6,741 $ 77,662
Commodity Derivatives        
Derivative [Line Items]        
Derivative asset   2,309    
Gas derivatives settled not paid   23,212 900  
Interest Rate Swaps        
Derivative [Line Items]        
Gain (Loss) on Commodity Derivative Instruments 0 4 744  
Cash Received in Settlement of Interest Rate Swaps 0 1,103 4,207  
Unrealized Loss on Interest Rate Swaps 0 (1,099) (3,463)  
Natural Gas Revenue | Natural Gas Commodity Swaps        
Derivative [Line Items]        
Realized (Loss) Gain on Commodity Derivative Instruments: (188,791) 275,672 62,567  
Unrealized Gain (Loss) on Commodity Derivative Instruments: 306,779 (286,567) 1,858,060  
Gain (Loss) on Commodity Derivative Instruments 117,988 (10,895) 1,920,627  
Natural Gas Revenue | Natural Gas Basis Swaps        
Derivative [Line Items]        
Realized (Loss) Gain on Commodity Derivative Instruments: 7,208 4,900 98,582  
Unrealized Gain (Loss) on Commodity Derivative Instruments: (31,180) (165,566) (93,222)  
Gain (Loss) on Commodity Derivative Instruments (23,972) (160,666) 5,360  
NGL Commodity Swaps | Natural Gas Commodity Swaps        
Derivative [Line Items]        
Realized (Loss) Gain on Commodity Derivative Instruments: 563 623 1,877  
Unrealized Gain (Loss) on Commodity Derivative Instruments: 2,082 (1,467) 788  
Gain (Loss) on Commodity Derivative Instruments $ 2,645 $ (844) $ 2,665  
v3.25.4
COMMITMENTS AND CONTINGENT LIABILITIES - Narrative (Details) - Settlement Agreement Between Murray And UMWA
$ in Thousands
Mar. 04, 2024
USD ($)
Dec. 31, 2025
USD ($)
May 01, 2020
division
Loss Contingencies [Line Items]      
Litigation settlement, amount awarded to other party $ 75,000    
Loss contingency, period payable 5 years    
Loss contingency, accrual, noncurrent   $ 75,000  
Murray      
Loss Contingencies [Line Items]      
Number of retirees | division     2,159
v3.25.4
COMMITMENTS AND CONTINGENT LIABILITIES - Schedule of Maximum Potential Total of Future Payments Under Commitment Instruments (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Loss Contingencies [Line Items]  
Total Commitments $ 308,432
Less Than 1  Year  
Loss Contingencies [Line Items]  
Total Commitments 306,252
1-3 Years  
Loss Contingencies [Line Items]  
Total Commitments 1,414
3-5 Years  
Loss Contingencies [Line Items]  
Total Commitments 766
Beyond 5  Years  
Loss Contingencies [Line Items]  
Total Commitments 0
Firm Transportation | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 25,077
Firm Transportation | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 129,336
Firm Transportation | Less Than 1  Year | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 25,077
Firm Transportation | Less Than 1  Year | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 129,336
Firm Transportation | 1-3 Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Firm Transportation | 1-3 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Firm Transportation | 3-5 Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Firm Transportation | 3-5 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Firm Transportation | Beyond 5  Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Firm Transportation | Beyond 5  Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Other | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 2,920
Other | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 12,957
Other | Less Than 1  Year | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 2,920
Other | Less Than 1  Year | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 12,957
Other | 1-3 Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Other | 1-3 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Other | 3-5 Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Other | 3-5 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Other | Beyond 5  Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Other | Beyond 5  Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Employee-Related | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 2,250
Employee-Related | Less Than 1  Year | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 2,250
Employee-Related | 1-3 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Employee-Related | 3-5 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Employee-Related | Beyond 5  Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Environmental | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 40,005
Environmental | Less Than 1  Year | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 40,005
Environmental | 1-3 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Environmental | 3-5 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Environmental | Beyond 5  Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Financial Guarantees | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 93,000
Financial Guarantees | Less Than 1  Year | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 93,000
Financial Guarantees | 1-3 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Financial Guarantees | 3-5 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Financial Guarantees | Beyond 5  Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 27,997
Loss Contingencies by Secondary Nature of Contingency | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 277,548
Loss Contingencies by Secondary Nature of Contingency | Other Guarantees  
Loss Contingencies [Line Items]  
Total Commitments 2,887
Loss Contingencies by Secondary Nature of Contingency | Less Than 1  Year | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 27,997
Loss Contingencies by Secondary Nature of Contingency | Less Than 1  Year | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 277,548
Loss Contingencies by Secondary Nature of Contingency | Less Than 1  Year | Other Guarantees  
Loss Contingencies [Line Items]  
Total Commitments 707
Loss Contingencies by Secondary Nature of Contingency | 1-3 Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | 1-3 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | 1-3 Years | Other Guarantees  
Loss Contingencies [Line Items]  
Total Commitments 1,414
Loss Contingencies by Secondary Nature of Contingency | 3-5 Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | 3-5 Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | 3-5 Years | Other Guarantees  
Loss Contingencies [Line Items]  
Total Commitments 766
Loss Contingencies by Secondary Nature of Contingency | Beyond 5  Years | Letters of Credit:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | Beyond 5  Years | Surety Bonds:  
Loss Contingencies [Line Items]  
Total Commitments 0
Loss Contingencies by Secondary Nature of Contingency | Beyond 5  Years | Other Guarantees  
Loss Contingencies [Line Items]  
Total Commitments $ 0
v3.25.4
COMMITMENTS AND CONTINGENT LIABILITIES - Schedule of Unrecorded Unconditional Purchase Obligation (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Jan. 02, 2024
Unrecorded Unconditional Purchase Obligation [Line Items]    
Total Purchase Obligations   $ 18,823
Purchase Commitment    
Unrecorded Unconditional Purchase Obligation [Line Items]    
Less than 1 year $ 270,869  
1 - 3 years 479,607  
3 - 5 years 273,803  
More than 5 years 457,473  
Total Purchase Obligations $ 1,481,752  
v3.25.4
SEGMENT INFORMATION - Narrative (Details)
 12 Months Ended
Dec. 31, 2025
segment
Segment Reporting [Abstract]  
Number of reportable segments 2
v3.25.4
SEGMENT INFORMATION - Schedule of Industry Segment Results (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Gain (Loss) on Commodity Derivative Instruments $ 96,661 $ (172,405) $ 1,928,652
Other Revenue and Operating Income 183,396 193,647 129,860
Total Revenue and Other Operating Income 2,239,134 1,266,786 3,434,948
Lease Operating Expense 97,416 70,646 63,333
Production, Ad Valorem and Other Fees 31,200 27,554 27,946
Depreciation, Depletion and Amortization 574,114 485,754 433,586
Interest Expense 170,592 150,594 143,278
Other Segment Items 179,767 270,380 161,946
Total Costs and Expenses 1,436,193 1,387,148 1,212,023
Income (Loss) Before Income Tax 802,941 (120,362) 2,222,925
Segment Assets 9,094,446 8,511,903 8,626,657
Capital Expenditures 494,988 540,332 679,404
Investments in unconsolidated equity affiliates 5,709 18,380 13,682
Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 1,913,728 1,186,077 1,302,218
Purchased Gas Revenue      
Segment Reporting Information [Line Items]      
Revenue 45,349 59,467 74,218
Transportation, Gathering and Compression      
Segment Reporting Information [Line Items]      
Transportation, Gathering and Compression 383,104 382,220 381,934
NRG Business      
Segment Reporting Information [Line Items]      
Revenue 223,210 132,935 165,465
NRG Business | Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 223,210 132,935 165,465
Direct Energy Business Marketing LLC      
Segment Reporting Information [Line Items]      
Revenue 208,775    
Direct Energy Business Marketing LLC | Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 208,775    
Citadel Energy Marketing LLC      
Segment Reporting Information [Line Items]      
Revenue 205,993 134,909 180,039
Citadel Energy Marketing LLC | Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 205,993 134,909 180,039
Operating Segments      
Segment Reporting Information [Line Items]      
Revenue 2,028,246 1,313,852 1,442,995
Operating Segments | Environmental Attributes      
Segment Reporting Information [Line Items]      
Other Revenue and Operating Income 77,829 95,490 40,685
Other      
Segment Reporting Information [Line Items]      
Gain (Loss) on Commodity Derivative Instruments 277,613 (453,475) 1,765,690
Other Revenue and Operating Income 114,227 125,339 63,301
Total Revenue and Other Operating Income 438,939 (267,755) 1,904,271
Lease Operating Expense 71 570 (349)
Production, Ad Valorem and Other Fees 39 59 66
Depreciation, Depletion and Amortization 26,905 20,872 18,514
Interest Expense 170,592 150,594 143,278
Other Segment Items 179,767 270,380 161,946
Total Costs and Expenses 379,185 443,908 324,266
Income (Loss) Before Income Tax 59,754 (711,663) 1,580,005
Equity in earnings (loss) of affiliates 740 1,314 2,942
Segment Assets 967,123 922,085 1,021,207
Capital Expenditures 6,646 15,465 12,969
Other | Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 1,750 914 1,062
Other | Purchased Gas Revenue      
Segment Reporting Information [Line Items]      
Revenue 45,349 59,467 74,218
Other | Transportation, Gathering and Compression      
Segment Reporting Information [Line Items]      
Transportation, Gathering and Compression 1,811 1,433 811
Shale | Operating Segments      
Segment Reporting Information [Line Items]      
Gain (Loss) on Commodity Derivative Instruments (169,598) 260,395 151,408
Other Revenue and Operating Income 69,169 68,308 66,559
Total Revenue and Other Operating Income 1,663,532 1,408,747 1,388,360
Lease Operating Expense 73,302 48,079 43,740
Production, Ad Valorem and Other Fees 24,749 22,036 21,636
Depreciation, Depletion and Amortization 488,021 405,292 365,020
Interest Expense 0 0 0
Other Segment Items 0 0 0
Total Costs and Expenses 903,496 791,574 746,049
Income (Loss) Before Income Tax 760,036 617,173 642,311
Segment Assets 7,218,019 6,669,076 6,656,655
Capital Expenditures 443,714 495,538 629,631
Shale | Operating Segments | Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 1,763,961 1,080,044 1,170,393
Shale | Operating Segments | Purchased Gas Revenue      
Segment Reporting Information [Line Items]      
Revenue 0 0 0
Shale | Operating Segments | Transportation, Gathering and Compression      
Segment Reporting Information [Line Items]      
Transportation, Gathering and Compression 317,424 316,167 315,653
Coalbed Methane | Operating Segments      
Segment Reporting Information [Line Items]      
Gain (Loss) on Commodity Derivative Instruments (11,354) 20,675 11,554
Other Revenue and Operating Income 0 0 0
Total Revenue and Other Operating Income 136,663 125,794 142,317
Lease Operating Expense 24,043 21,997 19,942
Production, Ad Valorem and Other Fees 6,412 5,459 6,244
Depreciation, Depletion and Amortization 59,188 59,590 50,052
Interest Expense 0 0 0
Other Segment Items 0 0 0
Total Costs and Expenses 153,512 151,666 141,708
Income (Loss) Before Income Tax (16,849) (25,872) 609
Segment Assets 909,304 920,742 948,795
Capital Expenditures 44,628 29,329 36,804
Coalbed Methane | Operating Segments | Natural Gas, NGLs and Oil Revenue      
Segment Reporting Information [Line Items]      
Revenue 148,017 105,119 130,763
Coalbed Methane | Operating Segments | Purchased Gas Revenue      
Segment Reporting Information [Line Items]      
Revenue 0 0 0
Coalbed Methane | Operating Segments | Transportation, Gathering and Compression      
Segment Reporting Information [Line Items]      
Transportation, Gathering and Compression $ 63,869 $ 64,620 $ 65,470
v3.25.4
SEGMENT INFORMATION - Schedule of Reconciliation of Segment Information, Revenue and Other Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting, Revenue Reconciling Item [Line Items]      
Gain (Loss) on Commodity Derivative Instruments $ 96,661 $ (172,405) $ 1,928,652
Other Operating Income 114,227 125,339 63,301
Total Consolidated Revenue and Other Operating Income 2,239,134 1,266,786 3,434,948
Operating Segments      
Segment Reporting, Revenue Reconciling Item [Line Items]      
Total Segment Revenue from Contracts with External Customers $ 2,028,246 $ 1,313,852 $ 1,442,995
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) - Schedule of Capitalized Costs (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Extractive Industries [Abstract]    
Intangible Drilling Cost $ 6,755,849 $ 6,171,177
Gas Gathering Assets 2,771,747 2,660,668
Proved Gas Properties 1,457,919 1,396,631
Unproved Gas Properties 747,528 721,692
Gas Wells and Related Equipment 1,833,856 1,657,272
Other Gas Assets 186,346 136,138
Total Property, Plant and Equipment 13,753,245 12,743,578
Accumulated Depreciation, Depletion and Amortization (6,091,349) (5,561,023)
Net Capitalized Costs $ 7,661,896 $ 7,182,555
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) - Schedule of Costs Incurred for Property Acquisition, Exploration and Development (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Property Acquisitions      
Proved Properties $ 534,229 $ 10,362 $ 2,319
Unproved Properties 49,118 15,061 26,405
Development 432,082 500,402 637,711
Exploration 6,806 4,494 4,257
Total 1,022,235 530,319 670,692
Apex Transaction      
Property Acquisitions      
Proved Properties 523,256    
Unproved Properties 3,200    
Midstream      
Property Acquisitions      
Development $ 37,669 $ 23,135 $ 46,814
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) - Schedule of Results of Operations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Extractive Industries [Abstract]      
Natural Gas, NGLs and Oil Revenue $ 1,913,728 $ 1,186,077 $ 1,302,218
Realized Gain (Loss) on Commodity Derivative Instruments (181,020) 281,195 163,026
Unrealized (Loss) Gain on Commodity Derivative Instruments 277,681 (453,600) 1,765,626
Purchased Gas Revenue 45,349 59,467 74,218
Total Revenue 2,055,738 1,073,139 3,305,088
Lease Operating Expense 97,416 70,646 63,333
Production, Ad Valorem and Other Fees 31,200 27,554 27,946
Transportation, Gathering and Compression 383,104 382,220 381,934
Purchased Gas Costs 42,647 57,248 69,924
Exploration Costs 10,516 8,446 10,447
Depreciation, Depletion and Amortization 574,114 485,754 433,586
Total Costs 1,138,997 1,031,868 987,170
Pre-tax Operating Income 916,741 41,271 2,317,918
Income Tax Expense 193,432 10,235 523,849
Results of Operations for Producing Activities excluding Corporate and Interest Costs $ 723,309 $ 31,036 $ 1,794,069
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) - Schedule of Average Unit Prices and Average Production Costs (Details)
Mcfe in Thousands
 12 Months Ended
Dec. 31, 2025
dollarsPerMcfe
Mcfe
Dec. 31, 2024
dollarsPerMcfe
Mcfe
Dec. 31, 2023
dollarsPerMcfe
Mcfe
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)      
Production (MMcfe) | Mcfe 628,960 550,814 560,366
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) 3.04 2.15 2.32
Average Effects of Commodity Derivative Financial Settlements (per Mcfe) (0.31) 0.57 0.32
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe) 2.75 2.66 2.61
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe) 0.15 0.13 0.11
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) - Narrative (Details)
Mcf in Millions
 12 Months Ended
Dec. 31, 2025
well
Mcf
Dec. 31, 2024
well
Dec. 31, 2023
well
Extractive Industries [Abstract]      
Net development wells drilled 18.9 25.7 30.8
Net dry development wells drilled 0 0 0
Net exploratory wells drilled 0 0 0
Number of net dry exploratory wells 0 0 0
Net development wells drilled but uncompleted 10.00    
Exploratory wells, drilled uncompleted 0    
Gas delivery commitment, remaining contractual volume | Mcf 658.7    
Period from reserves booking for proved undeveloped locations to be fully developed 5 years 5 years 5 years
v3.25.4
SUPPLEMENTAL GAS DATA (unaudited) - Schedule of Producing Wells, Developed Acreage and Undeveloped Acreage (Details)
Dec. 31, 2025
a
well
Extractive Industries [Abstract]  
Working interest percentage 100.00%
Gross  
Proved Developed Acreage | a 428,042
Proved Undeveloped Acreage | a 26,092
Unproved Acreage | a 4,946,079
Total Acreage | a 5,400,213
Net  
Proved Developed Acreage | a 428,042
Proved Undeveloped Acreage | a 26,092
Unproved Acreage | a 3,517,208
Total Acreage | a 3,971,342
Working Interest  
Gross  
Producing Gas Wells | well 4,560
Producing Oil Wells | well 2
Net  
Producing Gas Wells | well 4,488
Producing Oil Wells | well 0
Royalty Interest  
Gross  
Producing Gas Wells | well 412
Producing Oil Wells | well 128
Net  
Producing Gas Wells | well 0
Producing Oil Wells | well 0