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2025-05-31

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________
FORM 10-Q
__________________________________________________
(Mark One)

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

For the quarterly period ended September 30, 2025
OR

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

For the transition period from to
Commission file number: 001-14901
__________________________________________________
CNX Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware |  | 51-0337383
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)

CNX Center
1000 Horizon Vue Drive
Canonsburg, PA 15317-6506
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (724) 485-4000

Securities registered pursuant to Section 12(b) of the Act: |  |
Title of each class |  | Trading Symbol(s) |  | Name of exchange on which registered
Common Stock ($.01 par value) |  | CNX |  | New York Stock Exchange
Preferred Share Purchase Rights |  | -- |  | New York Stock Exchange

__________________________________________________
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller Reporting Company ☐
Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class |  | Shares outstanding as of October 20, 2025
Common stock, $0.01 par value |  | 134,832,658

TABLE OF CONTENTS

|  | Page
PART I FINANCIAL INFORMATION |
ITEM 1. | Unaudited Condensed Consolidated Financial Statements |
| Consolidated Statements of Income for the three and nine months ended S eptember 30, 2025 and 2024 | 5
| Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2025 and 2024 | 6
| Consolidated Balance Sheets at September 30, 2025 and December 31, 2024 | 7
| Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2025 and 2024 | 10
| Consolidated Statements of Cash Flows for the nine months ended September 30, 2025 and 2024 | 11
| Notes to Unaudited Consolidated Financial Statements | 12
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 32
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk | 60
ITEM 4. | Controls and Procedures | 61
PART II OTHER INFORMATION |
ITEM 1. | Legal Proceedings | 62
ITEM 1A. | Risk Factors | 62
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 62
ITEM 5. | Other Information | 62
ITEM 6. | Exhibits | 63

GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are certain terms and abbreviations commonly used in the oil and gas industry and included within this Form 10-Q:
Bbl - one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
BBtu - one billion British Thermal Units.
Bcf - one billion cubic feet of natural gas.
Bcfe - one billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Btu - one British Thermal Unit.
Mbbls - one thousand barrels of oil or other liquid hydrocarbons.
Mcf - one thousand cubic feet of natural gas.
Mcfe - one thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
MMBtu - one million British Thermal Units.
MMcfe - one million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
NGL - natural gas liquids - those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation or other methods in gas processing plants.
Tcfe - one trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Basis – when referring to commodity pricing, the difference between the price for a commodity at a primary trading hub and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location, transportation capacity availability and contract pricing.
Blending - process of mixing dry and damp gas in order to meet downstream pipeline specifications.
Condensate - a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Conventional play - a term used in the oil and natural gas industry to refer to an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps utilizing conventional recovery methods.
Coalbed methane (CBM) - an unconventional form of natural gas found in coal deposits or coal seams.
Developed reserves - developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development well - a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry gas - natural gas that contains little to no liquid hydrocarbons.
Environmental attributes - items such as (but 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.
Exploratory well - a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
Exploration costs - costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) costs of topographical, geographical and geophysical studies and the rights to access the properties in order to conduct those studies, (ii) costs of carrying and retaining undeveloped properties, such as delay rentals and the maintenance of land and lease records, (iii) dry hole contributions (iv) costs of drilling and equipping exploratory wells, and (v) costs of drilling exploratory-type stratigraphic test wells.
Gob well - a well drilled or vent hole converted to a well which produces or is capable of producing coalbed methane or other natural gas from a distressed zone created above and below a mined-out coal seam by any prior full seam extraction of the coal.
Gross acres - the total acres in which a working interest is owned.
Gross wells - the total wells in which a working interest is owned.
Lease operating expense - costs of operating wells and equipment on a producing lease, many of which are recurring. Includes items such as water disposals, repairs and maintenance, equipment rental and operating supplies, among others.
Net - “net” natural gas or “net” acres are determined by adding the fractional ownership working interests the Company has in gross wells or acres.

Net acres - the number of acres an owner has out of a particular number of gross acres.
Net wells - the percentage of ownership interest in a well that an owner has based on the working interest.
NYMEX - New York Mercantile Exchange.
Physical sales - the buying and selling of natural gas through contracts between buyers and sellers. The parties agree to the physical delivery of a specific volume of natural gas over a particular period at a given price.
Play - a proven geological formation that contains commercial amounts of hydrocarbons.
Production costs - costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities, which become part of the cost of oil and natural gas produced.
Proved reserves - quantities of oil, natural gas, and natural gas liquids (NGLs) which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved developed reserves (PDPs) - proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves (PUDs) - proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
Reservoir - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Remediated mine gas (RMG) - formerly referred to as coal mine methane (CMM) - any gaseous hydrocarbon that is extracted or released through wells, degasification boreholes, ventilation or bleeder shafts for the purposes of degasifying underground coal mining operations. Remediated mine gas may be extracted or released within or above mining activities and produced during, before, or after mining activity occurs or had occurred in connection with the degasification activities.
Royalty interest - an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowners' royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Throughput - the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period.
TIL - turn-in-line; a well turned to sales.
Transportation, gathering and compression - cost incurred related to transporting natural gas to the ultimate point of sale. These costs also include costs related to physically preparing natural gas, natural gas liquids and condensate for ultimate sale which include costs related to processing, compressing, dehydrating and fractionating, among others.
Service well - a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.
Shale gas - an unconventional natural gas that is found trapped within shale formations.
Unconventional formations - a term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to achieve economic flow rates.
Undeveloped reserves - undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Unproved properties - properties with no proved reserves.
Wet gas - natural gas that contains significant heavy hydrocarbons, such as propane, butane and other liquid hydrocarbons.
Working interest - an interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

PART I : FINANCIAL INFORMATION
ITEM 1.CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data) | Three Months Ended |  | Nine Months Ended
(Unaudited) | September 30, |  | September 30,
Revenue and Other Operating Income: | 2025 |  | 2024 |  | 2025 |  | 2024
Natural Gas, NGLs and Oil Revenue | $ | 400,990 |  |  | $ | 259,459 |  |  | $ | 1,437,113 |  |  | $ | 821,664 |
Gain on Commodity Derivative Instruments | 131,695 |  |  | 88,964 |  |  | 24,596 |  |  | 110,587 |
Purchased Gas Revenue | 9,026 |  |  | 27,306 |  |  | 30,985 |  |  | 52,612 |
Other Revenue and Operating Income | 42,129 |  |  | 48,484 |  |  | 135,956 |  |  | 145,345 |
Total Revenue and Other Operating Income | 583,840 |  |  | 424,213 |  |  | 1,628,650 |  |  | 1,130,208 |
Costs and Expenses: |  |  |  |  |  |  |
Operating Expense |  |  |  |  |  |  |
Lease Operating Expense | 27,127 |  |  | 17,253 |  |  | 76,715 |  |  | 52,798 |
Production, Ad Valorem and Other Fees | 7,725 |  |  | 6,646 |  |  | 24,666 |  |  | 20,909 |
Transportation, Gathering and Compression | 97,053 |  |  | 96,274 |  |  | 289,165 |  |  | 284,633 |
Depreciation, Depletion and Amortization | 149,323 |  |  | 121,227 |  |  | 428,979 |  |  | 357,418 |
Exploration and Production Related Other Costs | 1,656 |  |  | 1,935 |  |  | 5,509 |  |  | 6,610 |
Purchased Gas Costs | 8,455 |  |  | 26,594 |  |  | 29,066 |  |  | 50,549 |
Selling, General, and Administrative Costs | 30,375 |  |  | 32,498 |  |  | 98,456 |  |  | 102,194 |
Other Operating Expense | 19,178 |  |  | 16,462 |  |  | 54,273 |  |  | 62,172 |
Total Operating Expense | 340,892 |  |  | 318,889 |  |  | 1,006,829 |  |  | 937,283 |
Other (Income) Expense |  |  |  |  |  |  |
Other Expense (Income) | 1,752 |  |  | (4,590) |  |  | 9,429 |  |  | (10,664) |
(Gain) Loss on Asset Sales and Abandonments, net | (67,460) |  |  | (10,570) |  |  | (94,759) |  |  | 8,912 |
Loss on Debt Extinguishment | — |  |  | — |  |  | — |  |  | 7,043 |
Interest Expense | 42,964 |  |  | 37,923 |  |  | 128,616 |  |  | 113,997 |
Total Other (Income) Expense | (22,744) |  |  | 22,763 |  |  | 43,286 |  |  | 119,288 |
Total Costs and Expenses | 318,148 |  |  | 341,652 |  |  | 1,050,115 |  |  | 1,056,571 |
Income Before Income Tax | 265,692 |  |  | 82,561 |  |  | 578,535 |  |  | 73,637 |
Income Tax Expense | 63,589 |  |  | 17,021 |  |  | 141,625 |  |  | 19,507 |
Net Income | $ | 202,103 |  |  | $ | 65,540 |  |  | $ | 436,910 |  |  | $ | 54,130 |
Earnings per Share |  |  |  |  |  |  |
Basic | $ | 1.45 |  |  | $ | 0.44 |  |  | $ | 3.05 |  |  | $ | 0.36 |
Diluted | $ | 1.21 |  |  | $ | 0.37 |  |  | $ | 2.57 |  |  | $ | 0.32 |
Dividends Declared | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |

The accompanying notes are an integral part of these financial statements.
5

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

| Three Months Ended |  | Nine Months Ended
(Dollars in thousands) | September 30, |  | September 30,
(Unaudited) | 2025 |  | 2024 |  | 2025 |  | 2024
Net Income | $ | 202,103 |  |  | $ | 65,540 |  |  | $ | 436,910 |  |  | $ | 54,130 |
Other Comprehensive Income: |  |  |  |  |  |  |
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $(26), $(30), $(78), $(90)) | 70 |  |  | 81 |  |  | 209 |  |  | 243 |
Comprehensive Income | $ | 202,173 |  |  | $ | 65,621 |  |  | $ | 437,119 |  |  | $ | 54,373 |

The accompanying notes are an integral part of these financial statements.
6

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| (Unaudited) |  |
(Dollars in thousands) | September 30, 2025 |  | December 31, 2024
ASSETS |  |  |
Current Assets: |  |  |
Cash and Cash Equivalents | $ | 4,735 |  |  | $ | 17,198 |
Restricted Cash | 10,168 |  |  | 37,875 |
Accounts and Notes Receivable: |  |  |
Trade, net | 141,264 |  |  | 179,547 |
Other Receivables, net | 56,596 |  |  | 17,859 |
Supplies Inventories | 30,822 |  |  | 14,572 |
Derivative Instruments | 100,076 |  |  | 87,925 |
Prepaid Expenses | 17,234 |  |  | 15,659 |
Total Current Assets | 360,895 |  |  | 370,635 |
Property, Plant and Equipment: |  |  |
Property, Plant and Equipment | 13,839,517 |  |  | 13,037,948 |
Less—Accumulated Depreciation, Depletion and Amortization | 6,054,758 |  |  | 5,653,837 |
Total Property, Plant and Equipment—Net | 7,784,759 |  |  | 7,384,111 |
Other Non-Current Assets: |  |  |
Operating Lease Right-of-Use Assets | 167,893 |  |  | 98,713 |
Derivative Instruments | 118,387 |  |  | 160,183 |
Goodwill | 323,314 |  |  | 323,314 |
Other Intangible Assets | 58,971 |  |  | 63,885 |
Restricted Cash | 2,430 |  |  | — |
Other | 87,469 |  |  | 111,062 |
Total Other Non-Current Assets | 758,464 |  |  | 757,157 |
TOTAL ASSETS | $ | 8,904,118 |  |  | $ | 8,511,903 |

The accompanying notes are an integral part of these financial statements.
7

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| (Unaudited) |  |
(Dollars in thousands, except per share data) | September 30, 2025 |  | December 31, 2024
LIABILITIES AND EQUITY |  |  |
Current Liabilities: |  |  |
Accounts Payable | $ | 110,649 |  |  | $ | 123,249 |
Derivative Instruments | 316,729 |  |  | 354,621 |
Current Portion of Finance Lease Obligations | 5,080 |  |  | 4,236 |
Current Portion of Long-Term Debt | 329,378 |  |  | 327,766 |
Current Portion of Operating Lease Obligations | 48,140 |  |  | 51,474 |
Other Accrued Liabilities | 255,313 |  |  | 261,232 |
Total Current Liabilities | 1,065,289 |  |  | 1,122,578 |
Non-Current Liabilities: |  |  |
Long-Term Debt | 2,247,199 |  |  | 1,838,234 |
Finance Lease Obligations | 26,209 |  |  | 21,040 |
Operating Lease Obligations | 122,477 |  |  | 49,519 |
Derivative Instruments | 251,206 |  |  | 429,533 |
Deferred Income Taxes | 836,354 |  |  | 696,136 |
Asset Retirement Obligations | 124,460 |  |  | 119,189 |
Other | 115,351 |  |  | 137,644 |
Total Non-Current Liabilities | 3,723,256 |  |  | 3,291,295 |
TOTAL LIABILITIES | 4,788,545 |  |  | 4,413,873 |
Stockholders’ Equity: |  |  |
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 135,887,339 Issued and Outstanding at September 30, 2025; 148,879,640 Issued and Outstanding at December 31, 2024 | 1,360 |  |  | 1,490 |
Capital in Excess of Par Value | 2,254,021 |  |  | 2,348,959 |
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding | — |  |  | — |
Retained Earnings | 1,865,695 |  |  | 1,753,293 |
Accumulated Other Comprehensive Loss | (5,503) |  |  | (5,712) |
TOTAL STOCKHOLDERS' EQUITY | 4,115,573 |  |  | 4,098,030 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 8,904,118 |  |  | $ | 8,511,903 |

The accompanying notes are an integral part of these financial statements.
8

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands) (Unaudited) | Common Stock |  | Capital in Excess of Par Value |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  |  |  |  |  | Total Equity
June 30, 2025 | $ | 1,420 |  |  | $ | 2,298,970 |  |  | $ | 1,797,896 |  |  | $ | (5,573) |  |  |  |  |  |  | $ | 4,092,713 |
Net Income | — |  |  | — |  |  | 202,103 |  |  | — |  |  |  |  |  |  | 202,103 |
Issuance of Common Stock | — |  |  | 56 |  |  | — |  |  | — |  |  |  |  |  |  | 56 |
Purchase and Retirement of Common Stock | (60) |  |  | (50,170) |  |  | (133,956) |  |  | — |  |  |  |  |  |  | (184,186) |
Shares Withheld for Taxes | — |  |  | — |  |  | (348) |  |  | — |  |  |  |  |  |  | (348) |
Amortization of Stock-Based Compensation Awards | — |  |  | 5,165 |  |  | — |  |  | — |  |  |  |  |  |  | 5,165 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 70 |  |  |  |  |  |  | 70 |
September 30, 2025 | $ | 1,360 |  |  | $ | 2,254,021 |  |  | $ | 1,865,695 |  |  | $ | (5,503) |  |  |  |  |  |  | $ | 4,115,573 |
(Dollars in thousands) (Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
June 30, 2024 | $ | 1,516 |  |  | $ | 2,363,053 |  |  | $ | 1,893,215 |  |  | $ | (7,139) |  |  |  |  |  |  | $ | 4,250,645 |
Net Income | — |  |  | — |  |  | 65,540 |  |  | — |  |  |  |  |  |  | 65,540 |
Issuance of Common Stock | 1 |  |  | 169 |  |  | — |  |  | — |  |  |  |  |  |  | 170 |
Purchase and Retirement of Common Stock | (23) |  |  | (19,353) |  |  | (44,234) |  |  | — |  |  |  |  |  |  | (63,610) |
Shares Withheld for Taxes | — |  |  | — |  |  | (303) |  |  | — |  |  |  |  |  |  | (303) |
Amortization of Stock-Based Compensation Awards | — |  |  | 4,192 |  |  | — |  |  | — |  |  |  |  |  |  | 4,192 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 81 |  |  |  |  |  |  | 81 |
September 30, 2024 | $ | 1,494 |  |  | $ | 2,348,061 |  |  | $ | 1,914,218 |  |  | $ | (7,058) |  |  |  |  |  |  | $ | 4,256,715 |

The accompanying notes are an integral part of these financial statements.
9

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands) | Common Stock |  | Capital in Excess of Par Value |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  |  |  |  |  | Total Equity
December 31, 2024 | $ | 1,490 |  |  | $ | 2,348,959 |  |  | $ | 1,753,293 |  |  | $ | (5,712) |  |  |  |  |  |  | $ | 4,098,030 |
(Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income | — |  |  | — |  |  | 436,910 |  |  | — |  |  |  |  |  |  | 436,910 |
Issuance of Common Stock | 1 |  |  | 985 |  |  | — |  |  | — |  |  |  |  |  |  | 986 |
Purchase and Retirement of Common Stock | (139) |  |  | (114,980) |  |  | (310,668) |  |  | — |  |  |  |  |  |  | (425,787) |
Shares Withheld for Taxes | — |  |  | — |  |  | (13,840) |  |  | — |  |  |  |  |  |  | (13,840) |
Amortization of Stock-Based Compensation Awards | 8 |  |  | 19,057 |  |  | — |  |  | — |  |  |  |  |  |  | 19,065 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 209 |  |  |  |  |  |  | 209 |
September 30, 2025 | $ | 1,360 |  |  | $ | 2,254,021 |  |  | $ | 1,865,695 |  |  | $ | (5,503) |  |  |  |  |  |  | $ | 4,115,573 |
(Dollars in thousands) |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2023 | $ | 1,548 |  |  | $ | 2,384,910 |  |  | $ | 1,981,860 |  |  | $ | (7,301) |  |  |  |  |  |  | $ | 4,361,017 |
(Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income | — |  |  | — |  |  | 54,130 |  |  | — |  |  |  |  |  |  | 54,130 |
Issuance of Common Stock | 2 |  |  | 1,206 |  |  | — |  |  | — |  |  |  |  |  |  | 1,208 |
Purchase and Retirement of Common Stock | (66) |  |  | (53,790) |  |  | (103,591) |  |  | — |  |  |  |  |  |  | (157,447) |
Shares Withheld for Taxes | — |  |  | — |  |  | (18,181) |  |  | — |  |  |  |  |  |  | (18,181) |
Amortization of Stock-Based Compensation Awards | 10 |  |  | 15,735 |  |  | — |  |  | — |  |  |  |  |  |  | 15,745 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 243 |  |  |  |  |  |  | 243 |
September 30, 2024 | $ | 1,494 |  |  | $ | 2,348,061 |  |  | $ | 1,914,218 |  |  | $ | (7,058) |  |  |  |  |  |  | $ | 4,256,715 |

The accompanying notes are an integral part of these financial statements.
10

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) | Nine Months Ended
Dollars in Thousands | September 30,
Cash Flows from Operating Activities: | 2025 |  | 2024
Net Income | $ | 436,910 |  |  | $ | 54,130 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: |  |  |
Depreciation, Depletion and Amortization | 428,979 |  |  | 357,418 |
Amortization of Deferred Financing Costs | 8,083 |  |  | 8,722 |
Stock-Based Compensation | 19,065 |  |  | 15,745 |
(Gain) Loss on Asset Sales and Abandonments, net | (94,759) |  |  | 8,912 |
Loss on Debt Extinguishment | — |  |  | 7,043 |
Gain on Commodity Derivative Instruments | (24,596) |  |  | (110,587) |
Loss on Other Derivative Instruments | — |  |  | 1,099 |
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments | (161,977) |  |  | 234,347 |
Deferred Income Taxes | 140,140 |  |  | 16,191 |
Other | 1,842 |  |  | 1,001 |
Changes in Operating Assets: |  |  |
Accounts and Notes Receivable | 49,036 |  |  | (16,010) |
Supplies Inventories | (16,250) |  |  | 6,881 |
Prepaid Expenses | (1,575) |  |  | (4,275) |
Changes in Other Assets | 22,883 |  |  | (46,337) |
Changes in Operating Liabilities: |  |  |
Accounts Payable | (17,974) |  |  | (4,648) |
Accrued Interest | (15,393) |  |  | (15,126) |
Other Operating Liabilities | (20,388) |  |  | (13,075) |
Changes in Other Liabilities | (22,118) |  |  | 45,551 |
Net Cash Provided by Operating Activities | 731,908 |  |  | 546,982 |
Cash Flows from Investing Activities: |  |  |
Capital Expenditures | (320,574) |  |  | (434,837) |
Proceeds from Asset Sales | 105,207 |  |  | 24,152 |
Investment in Equity Affiliates | (3,303) |  |  | (3,562) |
Apex Acquisition (Net of Cash Acquired) | (517,599) |  |  | — |
Net Cash Used in Investing Activities | (736,269) |  |  | (414,247) |
Cash Flows from Financing Activities: |  |  |
Payments on Long-Term Notes | — |  |  | (356,504) |
Proceeds from CNXM Revolving Credit Facility Borrowings | 252,925 |  |  | 193,550 |
Repayments of CNXM Revolving Credit Facility Borrowings | (248,475) |  |  | (272,050) |
Proceeds from CNX Revolving Credit Facility Borrowings | 1,574,600 |  |  | 939,700 |
Repayments of CNX Revolving Credit Facility Borrowings | (1,370,800) |  |  | (838,500) |
Proceeds from Issuance of CNX Senior Notes | 198,500 |  |  | 395,000 |
Payments on Other Debt | (3,089) |  |  | (1,722) |
Proceeds from Issuance of Common Stock | 986 |  |  | 1,208 |
Shares Withheld for Taxes | (13,840) |  |  | (18,181) |
Purchases of Common Stock | (423,226) |  |  | (159,197) |
Debt Issuance and Financing Fees | (960) |  |  | (15,172) |
Net Cash Used in Financing Activities | (33,379) |  |  | (131,868) |
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash | (37,740) |  |  | 867 |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 55,073 |  |  | 443 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 17,333 |  |  | $ | 1,310 |

The accompanying notes are an integral part of these financial statements.
11

CNX RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
NOTE 1—BASIS OF PRESENTATION:
The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles ("GAAP") for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2025 are not necessarily indicative of the results that may be expected for future periods.
The Consolidated Balance Sheet at December 31, 2024 has been derived from the Audited Consolidated Financial Statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 2024 included in CNX Resources Corporation's ("CNX," "CNX Resources," the "Company," "we," "us," or "our") Annual Report on Form 10-K as filed with the Securities and Exchange Commission ("SEC") on February 11, 2025 (the "2024 Form 10-K").
Certain amounts in prior periods have been reclassified to conform to the current period presentation.
Cash & Cash Equivalents
Cash and cash equivalents of $4,735 and $17,198 as of September 30, 2025 and December 31, 2024, respectively, include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Restricted Cash:
Current assets include restricted cash of $10,168 and $37,875 as of September 30, 2025 and December 31, 2024, respectively, consisting 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. See Note 4 – Acquisitions and Dispositions for more information.
Other non-current assets include restricted cash of $2,430 as of September 30, 2025, consisting 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 various rights-of-way, surface acreage and other oil and gas royalty interests from a third party. No such transactions occurred as of December 31, 2024. See Note 4 – Acquisitions and Dispositions for more information.
Receivables
As of September 30, 2025 and December 31, 2024, Accounts Receivable - Trade were $141,264 and $179,547, respectively, and Other Receivables were $56,596 and $17,859, respectively.
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.
12

The following represents activity related to the allowance for credit losses for the nine months ended:

| September 30,
| 2025 |  | 2024
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 Losses | (202) |  |  | 201 |
Allowance for Credit Losses - Other Receivables, End of Period | $ | 1,031 |  |  | $ | 1,356 |

NOTE 2—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 10 – 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 Three Months Ended September 30, |  | For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Anti-Dilutive Options | — |  |  | 11,058 |  |  | — |  |  | 6,134 |
Anti-Dilutive Restricted Stock Units | 244,338 |  |  | — |  |  | 273,398 |  |  | 36,018 |
| 244,338 |  |  | 11,058 |  |  | 273,398 |  |  | 42,152 |

The Convertible Notes, if converted by the holder, may be settled in cash, shares of the Company's common stock or a combination thereof, at the Company's election. The Company is currently evaluating the methods in which the convertible obligation will be settled upon conversion. 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 10 – 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.
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The table below sets forth the share-based awards that have been exercised or released:

| For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Options | 8,225 |  |  | 24,675 |  |  | 106,231 |  |  | 934,111 |
Restricted Stock Units | 25,155 |  |  | 47,188 |  |  | 756,238 |  |  | 893,400 |
Performance Share Units | 12,052 |  |  | — |  |  | 495,622 |  |  | 753,673 |
| 45,432 |  |  | 71,863 |  |  | 1,358,091 |  |  | 2,581,184 |

The computations for basic and diluted earnings per share are as follows:

| For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net Income | $ | 202,103 |  |  | $ | 65,540 |  |  | $ | 436,910 |  |  | $ | 54,130 |
Basic Earnings Available to Shareholders | $ | 202,103 |  |  | $ | 65,540 |  |  | $ | 436,910 |  |  | $ | 54,130 |
Effect of Dilutive Securities: |  |  |  |  |  |  |
Add Back Interest on Convertible Notes (Net of Tax) | $ | 1,405 |  |  | $ | 1,377 |  |  | $ | 4,214 |  |  | $ | 4,132 |
Diluted Earnings Available to Shareholders | $ | 203,508 |  |  | $ | 66,917 |  |  | $ | 441,124 |  |  | $ | 58,262 |
Weighted-Average Shares of Common Stock Outstanding | 139,251,482 |  |  | 150,342,177 |  |  | 143,455,291 |  |  | 152,098,676 |
Effect of Diluted Shares: |  |  |  |  |  |  |
Options | 549,148 |  |  | 748,078 |  |  | 568,262 |  |  | 888,717 |
Restricted Stock Units | 1,176,208 |  |  | 1,422,715 |  |  | 1,138,590 |  |  | 1,248,254 |
Performance Share Units | 856,491 |  |  | 848,622 |  |  | 850,788 |  |  | 782,130 |
Convertible Notes | 25,751,869 |  |  | 25,751,869 |  |  | 25,751,869 |  |  | 25,751,869 |
Weighted-Average Diluted Shares of Common Stock Outstanding | 167,585,198 |  |  | 179,113,461 |  |  | 171,764,800 |  |  | 180,769,646 |
Earnings per Share: |  |  |  |  |  |  |
Basic | $ | 1.45 |  |  | $ | 0.44 |  |  | $ | 3.05 |  |  | $ | 0.36 |
Diluted | $ | 1.21 |  |  | $ | 0.37 |  |  | $ | 2.57 |  |  | $ | 0.32 |

NOTE 3—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.
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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 Three Months Ended September 30, |  | For the Nine Months Ended September 30,
2025 |  | 2024 |  | 2025 |  | 2024
Revenue from Contracts with Customers: |  |  |  |  |  |  |
Natural Gas Revenue | $ | 361,300 |  |  | $ | 209,228 |  |  | $ | 1,300,056 |  |  | $ | 682,754 |
NGL Revenue | 36,663 |  |  | 46,173 |  |  | 130,483 |  |  | 131,789 |
Oil/Condensate Revenue | 3,027 |  |  | 4,058 |  |  | 6,574 |  |  | 7,121 |
Total Natural Gas, NGL and Oil Revenue | 400,990 |  |  | 259,459 |  |  | 1,437,113 |  |  | 821,664 |
Purchased Gas Revenue | 9,026 |  |  | 27,306 |  |  | 30,985 |  |  | 52,612 |
Other Sources of Revenue and Other Operating Income: |  |  |  |  |  |  |
Gain on Commodity Derivative Instruments | 131,695 |  |  | 88,964 |  |  | 24,596 |  |  | 110,587 |
Other Revenue and Operating Income | 42,129 |  |  | 48,484 |  |  | 135,956 |  |  | 145,345 |
Total Revenue and Other Operating Income | $ | 583,840 |  |  | $ | 424,213 |  |  | $ | 1,628,650 |  |  | $ | 1,130,208 |

The disaggregated revenue information corresponds with the Company’s segment reporting found in Note 14 – 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.
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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 $24,858 as of September 30, 2025. The Company expects to recognize net revenue of $19,003 in the next 12 months and $4,076 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 the three and nine months ended September 30, 2025 and 2024, revenue recognized in the current reporting period related to performance obligations satisfied in a prior reporting period was not material.
NOTE 4—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, and subject to certain post-closing adjustments. 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 fair value as of the acquisition date. 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 nine months ended September 30, 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 nine months ended September 30, 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) Loss on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
During the nine months ended September 30, 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) Loss on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
Additionally, (Gain) Loss on Asset Sales and Abandonments, net in the Consolidated Statements of Income for both the three and nine months ended September 30, 2025 and 2024 and Proceeds from Asset Sales in the Consolidated Statements of Cash Flows for the nine months ended September 30, 2025 and 2024 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.
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NOTE 5—INCOME TAXES:
The effective tax rates for the three and nine months ended September 30, 2025 were 23.9% and 24.5%, respectively. The effective tax rates for the three and nine months ended September 30, 2024 were 20.6% and 26.5%, respectively. The effective tax rate for the three and nine months ended September 30, 2025 and 2024 differs from the U.S. federal statutory rate of 21% primarily due to the impact of equity compensation, federal tax credits, and state taxes.
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 5-year amortization period for domestic research and development 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.
The total amount of uncertain tax positions at September 30, 2025 and December 31, 2024 was $129,109 and $113,227, respectively. If these uncertain tax positions were recognized, approximately $129,109 and $113,227 would affect CNX's effective tax rate at September 30, 2025 and December 31, 2024, respectively. In 2025, CNX recognized an increase in unrecognized tax benefits of $15,882 for tax benefits resulting from changes to tax positions from prior periods and tax positions anticipated to be claimed on our 2025 federal income tax return for additional federal tax credits.
CNX recognizes accrued interest and penalties related to uncertain tax positions in interest expense and income tax expense, respectively. As of September 30, 2025 and December 31, 2024, CNX had no accrued liabilities for interest and penalties related to uncertain tax positions.
CNX and its subsidiaries file federal income tax returns with the United States and tax returns within various states. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2021.
NOTE 6—PROPERTY, PLANT AND EQUIPMENT:

| September 30, 2025 |  | December 31, 2024
Intangible Drilling Cost | $ | 6,666,391 |  |  | $ | 6,171,177 |
Gas Gathering Equipment | 2,746,020 |  |  | 2,660,668 |
Gas Wells and Related Equipment | 1,791,199 |  |  | 1,657,272 |
Proved Gas Properties | 1,448,112 |  |  | 1,396,631 |
Unproved Gas Properties | 747,904 |  |  | 721,692 |
Surface Land and Other Equipment | 180,268 |  |  | 180,408 |
Other | 259,623 |  |  | 250,100 |
Total Property, Plant and Equipment | 13,839,517 |  |  | 13,037,948 |
Less: Accumulated Depreciation, Depletion and Amortization | 6,054,758 |  |  | 5,653,837 |
Total Property, Plant and Equipment - Net | $ | 7,784,759 |  |  | $ | 7,384,111 |

NOTE 7—GOODWILL AND OTHER INTANGIBLE ASSETS:
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.
The accumulated impairment loss on goodwill is $473,045, resulting in a carrying value of $323,314 at both September 30, 2025 and December 31, 2024.
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Other Intangible Assets:
The carrying amount and accumulated amortization of other intangible assets consist of the following:

| September 30, 2025 |  | December 31, 2024
Other Intangible Assets: |  |  |
Gross Amortizable Asset - Customer Relationships | $ | 109,752 |  |  | $ | 109,752 |
Less: Accumulated Amortization - Customer Relationships | 50,781 |  |  | 45,867 |
Total Other Intangible Assets, net | $ | 58,971 |  |  | $ | 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 for both the three and nine months ended September 30, 2025 and 2024 was $1,638 and $4,914, respectively. The estimated annual amortization expense is expected to approximate $6,552 per year for each of the next five years.
NOTE 8—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, per the terms in the paragraph below. On May 14, 2025, the CNX Credit Facility borrowing base increased from $2,250,000 to $2,400,000 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 September 30, 2025.
At September 30, 2025, the CNX Credit Facility had $247,250 of borrowings outstanding, with a weighted average interest rate of 6.44% and $26,939 of letters of credit outstanding, leaving $1,125,811 of unused capacity. At December 31, 2024, the 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.
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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 September 30, 2025.
At September 30, 2025, the CNXM Credit Facility had $20,500 of borrowings outstanding, with a weighted average interest rate of 6.06% and no letters of credit outstanding, leaving $579,500 of unused capacity. At December 31, 2024, the 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.
NOTE 9—OTHER ACCRUED LIABILITIES:

| September 30, 2025 |  | December 31, 2024
Royalties | $ | 104,785 |  |  | $ | 100,518 |
Accrued Interest | 30,420 |  |  | 45,812 |
Transportation Charges | 22,952 |  |  | 17,922 |
Current Portion Settlement - See Note 11 | 22,868 |  |  | 7,080 |
Short-Term Incentive Compensation | 8,993 |  |  | 22,580 |
Deferred Revenue | 8,769 |  |  | 20,696 |
Accrued Payroll & Benefits | 7,007 |  |  | 7,357 |
Accrued Other Taxes | 4,226 |  |  | 9,216 |
Purchased Gas Payable | 1,667 |  |  | 143 |
Other | 28,784 |  |  | 15,125 |
Current Portion of Long-Term Liabilities: |  |  |
Asset Retirement Obligations | 12,875 |  |  | 12,875 |
Salary Retirement | 1,967 |  |  | 1,908 |
Total Other Accrued Liabilities | $ | 255,313 |  |  | $ | 261,232 |

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NOTE 10—LONG-TERM DEBT:

| September 30, 2025 |  | December 31, 2024
Senior Notes due March 2032 at 7.25% (Principal of $600,000 and $400,000 less Unamortized Discount of $5,369 and $4,479, respectively) | $ | 594,631 |  |  | $ | 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 $3,989 and $4,554, respectively) | 496,011 |  |  | 495,446 |
CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $2,644 and $3,077, respectively)* | 397,356 |  |  | 396,923 |
Convertible Senior Notes due May 2026 at 2.25% (Principal of $330,654 less Unamortized Discount and Issuance Costs of $1,175 and $2,658, respectively) | 329,479 |  |  | 327,996 |
CNX Revolving Credit Facility | 247,250 |  |  | 43,450 |
CNX Midstream Partners LP Revolving Credit Facility* | 20,500 |  |  | 16,050 |
Less: Unamortized Debt Issuance Costs | 8,650 |  |  | 9,386 |
| 2,576,577 |  |  | 2,166,000 |
Less: Current Portion | 329,378 |  |  | 327,766 |
Long-Term Debt | $ | 2,247,199 |  |  | $ | 1,838,234 |

*CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or the CNXM Credit Facility.
During the nine months ended September 30, 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 8 – 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 nine months ended September 30, 2024, CNX issued $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 nine months ended September 30, 2024, CNX purchased and retired $350,000 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 nine months ended September 30, 2024.
In 2020, CNX issued $345,000 in aggregate principal amount of Convertible Notes due May 2026 ("the Convertible Notes") in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, including $45,000 aggregate principal amount of Convertible Notes issued pursuant to the exercise in full of the initial purchasers’ option to purchase additional Convertible Notes. The Convertible Notes are senior, unsecured obligations of the Company. The Convertible Notes bear interest at a fixed rate of 2.25% per annum, payable semi-annually in arrears on May 1 and November 1 of each year, commencing on November 1, 2020. Proceeds from the issuance of the Convertible Notes totaled $334,650, net of initial purchaser discounts and issuance costs. The Convertible Notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
The initial conversion rate is 77.8816 shares of CNX's common stock per $1,000 principal amount of Convertible Notes, which represents an initial conversion price of approximately $12.84 per share, subject to adjustment upon the occurrence of specified events.
The Convertible Notes will mature on May 1, 2026, unless earlier repurchased, redeemed or converted. Before February 1, 2026, noteholders will have the right to convert their Convertible Notes only upon the occurrence of the following events:
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•during any calendar quarter (and only during such calendar quarter) commencing after June 30, 2020, if the Last Reported Sale Price per share of Common Stock exceeds one hundred and thirty percent (130%) of the Conversion Price for each of at least twenty (20) Trading Days (whether or not consecutive) during the thirty (30) consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter;
•during the five (5) consecutive Business Days immediately after any ten (10) consecutive trading day period (such ten (10) consecutive Trading Day period, the "Measurement Period") if the trading Price per $1,000 principal amount of Notes, as determined following a request by a Holder in accordance with the procedures set forth in the indenture, for each trading day of the Measurement Period was less than ninety eight percent (98%) of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day;
•if CNX calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or
•upon the occurrence of certain specified corporate events as set forth in the indenture governing the Convertible Notes.
From and after February 1, 2026, noteholders may convert their Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date.
Upon conversion, the Company may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture governing the Convertible Notes. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the Convertible Notes, that occur prior to the maturity date, the Company will increase the conversion rate, in certain circumstances, for a holder who elects to convert its Convertible Notes in connection with such a corporate event.
The Company is currently evaluating the methods in which the convertible obligation will be settled upon conversion.
If certain corporate events that constitute a “Fundamental Change” (as defined in the indenture governing the Convertible Notes) occur, then noteholders may require the Company to repurchase their Convertible Notes at a cash repurchase price equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock.
Pursuant to the terms of the Convertible Notes indenture, the Sale Price per share of Common Stock condition for conversion of the Convertible Notes was satisfied as of September 30, 2025, and, accordingly, holders of Convertible Notes are permitted to convert any of their Convertible Notes, at their option, at any time during the quarter beginning on October 1, 2025 and ending on December 31, 2025, subject to all terms and conditions set forth in the Convertible Notes indenture.
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:

| September 30, 2025 |  | December 31, 2024
Liability Component: |  |  |
Principal | $ | 330,654 |  |  | $ | 330,654 |
Unamortized Issuance Costs | (1,175) |  |  | (2,658) |
Net Carrying Amount | $ | 329,479 |  |  | $ | 327,996 |
Fair Value | $ | 826,698 |  |  | $ | 953,613 |
Fair Value Hierarchy | Level 2 |  | Level 2

21

Interest expense related to the Convertible Notes is as follows:

| For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Contractual Interest Expense | $ | 1,860 |  |  | $ | 1,860 |  |  | $ | 5,580 |  |  | $ | 5,580 |
Amortization of Issuance Costs | 498 |  |  | 484 |  |  | 1,483 |  |  | 1,441 |
Total Interest Expense | $ | 2,358 |  |  | $ | 2,344 |  |  | $ | 7,063 |  |  | $ | 7,021 |

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.
NOTE 11—COMMITMENTS AND CONTINGENT LIABILITIES:
CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, royalty accounting, damage to property, climate change, governmental regulations including environmental violations and remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CNX; however, such amounts cannot be reasonably estimated.
The 1992 Coal Industry Retiree Health Benefit Act ("Coal Act"), in Section 9711, requires coal companies that were providing health benefits to United Mine Workers of America ("UMWA") retirees as of February 1993 to continue providing health benefits to such individuals, in substantially the same coverages, for as long as the last signatory operator remains in business. Section 9711 also requires any "related person" to be joint and severally liable for the provision of these health benefits. On May 1, 2020, the court in the Murray Energy Corporation ("Murray") bankruptcy proceedings approved a settlement agreement between Murray and the UMWA that transferred to the UMWA 1992 Benefit Plan the Coal Act liabilities for retirees in Murray’s Section 9711 plan. The retirees transferred by Murray to the 1992 Benefit Plan include approximately 2,159 retirees allegedly traced to the December 2013 sale by CONSOL Energy Inc. to Murray Energy of the following possible last signatory operators: Consolidation Coal Company, McElroy Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Keystone Coal Mining Corp., and Eighty-Four Mining Company (the "Sold Subsidiaries"). On May 2, 2020, the Trustees of the UMWA 1992 Benefit Plan sued CNX and CONSOL Energy Inc. ("CONSOL") in federal court contending that the Sold Subsidiaries were last signatory operators and that CNX and CONSOL are related persons to the Sold Subsidiaries and, as such, CNX and CONSOL are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The 1992 Benefit Plan seeks, among other relief, a declaration that CNX and CONSOL are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 plan; that CNX and CONSOL are liable to post the security required by Section 9712; and, that CNX and CONSOL are liable to pay per beneficiary premiums until the eligible retirees are enrolled in a Section 9711 plan, and other fees, costs and disbursements under the Coal Act. On March 29, 2022, the Court denied the Defendants’ Motions to Dismiss CNX and CONSOL 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, CONSOL agreed to indemnify CNX for all coal-related liabilities, including this lawsuit. With respect to this matter, although a loss is possible, it is not probable, and accordingly no accrual has been recognized.
22

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, CONSOL 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. CONSOL 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 CONSOL for defense and indemnity in July 2021, which it denied. CNX continued to demand indemnity from CONSOL including prior to, during and after the March 2024 mediation. After CONSOL repudiated its contractual obligations to CNX, and after having timely fulfilled all SDA prerequisites for bringing the action, on March 7, 2024, CNX sued CONSOL for breach of contract seeking an order requiring CONSOL 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 CONSOL 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 September 30, 2025 and December 31, 2024, CONSOL 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 September 30, 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 September 30, 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 September 30, 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 Years |  | 3-5 Years |  | Beyond 5 Years
Letters of Credit: |  |  |  |  |  |  |  |  |
Firm Transportation | $ | 24,005 |  |  | $ | 24,005 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other | 2,934 |  |  | 2,934 |  |  | — |  |  | — |  |  | — |
Total Letters of Credit | 26,939 |  |  | 26,939 |  |  | — |  |  | — |  |  | — |
Surety Bonds: |  |  |  |  |  |  |  |  |
Employee-Related | 2,250 |  |  | 1,500 |  |  | 750 |  |  | — |  |  | — |
Environmental | 40,264 |  |  | 40,149 |  |  | 115 |  |  | — |  |  | — |
Firm Transportation | 126,336 |  |  | 76,336 |  |  | 50,000 |  |  | — |  |  | — |
Financial Guarantees | 72,720 |  |  | 26,000 |  |  | 46,720 |  |  | — |  |  | — |
Other | 12,793 |  |  | 12,264 |  |  | 529 |  |  | — |  |  | — |
Total Surety Bonds | 254,363 |  |  | 156,249 |  |  | 98,114 |  |  | — |  |  | — |
Other Guarantees | 3,064 |  |  | 707 |  |  | 2,121 |  |  | 236 |  |  | — |
Total Commitments | $ | 284,366 |  |  | $ | 183,895 |  |  | $ | 100,235 |  |  | $ | 236 |  |  | $ | — |

Excluded from the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business in November 2017. Although CONSOL has agreed to indemnify CNX to the extent that CNX would be called upon to pay any of these liabilities, there is no assurance that CONSOL will satisfy its obligations to indemnify CNX in the event that CNX is so called upon (See Part II. Item 1A. Risk Factors of this Form 10-Q and in the 2024 Form 10-K for additional information).
23

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 September 30, 2025, the purchase obligations for each of the next five years and beyond are as follows:

Obligations Due | Amount
Less than 1 year | $ | 254,076 |
1 - 3 years | 487,109 |
3 - 5 years | 287,159 |
More than 5 years | 488,484 |
Total Purchase Obligations | $ | 1,516,828 |

NOTE 12—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 had 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:

| September 30, |  | December 31, |  | Forecasted to
| 2025 |  | 2024 |  | Settle Through
Natural Gas Commodity Swaps (Bcf) | 949.9 |  |  | 1,163.7 |  |  | 2028
Natural Gas Basis Swaps (Bcf) | 591.4 |  |  | 688.7 |  |  | 2028
NGL Commodity Swaps (Mbbls) | 364.0 |  | 351.0 |  | 2026

24

The gross fair value of CNX's derivative instruments was as follows:

| September 30, |  | December 31,
| 2025 |  | 2024
Current Assets: |  |  |
Commodity Derivative Instruments: |  |  |
Natural Gas Commodity Swaps | $ | 63,027 |  |  | $ | 45,336 |
NGL Commodity Swaps | 1,604 |  |  | 90 |
Natural Gas Basis Swaps | 35,445 |  |  | 42,499 |
Total Current Assets | $ | 100,076 |  |  | $ | 87,925 |
Other Non-Current Assets: |  |  |
Commodity Derivative Instruments: |  |  |
Natural Gas Commodity Swaps | $ | 85,663 |  |  | $ | 117,875 |
Natural Gas Basis Swaps | 32,724 |  |  | 42,308 |
Total Other Non-Current Assets | $ | 118,387 |  |  | $ | 160,183 |
Current Liabilities: |  |  |
Commodity Derivative Instruments: |  |  |
Natural Gas Commodity Swaps | $ | 264,746 |  |  | $ | 300,994 |
NGL Commodity Swaps | — |  |  | 839 |
Natural Gas Basis Swaps | 51,983 |  |  | 52,788 |
Total Current Liabilities | $ | 316,729 |  |  | $ | 354,621 |
Non-Current Liabilities: |  |  |
Commodity Derivative Instruments: |  |  |
Natural Gas Commodity Swaps | $ | 203,927 |  |  | $ | 364,662 |
Natural Gas Basis Swaps | 47,279 |  |  | 64,871 |
Total Non-Current Liabilities | $ | 251,206 |  |  | $ | 429,533 |

25

The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows:

|  | For the Three Months Ended |  | For the Nine Months Ended |
|  | September 30, |  | September 30, |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |
Realized Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |  |  |
Natural Gas Commodity Swaps |  | $ | 4,061 |  |  | $ | 85,312 |  |  | $ | (125,872) |  |  | $ | 258,096 |  |
Natural Gas Basis Swaps |  | 17,591 |  |  | 8,797 |  |  | 3,633 |  |  | 531 |  |
NGL Commodity Swaps |  | 728 |  |  | 554 |  |  | (473) |  |  | 770 |  |
Total Realized Gain (Loss) on Commodity Derivative Instruments |  | 22,380 |  |  | 94,663 |  |  | (122,712) |  | * | 259,397 |  | **
Unrealized Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |  |  |
Natural Gas Commodity Swaps |  | 234,645 |  |  | 69,688 |  |  | 154,522 |  |  | (30,679) |  |
Natural Gas Basis Swaps |  | (125,257) |  |  | (77,905) |  |  | (9,292) |  |  | (118,190) |  |
NGL Commodity Swaps |  | (73) |  |  | 2,518 |  |  | 2,078 |  |  | 59 |  |
Total Unrealized Gain (Loss) on Commodity Derivative Instruments |  | 109,315 |  |  | (5,699) |  |  | 147,308 |  |  | (148,810) |  |
Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |  |  |
Natural Gas Commodity Swaps |  | 238,706 |  |  | 155,000 |  |  | 28,650 |  |  | 227,417 |  |
Natural Gas Basis Swaps |  | (107,666) |  |  | (69,108) |  |  | (5,659) |  |  | (117,659) |  |
NGL Commodity Swaps |  | 655 |  |  | 3,072 |  |  | 1,605 |  |  | 829 |  |
Total Gain on Commodity Derivative Instruments |  | $ | 131,695 |  |  | $ | 88,964 |  |  | $ | 24,596 |  |  | $ | 110,587 |  |

*Includes $18,362 of commodity derivatives that have been settled but not received at September 30, 2025, and excludes $2,309 of commodity derivatives that were settled but not received and $23,212 that were settled but not paid at December 31, 2024.
**Includes $30,891 of commodity derivatives that have been settled but not received at September 30, 2024, and excludes $6,741 of commodity derivatives that were settled but not received and $900 that were settled but not paid at December 31, 2023.
The effect of interest rate swaps on Interest Expense in the Company's Consolidated Statements of Income was as follows:

|  | For the Three Months Ended |  | For the Nine Months Ended
|  | September 30, |  | September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Cash Received in Settlement of Interest Rate Swaps |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 1,103 |
Unrealized Loss on Interest Rate Swaps |  | — |  |  | — |  |  | — |  |  | (1,099) |
Gain on Interest Rate Swaps |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 4 |

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.
NOTE 13—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.
26

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 September 30, 2025 |  | Fair Value Measurements at December 31, 2024
Description | Level 1 |  | Level 2 |  | Level 3 |  | Level 1 |  | Level 2 |  | Level 3
Commodity Derivatives | $ | — |  |  | $ | (349,472) |  | * | $ | — |  |  | $ | — |  |  | $ | (536,046) |  | ** | $ | — |

*Includes $18,362 of commodity derivatives that have been settled but not received at September 30, 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:

| September 30, 2025 |  | December 31, 2024
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Cash and Cash Equivalents | $ | 4,735 |  |  | $ | 4,735 |  |  | $ | 17,198 |  |  | $ | 17,198 |
Restricted Cash* | $ | 12,598 |  |  | $ | 12,598 |  |  | $ | 37,875 |  |  | $ | 37,875 |
Long-Term Debt (Excluding Debt Issuance Costs) | $ | 2,585,227 |  |  | $ | 3,099,849 |  |  | $ | 2,175,386 |  |  | $ | 2,785,556 |

*The September 30, 2025 restricted cash balance includes $10,168 and $2,430 located in current assets and other non-current assets, respectively, in the Consolidated Balance Sheets. The December 31, 2024 restricted cash balance is 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.
NOTE 14—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. This structure is in compliance with ASC 280, Segment Reporting and ASU 2023-07 - Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which the Company adopted as of December 31, 2024.
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.
27

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 three months ended September 30, 2025 are:

|  |  | For the Three Months Ended September 30, 2025 |  |  |  |  |  |  |  |  |
|  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 367,315 |  |  | $ | 32,745 |  |  | $ | 930 |  |  | $ | 400,990 |  |  |  |  |  |  |  |  |  | (A)
Gain on Commodity Derivative Instruments |  |  | 21,014 |  |  | 1,358 |  |  | 109,323 |  |  | 131,695 |  |  |  |  |  |  |  |  |  |
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 9,026 |  |  | 9,026 |  |  |  |  |  |  |  |  |  |
Other Revenue and Operating Income |  |  | 17,415 |  |  | — |  |  | 24,714 |  |  | 42,129 |  |  |  |  |  |  |  |  |  | (B)
Total Revenue and Other Operating Income |  |  | $ | 405,744 |  |  | $ | 34,103 |  |  | $ | 143,993 |  |  | $ | 583,840 |  |  |  |  |  |  |  |  |  |
Lease Operating Expense |  |  | 20,972 |  |  | 6,298 |  |  | (143) |  |  | 27,127 |  |  |  |  |  |  |  |  |  |
Transportation, Gathering and Compression |  |  | 80,481 |  |  | 16,195 |  |  | 377 |  |  | 97,053 |  |  |  |  |  |  |  |  |  |
Production, Ad Valorem, and Other Fees |  |  | 6,180 |  |  | 1,477 |  |  | 68 |  |  | 7,725 |  |  |  |  |  |  |  |  |  |
Depreciation, Depletion and Amortization |  |  | 127,334 |  |  | 15,096 |  |  | 6,893 |  |  | 149,323 |  |  |  |  |  |  |  |  |  |
Interest Expense |  |  | — |  |  | — |  |  | 42,964 |  |  | 42,964 |  |  |  |  |  |  |  |  |  |
Other Segment Items |  |  | — |  |  | — |  |  | (6,044) |  |  | (6,044) |  |  |  |  |  |  |  |  |  |
Total Costs and Expenses |  |  | $ | 234,967 |  |  | $ | 39,066 |  |  | $ | 44,115 |  |  | $ | 318,148 |  |  |  |  |  |  |  |  |  |
Income (Loss) Before Income Tax |  |  | $ | 170,777 |  |  | $ | (4,963) |  |  | $ | 99,878 |  |  | $ | 265,692 |  |  |  |  |  |  |  |  |  |
(A) Included in Natural Gas, NGLs and Oil Revenue are sales of $49,542 to DTE Energy Trading, Inc., $47,915 to NRG Business Marketing LLC, and $43,010 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 $17,415 and equity in loss of unconsolidated affiliates of $1,297 for Shale and Other, respectively. Other also includes sales of environmental attributes of $17,949.

|  |  | For the Three Months Ended September 30, 2025 |  |  |  |  |  |  |  |  |
Other Segment Disclosures |  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Segment Assets |  |  | $ | 7,152,404 |  |  | $ | 915,031 |  |  | $ | 836,683 |  |  | $ | 8,904,118 |  |  |  |  |  |  |  |  |  | (C)
Capital Expenditures |  |  | $ | 67,428 |  |  | $ | 6,258 |  |  | $ | 1,858 |  |  | $ | 75,544 |  |  |  |  |  |  |  |  |  |
(C) Includes investments in unconsolidated equity affiliates of $17,881.

Reportable segment results for the three months ended September 30, 2024 are:

|  |  | For the Three Months Ended September 30, 2024 |  |  |  |  |  |  |  |  |
|  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 237,403 |  |  | $ | 21,854 |  |  | $ | 202 |  |  | $ | 259,459 |  |  |  |  |  |  |  |  |  | (D)
Gain (Loss) on Commodity Derivative Instruments |  |  | 87,502 |  |  | 7,121 |  |  | (5,659) |  |  | 88,964 |  |  |  |  |  |  |  |  |  |
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 27,306 |  |  | 27,306 |  |  |  |  |  |  |  |  |  |
Other Revenue and Operating Income |  |  | 18,040 |  |  | — |  |  | 30,444 |  |  | 48,484 |  |  |  |  |  |  |  |  |  | (E)
Total Revenue and Other Operating Income |  |  | $ | 342,945 |  |  | $ | 28,975 |  |  | $ | 52,293 |  |  | $ | 424,213 |  |  |  |  |  |  |  |  |  |
Lease Operating Expense |  |  | 11,755 |  |  | 5,456 |  |  | 42 |  |  | 17,253 |  |  |  |  |  |  |  |  |  |
Transportation, Gathering and Compression |  |  | 79,599 |  |  | 16,343 |  |  | 332 |  |  | 96,274 |  |  |  |  |  |  |  |  |  |
Production, Ad Valorem, and Other Fees |  |  | 5,355 |  |  | 1,278 |  |  | 13 |  |  | 6,646 |  |  |  |  |  |  |  |  |  |
Depreciation, Depletion and Amortization |  |  | 101,135 |  |  | 15,024 |  |  | 5,068 |  |  | 121,227 |  |  |  |  |  |  |  |  |  |
Interest Expense |  |  | — |  |  |  |  | 37,923 |  |  | 37,923 |  |  |  |  |  |  |  |  |  |
Other Segment Items |  |  | — |  |  | — |  |  | 62,329 |  |  | 62,329 |  |  |  |  |  |  |  |  |  |
Total Costs and Expenses |  |  | $ | 197,844 |  |  | $ | 38,101 |  |  | $ | 105,707 |  |  | $ | 341,652 |  |  |  |  |  |  |  |  |  |
Income (Loss) Before Income Tax |  |  | $ | 145,101 |  |  | $ | (9,126) |  |  | $ | (53,414) |  |  | $ | 82,561 |  |  |  |  |  |  |  |  |  |
(D) Included in Natural Gas, NGLs and Oil Revenue are sales of $30,665 to Citadel Energy Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(E) Includes midstream revenue of $18,040 and equity in loss of unconsolidated affiliates of $529 for Shale and Other, respectively. Other also includes sales of environmental attributes of $24,898.

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|  |  | For the Three Months Ended September 30, 2024 |  |  |  |  |  |  |  |  |
Other Segment Disclosures |  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Segment Assets |  |  | $ | 6,663,892 |  |  | $ | 932,410 |  |  | $ | 941,747 |  |  | $ | 8,538,049 |  |  |  |  |  |  |  |  |  | (F)
Capital Expenditures |  |  | $ | 105,133 |  |  | $ | 7,389 |  |  | $ | 2,215 |  |  | $ | 114,737 |  |  |  |  |  |  |  |  |  |
(F) Includes investments in unconsolidated equity affiliates of $18,369.

Reportable segment results for the nine months ended September 30, 2025 are:

|  |  | For the Nine Months Ended September 30, 2025 |  |  |  |  |  |  |  |  |
|  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 1,326,488 |  |  | $ | 109,203 |  |  | $ | 1,422 |  |  | $ | 1,437,113 |  |  |  |  |  |  |  |  |  | (G)
(Loss) Gain on Commodity Derivative Instruments |  |  | (114,942) |  |  | (7,728) |  |  | 147,266 |  |  | 24,596 |  |  |  |  |  |  |  |  |  |
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 30,985 |  |  | 30,985 |  |  |  |  |  |  |  |  |  |
Other Revenue and Operating Income |  |  | 51,685 |  |  | — |  |  | 84,271 |  |  | 135,956 |  |  |  |  |  |  |  |  |  | (H)
Total Revenue and Other Operating Income |  |  | $ | 1,263,231 |  |  | $ | 101,475 |  |  | $ | 263,944 |  |  | $ | 1,628,650 |  |  |  |  |  |  |  |  |  |
Lease Operating Expense |  |  | 58,405 |  |  | 18,283 |  |  | 27 |  |  | 76,715 |  |  |  |  |  |  |  |  |  |
Transportation, Gathering and Compression |  |  | 238,580 |  |  | 49,305 |  |  | 1,280 |  |  | 289,165 |  |  |  |  |  |  |  |  |  |
Production, Ad Valorem, and Other Fees |  |  | 19,889 |  |  | 4,695 |  |  | 82 |  |  | 24,666 |  |  |  |  |  |  |  |  |  |
Depreciation, Depletion and Amortization |  |  | 364,962 |  |  | 43,714 |  |  | 20,303 |  |  | 428,979 |  |  |  |  |  |  |  |  |  |
Interest Expense |  |  | — |  |  | — |  |  | 128,616 |  |  | 128,616 |  |  |  |  |  |  |  |  |  |
Other Segment Items |  |  | — |  |  | — |  |  | 101,974 |  |  | 101,974 |  |  |  |  |  |  |  |  |  |
Total Costs and Expenses |  |  | $ | 681,836 |  |  | $ | 115,997 |  |  | $ | 252,282 |  |  | $ | 1,050,115 |  |  |  |  |  |  |  |  |  |
Income (Loss) Before Income Tax |  |  | $ | 581,395 |  |  | $ | (14,522) |  |  | $ | 11,662 |  |  | $ | 578,535 |  |  |  |  |  |  |  |  |  |
(G) Included in Natural Gas, NGLs and Oil Revenue are sales of $167,758 to Citadel Energy Marketing LLC, $154,654 to DTE Energy Trading, Inc., and $151,213 to NGR Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(H) Includes midstream revenue of $51,685 and equity in loss of unconsolidated affiliates of $749 for Shale and Other, respectively. Other also includes sales of environmental attributes of $61,234.

|  |  | For the Nine Months Ended September 30, 2025 |  |  |  |  |  |  |  |  |
Other Segment Disclosures |  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Segment Assets |  |  | $ | 7,152,404 |  |  | $ | 915,031 |  |  | $ | 836,683 |  |  | $ | 8,904,118 |  |  |  |  |  |  |  |  |  | (I)
Capital Expenditures |  |  | $ | 280,663 |  |  | $ | 35,506 |  |  | $ | 4,405 |  |  | $ | 320,574 |  |  |  |  |  |  |  |  |  |
(I) Includes investments in unconsolidated equity affiliates of $17,881.

Reportable segment results for the nine months ended September 30, 2024 are:

|  |  | For the Nine Months Ended September 30, 2024 |  |  |  |  |  |  |  |  |
|  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 745,763 |  |  | $ | 75,202 |  |  | $ | 699 |  |  | $ | 821,664 |  |  |  |  |  |  |  |  |  | (J)
Gain (Loss) on Commodity Derivative Instruments |  |  | 240,200 |  |  | 19,082 |  |  | (148,695) |  |  | 110,587 |  |  |  |  |  |  |  |  |  |
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 52,612 |  |  | 52,612 |  |  |  |  |  |  |  |  |  |
Other Revenue and Operating Income |  |  | 50,375 |  |  | — |  |  | 94,970 |  |  | 145,345 |  |  |  |  |  |  |  |  |  | (K)
Total Revenue and Other Operating Income (Loss) |  |  | $ | 1,036,338 |  |  | $ | 94,284 |  |  | $ | (414) |  |  | $ | 1,130,208 |  |  |  |  |  |  |  |  |  |
Lease Operating Expense |  |  | 36,233 |  |  | 16,194 |  |  | 371 |  |  | 52,798 |  |  |  |  |  |  |  |  |  |
Transportation, Gathering and Compression |  |  | 235,611 |  |  | 48,004 |  |  | 1,018 |  |  | 284,633 |  |  |  |  |  |  |  |  |  |
Production, Ad Valorem, and Other Fees |  |  | 16,700 |  |  | 4,165 |  |  | 44 |  |  | 20,909 |  |  |  |  |  |  |  |  |  |
Depreciation, Depletion and Amortization |  |  | 298,521 |  |  | 43,885 |  |  | 15,012 |  |  | 357,418 |  |  |  |  |  |  |  |  |  |
Interest Expense |  |  | — |  |  | — |  |  | 113,997 |  |  | 113,997 |  |  |  |  |  |  |  |  |  |
Other Segment Items |  |  | — |  |  | — |  |  | 226,816 |  |  | 226,816 |  |  |  |  |  |  |  |  |  |
Total Costs and Expenses |  |  | $ | 587,065 |  |  | $ | 112,248 |  |  | $ | 357,258 |  |  | $ | 1,056,571 |  |  |  |  |  |  |  |  |  |
Income (Loss) Before Income Tax |  |  | $ | 449,273 |  |  | $ | (17,964) |  |  | $ | (357,672) |  |  | $ | 73,637 |  |  |  |  |  |  |  |  |  |
(J) Included in Natural Gas, NGLs and Oil Revenue are sales of $95,194 to NRG Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(K) Includes midstream revenue of $50,375 and equity in loss of unconsolidated affiliates of $1,006 for Shale and Other, respectively. Other also includes sales of environmental attributes of $70,544.

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|  |  | For the Nine Months Ended September 30, 2024 |  |  |  |  |  |  |  |  |
Other Segment Disclosures |  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Segment Assets |  |  | $ | 6,663,892 |  |  | $ | 932,410 |  |  | $ | 941,747 |  |  | $ | 8,538,049 |  |  |  |  |  |  |  |  |  | (L)
Capital Expenditures |  |  | $ | 396,924 |  |  | $ | 23,817 |  |  | $ | 14,096 |  |  | $ | 434,837 |  |  |  |  |  |  |  |  |  |
(L) Includes investments in unconsolidated equity affiliates of $18,369.

Reconciliation of Segment Information to Consolidated Amounts:
R evenue and Other Operating Income:

| For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
2025 |  | 2024 |  | 2025 |  | 2024
Total Segment Revenue from Contracts with External Customers | $ | 427,431 |  |  | $ | 304,805 |  |  | $ | 1,519,783 |  |  | $ | 924,651 |
Gain on Commodity Derivative Instruments | 131,695 |  |  | 88,964 |  |  | 24,596 |  |  | 110,587 |
Other Operating Income | 24,714 |  |  | 30,444 |  |  | 84,271 |  |  | 94,970 |
Total Consolidated Revenue and Other Operating Income | $ | 583,840 |  |  | $ | 424,213 |  |  | $ | 1,628,650 |  |  | $ | 1,130,208 |

NOTE 15—STOCK REPURCHASE:
During 2017, the Company announced a program permitting CNX to repurchase a portion of its outstanding shares not to exceed a dollar maximum established by the Company's Board of Directors. As of September 30, 2025, the amount available under the current Board-approved $2,900,000 stock repurchase program is $529,319 and it is not subject to an expiration date. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Company's 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 nine months ended September 30, 2025, 13,896,637 shares were repurchased and retired at an average price of $30.34 per share for a total cost of $425,787. During the nine months ended September 30, 2024, 6,575,610 shares were repurchased and retired at an average price of $23.74 per share for a total cost of $157,447. The one-percent excise tax under the Inflation Reduction Act of 2022 is included in total costs for both periods.
NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CNX.
As of September 30, 2025 and December 31, 2024, CNX purchased goods and services related to capital projects in the amount of $20,010 and $30,905, respectively, which are included in accounts payable.
The following table shows cash paid:

| For the Nine Months Ended September 30,
| 2025 |  | 2024
Interest | $ | 135,812 |  |  | $ | 119,189 |
Income Taxes | $ | 4,850 |  |  | $ | 5,554 |

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 September 30, 2025, the amount in escrow was classified as Restricted Cash on the Company’s Consolidated Balance Sheets.
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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.
NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:
In November 2024, the FASB issued Accounting Standards Update (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 10 – 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.
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. This ASU addresses more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. This ASU also includes certain other amendments to improve the effectiveness of income tax disclosures. The amendments in this ASU are effective for public business entities for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. The Company does not expect adoption of this ASU to have a material impact on its financial statements other than certain of our income tax disclosures.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this Form 10-Q. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward-looking statements that are based on the current views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see "Part I. Item 1A. Risk Factors" and the section entitled "Forward-Looking Statements" contained in our Annual Report on Form 10-K for the year ended December 31, 2024, which we filed with the SEC on February 11, 2025 (the “2024 Form 10-K”). CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
General
CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations. Examples include global events such as the current uncertainties in global financial markets, geopolitical tensions and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, all of which have had an impact on global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
Natural Gas, NGL, and Oil Pricing
Prices for natural gas, NGLs and oil that CNX produces significantly impact revenue and cash flows. In the current economic environment, CNX expects that commodity prices for some or all of the commodities we produce will remain volatile. In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length as well as financial hedges. However, this market volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Inflation
The inflationary environment over the last few years, primarily related to steel, diesel fuel and labor, continues to present risk for CNX and the broader natural gas industry. If inflation were to increase materially for any extended period of time, and CNX is unable to successfully mitigate the impact, our costs could increase further, thus having a greater impact on our financial position. CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset any additional potential cost increases from inflation.
Hedging Update
Total hedged natural gas production for the fourth quarter of 2025 is 121.9 Bcf. CNX's annual gas hedge position is shown in the table below:

|  | 2025 |  | 2026
Volumes Hedged (Bcf), as of 10/8/25 |  | 484.0(1) |  | 441.3 |

1 Includes actual settlements of 286.7 Bcf.
CNX's hedged gas volumes include a combination of NYMEX financial hedges, index (NYMEX and basis) financial hedges, and physical fixed price sales. In addition, to protect the NYMEX hedge volumes from basis exposure, CNX enters into basis-only financial hedges and physical sales with fixed basis at certain sales points. CNX has also entered into a nominal quantity of NGL hedges. See Quantitative and Qualitative Disclosures About Market Risk in Item 3 of this Form 10-Q for additional information.
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Other Updates
During the nine months ended September 30, 2025, CNX completed the acquisition of Apex Energy II, LLC, ("the Apex Transaction") (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). 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.
On September 30, 2025, CNX entered into an agreement to acquire Utica Shale oil and gas rights, across approximately 23,000 nearly contiguous acres, that sit beneath the Apex Energy footprint. The cost of the acquisition will be approximately $50 million to be paid equally over a three-year period starting in January 2026. This transaction provides the critical strategic benefits CNX envisioned when acquiring Apex due to our ability to leverage the Apex infrastructure already in place to efficiently develop that leasehold.
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 5-year amortization period for domestic research and development 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.
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Results of Operations - Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Net Income
CNX reported net income of $202 million, or earnings per diluted share of $1.21, for the three months ended September 30, 2025, compared to net income of $66 million, or earnings per diluted share of $0.37, for the three months ended September 30, 2024.
Included in earnings for the three months ended September 30, 2025 was an unrealized gain on commodity derivative instruments of $110 million and a net gain on asset sales and abandonments of $68 million. Included in the earnings for the three months ended September 30, 2024 was an unrealized loss on commodity derivative instruments of $6 million and a net gain on asset sales and abandonments of $11 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the gain on asset sales and abandonments.
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations. These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Non-GAAP Financial Measures Reconciliation

| For the Three Months Ended September 30,
(Dollars in millions) | 2025 | 2024
Total Revenue and Other Operating Income | $ | 584 |  |  | $ | 424 |
(Deduct) Add: |  |  |
Purchased Gas Revenue | (9) |  |  | (27) |
Unrealized (Gain) Loss on Commodity Derivative Instruments | (110) |  |  | 6 |
Other Revenue and Operating Income | (42) |  |  | (49) |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | $ | 423 |  |  | $ | 354 |
Total Operating Expense | $ | 341 |  |  | $ | 319 |
Deduct: |  |  |
Depreciation, Depletion and Amortization (DD&A) - Corporate | (5) |  |  | (4) |
Exploration and Production Related Other Costs | (2) |  |  | (2) |
Purchased Gas Costs | (9) |  |  | (27) |
Selling, General and Administrative Costs | (30) |  |  | (33) |
Other Operating Expense | (19) |  |  | (16) |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1 | $ | 276 |  |  | $ | 237 |

1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
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Selected Natural Gas, NGL and Oil Production Financial Data
The following table presents a summary of our total sales volumes, sales of natural gas, NGL and oil including cash settlements, natural gas, NGL and oil production costs and natural gas, NGL and oil production margin related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation above for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP):

| For the Three Months Ended September 30,
| 2025 |  | 2024 |  | Variance
| in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe
Total Sales Volumes (Bcfe)* |  |  | 161.3 |  |  |  | 134.5 |  |  |  | 26.8 |
Natural Gas, NGL and Oil Revenue | $ | 401 |  |  | $ | 2.47 |  |  | $ | 259 |  |  | $ | 1.85 |  |  | $ | 142 |  |  | $ | 0.62 |
Gain on Commodity Derivative Instruments - Cash Settlement | 22 |  |  | 0.15 |  |  | 95 |  |  | 0.78 |  |  | (73) |  |  | (0.63) |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | 423 |  |  | 2.62 |  |  | 354 |  |  | 2.63 |  |  | 69 |  |  | (0.01) |
Lease Operating Expense | 27 |  |  | 0.17 |  |  | 17 |  |  | 0.13 |  |  | 10 |  |  | 0.04 |
Production, Ad Valorem, and Other Fees | 8 |  |  | 0.05 |  |  | 7 |  |  | 0.05 |  |  | 1 |  |  | — |
Transportation, Gathering and Compression | 97 |  |  | 0.60 |  |  | 96 |  |  | 0.72 |  |  | 1 |  |  | (0.12) |
Depreciation, Depletion and Amortization (DD&A) | 144 |  |  | 0.89 |  |  | 117 |  |  | 0.86 |  |  | 27 |  |  | 0.03 |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure | 276 |  |  | 1.71 |  |  | 237 |  |  | 1.76 |  |  | 39 |  |  | (0.05) |
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure | $ | 147 |  |  | $ | 0.91 |  |  | $ | 117 |  |  | $ | 0.87 |  |  | $ | 30 |  |  | $ | 0.04 |

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
The 26.8 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Changes in the average costs per Mcfe were primarily related to the following items:
•Lease operating expense increased on a per unit basis primarily due to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense. The increases were offset, in part, by the overall increase in total sales volumes.
•Transportation, gathering and compression expense decreased on a per unit basis primarily due to the overall increase in total sales volumes and a decrease in processing costs due to production mix. The per unit decrease was offset, in part, by higher repairs and maintenance expense.
•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate. The increase was offset, in part, by the overall increase in total sales volumes.
35

Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:

|  | For the Three Months Ended September 30,
in thousands (unless noted) |  | 2025 |  | 2024 |  | Variance |  | Percent Change
LIQUIDS |  |  |  |  |  |  |  |
NGL: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 12,042 |  |  | 13,196 |  |  | (1,154) |  |  | (8.7) | %
Sales Volume (Mbbls) |  | 2,007 |  |  | 2,199 |  |  | (192) |  |  | (8.7) | %
Gross Price ($/Bbl) |  | $ | 18.24 |  |  | $ | 21.00 |  |  | $ | (2.76) |  |  | (13.1) | %
Gross NGL Revenue |  | $ | 36,663 |  |  | $ | 46,173 |  |  | $ | (9,510) |  |  | (20.6) | %
Oil/Condensate: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 319 |  |  | 394 |  |  | (75) |  |  | (19.0) | %
Sales Volume (Mbbls) |  | 53 |  |  | 66 |  |  | (13) |  |  | (19.7) | %
Gross Price ($/Bbl) |  | $ | 56.94 |  |  | $ | 61.86 |  |  | $ | (4.92) |  |  | (8.0) | %
Gross Oil/Condensate Revenue |  | $ | 3,027 |  |  | $ | 4,058 |  |  | $ | (1,031) |  |  | (25.4) | %
NATURAL GAS |  |  |  |  |  |  |  |
Sales Volume (MMcf) |  | 148,940 |  |  | 120,900 |  |  | 28,040 |  |  | 23.2 | %
Sales Price ($/Mcf) |  | $ | 2.43 |  |  | $ | 1.73 |  |  | $ | 0.70 |  |  | 40.5 | %
Gross Natural Gas Revenue |  | $ | 361,300 |  |  | $ | 209,228 |  |  | $ | 152,072 |  |  | 72.7 | %
Hedging Impact ($/Mcf) |  | $ | 0.15 |  |  | $ | 0.78 |  |  | $ | (0.63) |  |  | (80.8) | %
Gain on Commodity Derivative Instruments - Cash Settlement |  | $ | 22,379 |  |  | $ | 94,663 |  |  | $ | (72,284) |  |  | (76.4) | %

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 26.8 Bcfe increase in total sales volumes and the $0.70 per Mcf increase in natural gas sales price, when excluding the impact of hedging. The increases were offset, in part, by the impact of the change in the gain on commodity derivative instruments - cash settlement related to the Company's hedging program and the $2.76 per Bbl decrease in NGL prices.
36

SEGMENT ANALYSIS for the three months ended September 30, 2025 compared to the three months ended September 30, 2024:

| For the Three Months Ended |  | Difference to Three Months Ended
| September 30, 2025 |  | September 30, 2024
(in millions) | Shale |  | CBM |  | Other |  | Total |  | Shale |  | CBM |  | Other |  | Total
Natural Gas, NGLs and Oil Revenue | $ | 367 |  |  | $ | 33 |  |  | $ | 1 |  |  | $ | 401 |  |  | $ | 130 |  |  | $ | 11 |  |  | $ | 1 |  |  | $ | 142 |
Gain on Commodity Derivative Instruments | 21 |  |  | 1 |  |  | 110 |  |  | 132 |  |  | (67) |  |  | (6) |  |  | 116 |  |  | 43 |
Purchased Gas Revenue | — |  |  | — |  |  | 9 |  |  | 9 |  |  | — |  |  | — |  |  | (18) |  |  | (18) |
Other Revenue and Operating Income | 18 |  |  | — |  |  | 24 |  |  | 42 |  |  | — |  |  | — |  |  | (7) |  |  | (7) |
Total Revenue and Other Operating Income | 406 |  |  | 34 |  |  | 144 |  |  | 584 |  |  | 63 |  |  | 5 |  |  | 92 |  |  | 160 |
Lease Operating Expense | 21 |  |  | 6 |  |  | — |  |  | 27 |  |  | 9 |  |  | 1 |  |  | — |  |  | 10 |
Production, Ad Valorem, and Other Fees | 6 |  |  | 2 |  |  | — |  |  | 8 |  |  | 1 |  |  | — |  |  | — |  |  | 1 |
Transportation, Gathering and Compression | 81 |  |  | 16 |  |  | — |  |  | 97 |  |  | 1 |  |  | — |  |  | — |  |  | 1 |
Depreciation, Depletion and Amortization | 127 |  |  | 15 |  |  | 7 |  |  | 149 |  |  | 26 |  |  | — |  |  | 2 |  |  | 28 |
Exploration and Production Related Other Costs | — |  |  | — |  |  | 2 |  |  | 2 |  |  | — |  |  | — |  |  | — |  |  | — |
Purchased Gas Costs | — |  |  | — |  |  | 9 |  |  | 9 |  |  | — |  |  | — |  |  | (18) |  |  | (18) |
Selling, General and Administrative Costs | — |  |  | — |  |  | 30 |  |  | 30 |  |  | — |  |  | — |  |  | (3) |  |  | (3) |
Other Operating Expense | — |  |  | — |  |  | 19 |  |  | 19 |  |  | — |  |  | — |  |  | 3 |  |  | 3 |
Total Operating Expense | 235 |  |  | 39 |  |  | 67 |  |  | 341 |  |  | 37 |  |  | 1 |  |  | (16) |  |  | 22 |
Other Expense | — |  |  | — |  |  | 2 |  |  | 2 |  |  | — |  |  | — |  |  | 7 |  |  | 7 |
Gain on Asset Sales and Abandonments, net | — |  |  | — |  |  | (68) |  |  | (68) |  |  | — |  |  | — |  |  | (57) |  |  | (57) |
Interest Expense | — |  |  | — |  |  | 43 |  |  | 43 |  |  | — |  |  | — |  |  | 5 |  |  | 5 |
Total Other Expense | — |  |  | — |  |  | (23) |  |  | (23) |  |  | — |  |  | — |  |  | (45) |  |  | (45) |
Total Costs and Expenses | 235 |  |  | 39 |  |  | 44 |  |  | 318 |  |  | 37 |  |  | 1 |  |  | (61) |  |  | (23) |
Earnings (Loss) Before Income Tax | $ | 171 |  |  | $ | (5) |  |  | $ | 100 |  |  | $ | 266 |  |  | $ | 26 |  |  | $ | 4 |  |  | $ | 153 |  |  | $ | 183 |

37

SHALE SEGMENT
The Shale segment had earnings before income tax of $171 million for the three months ended September 30, 2025 compared to earnings before income tax of $145 million for the three months ended September 30, 2024.

| For the Three Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
Shale Gas Sales Volumes (Bcf) | 139.2 |  |  | 110.8 |  |  | 28.4 |  |  | 25.6 | %
NGLs Sales Volumes (Bcfe)* | 12.0 |  |  | 13.2 |  |  | (1.2) |  |  | (9.1) | %
Oil/Condensate Sales Volumes (Bcfe)* | 0.3 |  |  | 0.4 |  |  | (0.1) |  |  | (25.0) | %
Total Shale Sales Volumes (Bcfe)* | 151.5 |  |  | 124.4 |  |  | 27.1 |  |  | 21.8 | %
Average Sales Price - Natural Gas (per Mcf) | $ | 2.36 |  |  | $ | 1.69 |  |  | $ | 0.67 |  |  | 39.6 | %
Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | 0.15 |  |  | $ | 0.79 |  |  | $ | (0.64) |  |  | (81.0) | %
Average Sales Price - NGLs (per Mcfe)* | $ | 3.04 |  |  | $ | 3.50 |  |  | $ | (0.46) |  |  | (13.1) | %
Average Sales Price - Oil/Condensate (per Mcfe)* | $ | 9.01 |  |  | $ | 10.30 |  |  | $ | (1.29) |  |  | (12.5) | %
Total Average Shale Sales Price (per Mcfe) | $ | 2.56 |  |  | $ | 2.61 |  |  | $ | (0.05) |  |  | (1.9) | %
Average Shale Lease Operating Expenses (per Mcfe) | 0.14 |  |  | 0.09 |  |  | 0.05 |  |  | 55.6 | %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) | 0.04 |  |  | 0.04 |  |  | — |  |  | — | %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe) | 0.53 |  |  | 0.64 |  |  | (0.11) |  |  | (17.2) | %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.84 |  |  | 0.82 |  |  | 0.02 |  |  | 2.4 | %
Total Average Shale Production Costs (per Mcfe) | $ | 1.55 |  |  | $ | 1.59 |  |  | $ | (0.04) |  |  | (2.5) | %
Total Average Shale Production Margin (per Mcfe) | $ | 1.01 |  |  | $ | 1.02 |  |  | $ | (0.01) |  |  | (1.0) | %

* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGL, condensate, and natural gas prices.
The increase in total Shale sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $367 million for the three months ended September 30, 2025 compared to $237 million for the three months ended September 30, 2024. The $130 million increase was primarily due to a 39.6% increase in the average sales price for natural gas and a 21.8% increase in total Shale sales volumes. The increase was offset, in part, by the 81.0% change in the gain on commodity derivative instruments and a 13.1% decrease in the average sales price of NGLs.
The decrease in total average Shale sales price was primarily due to a $0.46 per Mcfe decrease in the average NGL sales price and a $0.64 per Mcf change in the gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 115.7 Bcf of the Company's produced Shale gas sales volumes for the three months ended September 30, 2025 at an average gain of $0.18 per Mcf hedged. For the three months ended September 30, 2024, these financial hedges represented approximately 96.0 Bcf at an average gain of $0.91 per Mcf hedged. These decreases were offset, in part, by a $0.67 per Mcf increase in average natural gas sales price.
Total operating costs and expenses for the Shale segment were $235 million for the three months ended September 30, 2025 compared to $198 million for the three months ended September 30, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:
•Shale lease operating expenses were $21 million for the three months ended September 30, 2025 compared to $12 million for the three months ended September 30, 2024. The increase in total dollars and unit costs was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense. The increase in unit costs was offset, in part, by the overall increase in volumes.
38

•Shale production, ad valorem and other fees were $6 million for the three months ended September 30, 2025 compared to $5 million for the three months ended September 30, 2024. The increase in total dollars was primarily due to increased realized prices on natural gas. Unit costs remained flat in the period-to-period comparison due to the overall increase in volumes.
•Shale transportation, gathering and compression costs were $81 million for the three months ended September 30, 2025 compared to $80 million for the three months ended September 30, 2024. The increase in total dollars was primarily due to higher repairs and maintenance expense and electrical compression expense offset, in part, by lower processing costs due to production mix. The decrease in unit costs was primarily due to the overall increase in volumes.
•Depreciation, depletion and amortization costs attributable to the Shale segment were $127 million for the three months ended September 30, 2025 compared to $101 million for the three months ended September 30, 2024. These amounts included depletion on a units of production basis of $0.74 per Mcfe and $0.70 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering services provided to third parties. The Shale segment had other revenue and operating income of $18 million for both the three months ended September 30, 2025 and 2024.
COALBED METHANE (CBM) SEGMENT
The CBM segment had a loss before income tax of $5 million for the three months ended September 30, 2025 compared to a loss before income tax of $9 million for the three months ended September 30, 2024.

| For the Three Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 9.7 |  |  | 10.0 |  |  | (0.3) |  |  | (3.0) | %
Average Sales Price - Gas (per Mcf) | $ | 3.39 |  |  | $ | 2.19 |  |  | $ | 1.20 |  |  | 54.8 | %
Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | 0.14 |  |  | $ | 0.71 |  |  | $ | (0.57) |  |  | (80.3) | %
Total Average CBM Sales Price (per Mcf) | $ | 3.53 |  |  | $ | 2.90 |  |  | $ | 0.63 |  |  | 21.7 | %
Average CBM Lease Operating Expenses (per Mcf) | 0.65 |  |  | 0.55 |  |  | 0.10 |  |  | 18.2 | %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) | 0.16 |  |  | 0.12 |  |  | 0.04 |  |  | 33.3 | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 1.68 |  |  | 1.64 |  |  | 0.04 |  |  | 2.4 | %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.55 |  |  | 1.50 |  |  | 0.05 |  |  | 3.3 | %
Total Average CBM Production Costs (per Mcf) | $ | 4.04 |  |  | $ | 3.81 |  |  | $ | 0.23 |  |  | 6.0 | %
Total Average CBM Production Margin (per Mcf) | $ | (0.51) |  |  | $ | (0.91) |  |  | $ | 0.40 |  |  | 44.0 | %

The CBM segment had natural gas revenue of $33 million for the three months ended September 30, 2025 compared to $22 million for the three months ended September 30, 2024. The $11 million increase was primarily due to a 54.8% increase in the average sales price for natural gas in the current period offset, in part, by a 3.0% decrease in CBM sales volumes due to normal production declines.
The total average CBM sales price increased $0.63 per Mcf primarily due to a $1.20 per Mcf increase in average gas sales price offset, in part, by a $0.57 per Mcf change in the gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 7.4 Bcf of the Company's produced CBM sales volumes for the three months ended September 30, 2025 at an average gain of $0.18 per Mcf hedged. For the three months ended September 30, 2024, these financial hedges represented approximately 7.9 Bcf at an average gain of $0.90 per Mcf hedged.
Total operating costs and expenses for the CBM segment were $39 million for the three months ended September 30, 2025 compared to $38 million for the three months ended September 30, 2024. The increases in total dollars and unit costs for the CBM segment were due to the following items:
39

•CBM lease operating expenses were $6 million for the three months ended September 30, 2025 compared to $5 million for the three months ended September 30, 2024. The increase in total dollars and unit costs was primarily due to an increase in repairs and maintenance expense. The increase in per unit costs was also due to the decrease in total CBM volumes.
•CBM transportation, gathering and compression costs were $16 million for both the three months ended September 30, 2025 and 2024. The increase in unit costs was due to the decrease in total CBM volumes.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $15 million for both the three months ended September 30, 2025 and 2024. These amounts included depletion on a units of production basis of $0.87 per Mcfe and $0.85 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER SEGMENT
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, sales of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative expense (“SG&A”), interest expense and income taxes.
The Other Segment had earnings before income tax of $100 million for the three months ended September 30, 2025 compared to a loss before income tax of $53 million for the three months ended September 30, 2024. The increase in total dollars is discussed below.

| For the Three Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
Other Gas Sales Volumes (Bcf) | 0.1 |  |  | 0.1 |  |  | — |  |  | — | %

Unrealized Gain (Loss) on Commodity Derivative Instruments
For the three months ended September 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $110 million. For the three months ended September 30, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $6 million. The unrealized gain or loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Purchased Gas Revenue and Costs
Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $9 million for the three months ended September 30, 2025 compared to $27 million for the three months ended September 30, 2024. Purchased gas costs were $9 million for the three months ended September 30, 2025 compared to $27 million for the three months ended September 30, 2024. The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes offset, in part, by an increase in average sales price.

| For the Three Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
Purchased Gas Sales Volumes (in Bcf) | 3.3 |  |  | 16.3 |  |  | (13.0) |  |  | (79.8) | %
Average Sales Price (per Mcf) | $ | 2.73 |  |  | $ | 1.67 |  |  | $ | 1.06 |  |  | 63.5 | %
Purchased Gas Average Cost (per Mcf) | $ | 2.55 |  |  | $ | 1.63 |  |  | $ | 0.92 |  |  | 56.4 | %

40

Other Operating Income

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Sales of Environmental Attributes | $ | 18 |  |  | $ | 25 |  |  | $ | (7) |  |  | (28.0) | %
Equity Loss from Affiliates | (1) |  |  | — |  |  | (1) |  |  | (100.0) | %
Excess Firm Transportation Income | 4 |  |  | 4 |  |  | — |  |  | — | %
Water Income | 3 |  |  | 2 |  |  | 1 |  |  | 50.0 | %
Total Other Operating Income | $ | 24 |  |  | $ | 31 |  |  | $ | (7) |  |  | (22.6) | %

•Sales of environmental attributes include 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. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The decrease in the period-to-period comparison was primarily due to a decrease in the price received for the environmental attributes sold.
•Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in Total Other Operating Expense.
•Water income represents revenue generated when CNX accepts deliveries of produced water from third parties for reuse in the Company’s hydraulic fracturing operations, as well as from sales of freshwater to third parties.
Exploration and Production Related Other Costs

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Land Rentals | $ | 2 |  |  | $ | 1 |  |  | $ | 1 |  |  | 100.0 | %
Lease Expiration Costs | — |  |  | 1 |  |  | (1) |  |  | (100.0) | %
Total Exploration and Production Related Other Costs | $ | 2 |  |  | $ | 2 |  |  | $ | — |  |  | — | %

SG&A
SG&A includes costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Salaries, Wages and Employee Benefits | $ | 6 |  |  | $ | 7 |  |  | $ | (1) |  |  | (14.3) | %
Short-Term Incentive Compensation | 3 |  |  | 3 |  |  | — |  |  | — | %
Long-Term Equity-Based Compensation (Non-Cash) | 5 |  |  | 4 |  |  | 1 |  |  | 25.0 | %
Other | 16 |  |  | 19 |  |  | (3) |  |  | (15.8) | %
Total SG&A | $ | 30 |  |  | $ | 33 |  |  | $ | (3) |  |  | (9.1) | %

•Other decreased in the period-to-period comparison primarily due to lower professional services and various other one-time items, none of which were individually material.
41

Other Operating Expense

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Inventory Adjustments | $ | — |  |  | $ | (1) |  |  | $ | 1 |  |  | 100.0 | %
Insurance Expense | 1 |  |  | 2 |  |  | (1) |  |  | (50.0) | %
Environmental Attribute Fees | 3 |  |  | 4 |  |  | (1) |  |  | (25.0) | %
Unutilized Firm Transportation and Processing Fees | 12 |  |  | 13 |  |  | (1) |  |  | (7.7) | %
Other | 3 |  |  | (2) |  |  | 5 |  |  | 250.0 | %
Total Other Operating Expense | $ | 19 |  |  | $ | 16 |  |  | $ | 3 |  |  | 18.8 | %

•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Revenue and Operating Income.
•Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Income.
•Other increased in the period-to-period comparison due to multiple one-time items, none of which were individually material.
Other Expense (Income)

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Litigation Recoveries | $ | — |  |  | $ | 8 |  |  | $ | (8) |  |  | (100.0) | %
Right-of-Way Sales | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Other | 1 |  |  | 1 |  |  | — |  |  | — | %
Total Other Income | $ | 2 |  |  | $ | 9 |  |  | $ | (7) |  |  | (77.8) | %
Other Expense |  |  |  |  |  |  |
Bank Fees | 3 |  |  | 3 |  |  | — |  |  | — | %
Other Corporate Expense | 1 |  |  | 1 |  |  | — |  |  | — | %
Total Other Expense | $ | 4 |  |  | $ | 4 |  |  | $ | — |  |  | — | %
Total Other Expense (Income) | $ | 2 |  |  | $ | (5) |  |  | $ | 7 |  |  | 140.0 | %

•CNX pursues legal recoveries when certain circumstances arise. The decrease in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in the prior period.
Gain on Asset Sales and Abandonments, net
A net gain on asset sales and abandonments of $68 million was recognized in the three months ended September 30, 2025 compared to a net gain of $11 million in the three months ended September 30, 2024. The net gain recognized during the three months ended September 30, 2025 primarily relates to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million. The remaining net gain during the three months ended September 30, 2025, as well as, the net gain during the three months ended September 30, 2024 related to 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. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
42

Interest Expense

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Total Interest Expense | $ | 43 |  |  | $ | 38 |  |  | $ | 5 |  |  | 13.2 | %

The $5 million increase in total interest expense was primarily due to higher borrowings on the CNX Credit Facility at higher interest rates and higher principal balances related to the long-term debt that was issued in 2025 offset, in part, by lower borrowings on the CNXM Credit Facility. See Note 8 – Revolving Credit Facilities and Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Income Taxes

| For the Three Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Total Company Earnings Before Income Tax | $ | 266 |  |  | $ | 83 |  |  | $ | 183 |  |  | 220.5 | %
Income Tax Expense | $ | 64 |  |  | $ | 17 |  |  | $ | 47 |  |  | 276.5 | %
Effective Income Tax Rate | 23.9 | % |  | 20.6 | % |  | 3.3 | % |  |

The effective income tax rates for the three months ended September 30, 2025 and 2024 were 23.9% and 20.6%, respectively. The effective rate for the three months ended September 30, 2025 and 2024 differs from the U.S. federal statutory rate of 21% primarily due to the impact equity compensation, federal tax credits and state taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
43

Results of Operations - Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Net Income
CNX reported net income of $437 million, or earnings per diluted share of $2.57, for the nine months ended September 30, 2025, compared to net income of $54 million, or earnings per diluted share of $0.32, for the nine months ended September 30, 2024.
Included in the earnings for the nine months ended September 30, 2025 was an unrealized gain on commodity derivative instruments of $148 million and a net gain on asset sales and abandonments of $95 million. Included in the earnings for the nine months ended September 30, 2024 was an unrealized loss on commodity derivative instruments of $149 million and a net loss on asset sales and abandonments of $9 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the (gain) loss on asset sales and abandonments.
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations. These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Non-GAAP Financial Measures Reconciliation

| For the Nine Months Ended September 30,
(Dollars in millions) | 2025 | 2024
Total Revenue and Other Operating Income | $ | 1,629 |  |  | $ | 1,130 |
(Deduct) Add: |  |  |
Purchased Gas Revenue | (31) |  |  | (53) |
Unrealized (Gain) Loss on Commodity Derivative Instruments | (148) |  |  | 149 |
Other Revenue and Operating Income | (136) |  |  | (145) |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | $ | 1,314 |  |  | $ | 1,081 |
Total Operating Expense | $ | 1,007 |  |  | $ | 937 |
Deduct: |  |  |
Depreciation, Depletion and Amortization (DD&A) - Corporate | (17) |  |  | (10) |
Exploration and Production Related Other Costs | (6) |  |  | (7) |
Purchased Gas Costs | (29) |  |  | (51) |
Selling, General and Administrative Costs | (98) |  |  | (102) |
Other Operating Expense | (54) |  |  | (62) |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1 | $ | 803 |  |  | $ | 705 |

1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
44

Selected Natural Gas, NGL and Oil Production Financial Data
The following table presents a summary of our total sales volumes, sales of natural gas, NGL and oil including cash settlements, natural gas, NGL and oil production costs and natural gas, NGL and oil production margin related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation above for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP):

| For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | Variance
| in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe
Total Sales Volumes (Bcfe)* |  |  | 476.7 |  |  |  |  | 408.8 |  |  |  |  | 67.9 |
Natural Gas, NGL and Oil Revenue | $ | 1,437 |  |  | $ | 3.04 |  |  | $ | 822 |  |  | $ | 1.94 |  |  | $ | 615 |  |  | $ | 1.10 |
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement | (123) |  |  | (0.28) |  |  | 259 |  |  | 0.70 |  |  | (382) |  |  | (0.98) |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | 1,314 |  |  | 2.76 |  |  | 1,081 |  |  | 2.64 |  |  | 233 |  |  | 0.12 |
Lease Operating Expense | 77 |  |  | 0.16 |  |  | 53 |  |  | 0.13 |  |  | 24 |  |  | 0.03 |
Production, Ad Valorem, and Other Fees | 25 |  |  | 0.06 |  |  | 21 |  |  | 0.05 |  |  | 4 |  |  | 0.01 |
Transportation, Gathering and Compression | 289 |  |  | 0.61 |  |  | 284 |  |  | 0.70 |  |  | 5 |  |  | (0.09) |
Depreciation, Depletion and Amortization (DD&A) | 412 |  |  | 0.86 |  |  | 347 |  |  | 0.84 |  |  | 65 |  |  | 0.02 |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure | 803 |  |  | 1.69 |  |  | 705 |  |  | 1.72 |  |  | 98 |  |  | (0.03) |
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure | $ | 511 |  |  | $ | 1.07 |  |  | $ | 376 |  |  | $ | 0.92 |  |  | $ | 135 |  |  | $ | 0.15 |

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
The 67.9 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Changes in the average costs per Mcfe were primarily related to the following items:
•Lease operating expense increased on a per unit basis primarily due to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense. The increases were offset, in part, by the overall increase in total sales volumes.
•Transportation, gathering and compression expense decreased on a per unit basis primarily due to the overall increase in total sales volumes and a decrease in processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes. The per unit decreases was offset, in part, by higher repairs and maintenance expense.
•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate.
45

Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:

|  | For the Nine Months Ended September 30,
in thousands (unless noted) |  | 2025 |  | 2024 |  | Variance |  | Percent Change
LIQUIDS |  |  |  |  |  |  |  |
NGL: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 35,356 |  |  | 36,876 |  |  | (1,520) |  |  | (4.1) | %
Sales Volume (Mbbls) |  | 5,893 |  |  | 6,146 |  |  | (253) |  |  | (4.1) | %
Gross Price ($/Bbl) |  | $ | 22.14 |  |  | $ | 21.42 |  |  | $ | 0.72 |  |  | 3.4 | %
Gross NGL Revenue |  | $ | 130,483 |  |  | $ | 131,790 |  |  | $ | (1,307) |  |  | (1.0) | %
Oil/Condensate: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 705 |  |  | 677 |  |  | 28 |  |  | 4.1 | %
Sales Volume (Mbbls) |  | 118 |  |  | 113 |  |  | 5 |  |  | 4.4 | %
Gross Price ($/Bbl) |  | $ | 55.92 |  |  | $ | 63.12 |  |  | $ | (7.20) |  |  | (11.4) | %
Gross Oil/Condensate Revenue |  | $ | 6,574 |  |  | $ | 7,120 |  |  | $ | (546) |  |  | (7.7) | %
NATURAL GAS |  |  |  |  |  |  |  |
Sales Volume (MMcf) |  | 440,658 |  |  | 371,293 |  |  | 69,365 |  |  | 18.7 | %
Sales Price ($/Mcf) |  | $ | 2.95 |  |  | $ | 1.84 |  |  | $ | 1.11 |  |  | 60.3 | %
Gross Natural Gas Revenue |  | $ | 1,300,056 |  |  | $ | 682,754 |  |  | $ | 617,302 |  |  | 90.4 | %
Hedging Impact ($/Mcf) |  | $ | (0.28) |  |  | $ | 0.70 |  |  | $ | (0.98) |  |  | (140.0) | %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement |  | $ | (122,712) |  |  | $ | 259,397 |  |  | $ | (382,109) |  |  | (147.3) | %

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 67.9 Bcfe increase in total sales volumes and the $1.11 per Mcf increase in natural gas sales price, when excluding the impact of hedging. These increases were offset, in part, by the impact of the change in the (loss) gain on commodity derivative instruments - cash settlement related to the Company's hedging program.
46

SEGMENT ANALYSIS for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024:

| For the Nine Months Ended |  | Difference to Nine Months Ended
| September 30, 2025 |  | September 30, 2024
(in millions) | Shale |  | CBM |  | Other |  | Total |  | Shale |  | CBM |  | Other |  | Total
Natural Gas, NGLs and Oil Revenue | $ | 1,326 |  |  | $ | 109 |  |  | $ | 2 |  |  | $ | 1,437 |  |  | $ | 580 |  |  | $ | 34 |  |  | $ | 1 |  |  | $ | 615 |
(Loss) Gain on Commodity Derivative Instruments | (115) |  |  | (8) |  |  | 148 |  |  | 25 |  |  | (355) |  |  | (27) |  |  | 297 |  |  | (85) |
Purchased Gas Revenue | — |  |  | — |  |  | 31 |  |  | 31 |  |  | — |  |  | — |  |  | (22) |  |  | (22) |
Other Revenue and Operating Income | 52 |  |  | — |  |  | 84 |  |  | 136 |  |  | 2 |  |  | — |  |  | (11) |  |  | (9) |
Total Revenue and Other Operating Income | 1,263 |  |  | 101 |  |  | 265 |  |  | 1,629 |  |  | 227 |  |  | 7 |  |  | 265 |  |  | 499 |
Lease Operating Expense | 59 |  |  | 18 |  |  | — |  |  | 77 |  |  | 23 |  |  | 2 |  |  | (1) |  |  | 24 |
Production, Ad Valorem, and Other Fees | 20 |  |  | 5 |  |  | — |  |  | 25 |  |  | 3 |  |  | 1 |  |  | — |  |  | 4 |
Transportation, Gathering and Compression | 238 |  |  | 49 |  |  | 2 |  |  | 289 |  |  | 2 |  |  | 1 |  |  | 2 |  |  | 5 |
Depreciation, Depletion and Amortization | 365 |  |  | 43 |  |  | 21 |  |  | 429 |  |  | 67 |  |  | (1) |  |  | 6 |  |  | 72 |
Exploration and Production Related Other Costs | — |  |  | — |  |  | 6 |  |  | 6 |  |  | — |  |  | — |  |  | (1) |  |  | (1) |
Purchased Gas Costs | — |  |  | — |  |  | 29 |  |  | 29 |  |  | — |  |  | — |  |  | (22) |  |  | (22) |
Selling, General and Administrative Costs | — |  |  | — |  |  | 98 |  |  | 98 |  |  | — |  |  | — |  |  | (4) |  |  | (4) |
Other Operating Expense | — |  |  | — |  |  | 54 |  |  | 54 |  |  | — |  |  | — |  |  | (8) |  |  | (8) |
Total Operating Expense | 682 |  |  | 115 |  |  | 210 |  |  | 1,007 |  |  | 95 |  |  | 3 |  |  | (28) |  |  | 70 |
Other Expense | — |  |  | — |  |  | 9 |  |  | 9 |  |  | — |  |  | — |  |  | 20 |  |  | 20 |
Gain on Asset Sales and Abandonments, net | — |  |  | — |  |  | (95) |  |  | (95) |  |  | — |  |  | — |  |  | (104) |  |  | (104) |
Loss on Debt Extinguishment | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (7) |  |  | (7) |
Interest Expense | — |  |  | — |  |  | 129 |  |  | 129 |  |  | — |  |  | — |  |  | 15 |  |  | 15 |
Total Other Expense | — |  |  | — |  |  | 43 |  |  | 43 |  |  | — |  |  | — |  |  | (76) |  |  | (76) |
Total Costs and Expenses | 682 |  |  | 115 |  |  | 253 |  |  | 1,050 |  |  | 95 |  |  | 3 |  |  | (104) |  |  | (6) |
Earnings (Loss) Before Income Tax | $ | 581 |  |  | $ | (14) |  |  | $ | 12 |  |  | $ | 579 |  |  | $ | 132 |  |  | $ | 4 |  |  | $ | 369 |  |  | $ | 505 |

47

SHALE SEGMENT
The Shale segment had earnings before income tax of $581 million for the nine months ended September 30, 2025 compared to earnings before income tax of $449 million for the nine months ended September 30, 2024.

| For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
Shale Gas Sales Volumes (Bcf) | 412.2 |  |  | 341.9 |  |  | 70.3 |  |  | 20.6 | %
NGLs Sales Volumes (Bcfe)* | 35.3 |  |  | 36.9 |  |  | (1.6) |  |  | (4.3) | %
Oil/Condensate Sales Volumes (Bcfe)* | 0.6 |  |  | 0.7 |  |  | (0.1) |  |  | (14.3) | %
Total Shale Sales Volumes (Bcfe)* | 448.1 |  |  | 379.5 |  |  | 68.6 |  |  | 18.1 | %
Average Shale Gas Sales Price (per Mcf) | $ | 2.89 |  |  | $ | 1.78 |  |  | $ | 1.11 |  |  | 62.4 | %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | (0.28) |  |  | $ | 0.70 |  |  | $ | (0.98) |  |  | (140.0) | %
Average Sales Price - NGLs (per Mcfe)* | $ | 3.69 |  |  | $ | 3.57 |  |  | $ | 0.12 |  |  | 3.4 | %
Average Sales Price - Oil/Condensate (per Mcfe)* | $ | 9.11 |  |  | $ | 10.49 |  |  | $ | (1.38) |  |  | (13.2) | %
Total Average Shale Sales Price (per Mcfe) | $ | 2.70 |  |  | $ | 2.60 |  |  | $ | 0.10 |  |  | 3.8 | %
Average Shale Lease Operating Expenses (per Mcfe) | 0.13 |  |  | 0.10 |  |  | 0.03 |  |  | 30.0 | %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) | 0.04 |  |  | 0.04 |  |  | — |  |  | — | %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe) | 0.53 |  |  | 0.62 |  |  | (0.09) |  |  | (14.5) | %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.82 |  |  | 0.79 |  |  | 0.03 |  |  | 3.8 | %
Total Average Shale Production Costs (per Mcfe) | $ | 1.52 |  |  | $ | 1.55 |  |  | $ | (0.03) |  |  | (1.9) | %
Total Average Shale Production Margin (per Mcfe) | $ | 1.18 |  |  | $ | 1.05 |  |  | $ | 0.13 |  |  | 12.4 | %

* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGL, condensate, and natural gas prices.
The increase in total Shale sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,326 million for the nine months ended September 30, 2025 compared to $746 million for the nine months ended September 30, 2024. The $580 million increase was primarily due to a 62.4% increase in the average sales price for natural gas and an 18.1% increase in total Shale sales volumes. The increase was offset, in part, by the 140.0% change in the (loss) gain on commodity derivative instruments.
The increase in total average Shale sales price was primarily due to a $1.11 per Mcf increase in average gas sales price and a $0.12 per Mcfe increase in the average NGL sales price. These increases were offset, in part, by a $0.98 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 339.0 Bcf of the Company's produced Shale gas sales volumes for the nine months ended September 30, 2025 at an average loss of $0.34 per Mcf hedged. For the nine months ended September 30, 2024, these financial hedges represented approximately 285.6 Bcf at an average gain of $0.84 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $682 million for the nine months ended September 30, 2025 compared to $587 million for the nine months ended September 30, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:
•Shale lease operating expenses were $59 million for the nine months ended September 30, 2025 compared to $36 million for the nine months ended September 30, 2024. The increase in total dollars and unit costs was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions.
•Shale production, ad valorem and other fees were $20 million for the nine months ended September 30, 2025 compared to $17 million for the nine months ended September 30, 2024. The increase in total dollars was primarily due to increased realized prices on natural gas. Unit costs remained flat in the period-to-period comparison due to the overall increase
48

in volumes.
•Shale transportation, gathering and compression costs were $238 million for the nine months ended September 30, 2025 compared to $236 million for the nine months ended September 30, 2024. The increase in total dollars was primarily due to higher repairs and maintenance and electrical compression expense offset, in part, by lower processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes. The decrease in unit costs was due to the increase in total Shale sales volumes offset, in part, by the increases in total dollars.
•Depreciation, depletion and amortization costs attributable to the Shale segment were $365 million for the nine months ended September 30, 2025 compared to $298 million for the nine months ended September 30, 2024. These amounts included depletion on a unit of production basis of $0.71 per Mcfe and $0.67 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering services provided to third parties. The Shale segment had other revenue and operating income of $52 million for the nine months ended September 30, 2025 compared to $50 million for the nine months ended September 30, 2024. The increase in the period-to-period comparison was primarily due to an increase in third-party gathering volumes.
COALBED METHANE (CBM) SEGMENT
The CBM segment had a loss before income tax of $14 million for the nine months ended September 30, 2025 compared to a loss before income tax of $18 million for the nine months ended September 30, 2024.

| For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 28.4 |  |  | 29.1 |  |  | (0.7) |  |  | (2.4) | %
Average CBM Gas Sales Price (per Mcf) | $ | 3.85 |  |  | $ | 2.58 |  |  | $ | 1.27 |  |  | 49.2 | %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | (0.27) |  |  | $ | 0.65 |  |  | $ | (0.92) |  |  | (141.5) | %
Total Average CBM Sales Price (per Mcf) | $ | 3.58 |  |  | $ | 3.24 |  |  | $ | 0.34 |  |  | 10.5 | %
Average CBM Lease Operating Expenses (per Mcf) | 0.65 |  |  | 0.56 |  |  | 0.09 |  |  | 16.1 | %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) | 0.17 |  |  | 0.15 |  |  | 0.02 |  |  | 13.3 | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 1.74 |  |  | 1.65 |  |  | 0.09 |  |  | 5.5 | %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.53 |  |  | 1.50 |  |  | 0.03 |  |  | 2.0 | %
Total Average CBM Production Costs (per Mcf) | $ | 4.09 |  |  | $ | 3.86 |  |  | $ | 0.23 |  |  | 6.0 | %
Total Average CBM Production Margin (per Mcf) | $ | (0.51) |  |  | $ | (0.62) |  |  | $ | 0.11 |  |  | 17.7 | %

The CBM segment had natural gas revenue of $109 million for the nine months ended September 30, 2025 compared to $75 million for the nine months ended September 30, 2024. The $34 million increase was due to a 49.2% increase in the average sales price for natural gas in the current period offset, in part, by a 2.4% decrease in CBM sales volumes due to normal production declines.
The total average CBM sales price increased $0.34 per Mcf due to a $1.27 per Mcf increase in average natural gas sales price offset, in part, by a $0.92 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 21.8 Bcf of the Company's produced CBM sales volumes for the nine months ended September 30, 2025 at an average loss of $0.36 per Mcf hedged. For the nine months ended September 30, 2024, these financial hedges represented approximately 22.6 Bcf at an average gain of $0.84 per Mcf hedged.
Total operating costs and expenses for the CBM segment were $115 million for the nine months ended September 30, 2025 compared to $112 million for the nine months ended September 30, 2024. The increase in total dollars and unit costs for the CBM segment were due to the following items:
•CBM lease operating expenses were $18 million for the nine months ended September 30, 2025 compared to $16 million for the nine months ended September 30, 2024. The increase in total dollars and unit costs was primarily due to an
49

increase in water disposal costs and well tending expense. The increase in per unit costs was also due to the decrease in total CBM volumes.
•CBM transportation, gathering and compression costs were $49 million for the nine months ended September 30, 2025 compared to $48 million for the nine months ended September 30, 2024. The increase in total dollars was primarily due to higher repairs and maintenance expenses offset, in part, by lower electrical compression expense. The increase in per unit costs was also due to the decrease in CBM gas sales volumes.
•Depreciation, depletion and amortization costs attributable to the CBM segment was $43 million for the nine months ended September 30, 2025 compared to $44 million for the nine months ended September 30, 2024. These amounts included depletion on a unit of production basis of $0.86 per Mcfe and $0.85 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER SEGMENT
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, sales of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative expense (“SG&A”), interest expense and income taxes.
The Other Segment had earnings before income tax of $12 million for the nine months ended September 30, 2025 compared to a loss before income tax of $357 million for the nine months ended September 30, 2024. The increase in total dollars is discussed below.

| For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
Other Gas Sales Volumes (Bcf) | 0.2 |  |  | 0.2 |  |  | — |  |  | — | %

Unrealized Gain (Loss) on Commodity Derivative Instruments
For the nine months ended September 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $148 million. For the nine months ended September 30, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $149 million. The unrealized gain (loss) on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Purchased Gas Revenue and Costs
Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $31 million for the nine months ended September 30, 2025 compared to $53 million for the nine months ended September 30, 2024. Purchased gas costs were $29 million for the nine months ended September 30, 2025 compared to $51 million for the nine months ended September 30, 2024. The period-to-period decrease in purchased gas revenue was primarily due to a decrease in purchased gas sales volumes.

| For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | Variance |  | Percent Change
Purchased Gas Sales Volumes (in Bcf) | 9.4 |  |  | 27.8 |  |  | (18.4) |  |  | (66.2) | %
Average Sales Price (per Mcf) | $ | 3.29 |  |  | $ | 1.89 |  |  | $ | 1.40 |  |  | 74.1 | %
Purchased Gas Average Cost (per Mcf) | $ | 3.09 |  |  | $ | 1.82 |  |  | $ | 1.27 |  |  | 69.8 | %

50

Other Operating Income

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Sales of Environmental Attributes | $ | 61 |  |  | $ | 71 |  |  | $ | (10) |  |  | (14.1) | %
Excess Firm Transportation Income | 12 |  |  | 15 |  |  | (3) |  |  | (20.0) | %
Equity Loss from Affiliates | (1) |  |  | (1) |  |  | — |  |  | — | %
Water Income | 12 |  |  | 10 |  |  | 2 |  |  | 20.0 | %
Total Other Operating Income | $ | 84 |  |  | $ | 95 |  |  | $ | (11) |  |  | (11.6) | %

•Sales of environmental attributes include 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. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The decrease in the period-to-period comparison was due to a decrease in the amount of environmental attributes sold and a decrease in the price received.
•Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in Total Other Operating Expense.
•Water income represents revenue generated when CNX accepts deliveries of produced water from third parties for reuse in the Company’s hydraulic fracturing operations, as well as from sales of freshwater to third parties. Water income increased in the period-to-period comparison primarily due to an increase in third-party sales in the current period.
Exploration and Production Related Other Costs

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Lease Expiration Costs | $ | 1 |  |  | $ | 3 |  |  | $ | (2) |  |  | (66.7) | %
Land Rentals | 5 |  |  | 4 |  |  | 1 |  |  | 25.0 | %
Total Exploration and Production Related Other Costs | $ | 6 |  |  | $ | 7 |  |  | $ | (1) |  |  | (14.3) | %

SG&A
SG&A includes costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Salaries, Wages and Employee Benefits | $ | 19 |  |  | $ | 22 |  |  | $ | (3) |  |  | (13.6) | %
Short-term Incentive Compensation | 8 |  |  | 10 |  |  | (2) |  |  | (20.0) | %
Contributions and Advertising | 5 |  |  | 4 |  |  | 1 |  |  | 25.0 | %
Long-term Equity-Based Compensation (Non-Cash) | 19 |  |  | 15 |  |  | 4 |  |  | 26.7 | %
Other | 47 |  |  | 51 |  |  | (4) |  |  | (7.8) | %
Total SG&A | $ | 98 |  |  | $ | 102 |  |  | $ | (4) |  |  | (3.9) | %

•Salaries, wages and employee benefits decreased in the period-to-period comparison due to a reduction in headcount that occurred at the end of the first quarter of 2025.
•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in the amount of equity awards.
•Other decreased in the period-to-period comparison primarily due to lower professional services and various other one-time items, none of which were individually material.
51

Other Operating Expense

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Unutilized Firm Transportation and Processing Fees | $ | 30 |  |  | $ | 37 |  |  | $ | (7) |  |  | (18.9) | %
Environmental Attribute Fees | 8 |  |  | 11 |  |  | (3) |  |  | (27.3) | %
Idle Equipment and Service Charges | 3 |  |  | 4 |  |  | (1) |  |  | (25.0) | %
Water Expense | 1 |  |  | 1 |  |  | — |  |  | — | %
Inventory Adjustments | 1 |  |  | 1 |  |  | — |  |  | — | %
Insurance Expense | 3 |  |  | 3 |  |  | — |  |  | — | %
Virginia Flood Expense | — |  |  | (2) |  |  | 2 |  |  | 100.0 | %
Other | 8 |  |  | 7 |  |  | 1 |  |  | 14.3 | %
Total Other Operating Expense | $ | 54 |  |  | $ | 62 |  |  | $ | (8) |  |  | (12.9) | %

•Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Income. The decrease in period-to-period comparison was primarily due to lower fees in the current period, resulting from capacity optimization driven by colder weather in the earlier part of the year.
•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Revenue and Operating Income. The decrease in fees in the period-to-period comparison relates to the decrease in sales above.
Other Expense (Income)

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Litigation Recoveries | $ | — |  |  | $ | 20 |  |  | $ | (20) |  |  | (100.0) | %
Interest Income | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Right-of-Way Sales | 2 |  |  | 1 |  |  | 1 |  |  | 100.0 | %
Other | 3 |  |  | 3 |  |  | — |  |  | — | %
Total Other Income | $ | 6 |  |  | $ | 24 |  |  | $ | (18) |  |  | (75.0) | %
Other Expense |  |  |  |  |  |  |
Professional Services | $ | 3 |  |  | $ | 3 |  |  | $ | — |  |  | — | %
Bank Fees | 8 |  |  | 8 |  |  | — |  |  | — | %
Other Corporate Expense | 4 |  |  | 2 |  |  | 2 |  |  | 100.0 | %
Total Other Expense | $ | 15 |  |  | $ | 13 |  |  | $ | 2 |  |  | 15.4 | %
Total Other Expense (Income) | $ | 9 |  |  | $ | (11) |  |  | $ | 20 |  |  | 181.8 | %

•CNX pursues legal recoveries when certain circumstances arise. The decrease in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in the prior period.
52

(Gain) Loss on Asset Sales and Abandonments, net
A net gain on asset sales and abandonments of $95 million was recognized in the nine months ended September 30, 2025 compared to a net loss of $9 million in the nine months ended September 30, 2024. The net gain recognized in the nine months ended September 30, 2025 primarily relates to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million. The remaining net gain during the period primarily relates to sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material. The net loss recognized in the nine months ended September 30, 2024 primarily relates to a $26 million loss on the sale of a non-core pipeline to a third party offset, in part, by a net gain on the sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material.. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Loss on Debt Extinguishment
A loss on debt extinguishment of $7 million was recognized in the nine months ended September 30, 2024 in connection with CNX's repurchase of $350 million aggregate principal amount of 7.25% Senior Notes due March 2027 at an average price equal to 101.9% of the principal amount. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such transactions occurred in the current period.
Interest Expense

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Total Interest Expense | $ | 129 |  |  | $ | 114 |  |  | $ | 15 |  |  | 13.2 | %

The $15 million increase in total interest expense was primarily due to higher borrowings on the CNX Credit Facility at higher interest rates and higher principal balances related to the long-term debt that was issued in 2025 offset, in part, by lower borrowings on the CNXM Credit Facility. See Note 8 – Revolving Credit Facilities and Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Income Taxes

| For the Nine Months Ended September 30,
(in millions) | 2025 |  | 2024 |  | Variance |  | Percent Change
Total Company Earnings Before Income Tax | $ | 579 |  |  | $ | 74 |  |  | $ | 505 |  |  | 682.4 | %
Income Tax Expense | $ | 142 |  |  | $ | 20 |  |  | $ | 122 |  |  | 610.0 | %
Effective Income Tax Rate | 24.5 | % |  | 26.5 | % |  | (2.0) | % |  |

The effective income tax rates for the nine months ended September 30, 2025 and 2024 were 24.5% and 26.5%, respectively. The effective tax rate for the nine months ended September 30, 2025 and 2024 differs from the U.S. federal statutory rate of 21% primarily due to the impact of equity compensation, federal tax credits, and state taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
53

Liquidity and Capital Resources
Overview, Sources and Uses
CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CNX currently believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments, if any, and to provide required letters of credit for at least the next twelve months and the foreseeable future thereafter. Nevertheless, the ability of CNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, some of which are beyond CNX’s control.
From time to time, CNX is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.
CNX continuously reviews its liquidity and capital resources. If market conditions were to change, for instance due to a significant decline in commodity prices, and our revenue was reduced significantly or operating and capital costs were to increase significantly, our cash flows and liquidity could be reduced.
As of September 30, 2025, CNX was in compliance with all of its debt covenants. After considering the potential effect of a significant decline in commodity prices, CNX currently expects to remain in compliance with its debt covenants.
CNX frequently evaluates potential acquisitions. CNX has historically funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CNX on terms which CNX finds acceptable, or at all.
Factors that may Impact our Liquidity
•The Company’s cash on hand and access to additional liquidity. Cash, cash equivalents and restricted cash were $17 million as of September 30, 2025 and $55 million as of December 31, 2024.
•Accounts and notes receivable - trade were $141 million as of September 30, 2025 and $180 million as of December 31, 2024. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.
•As of September 30, 2025, CNX had approximately $329 million classified as current portion of long-term debt, primarily related to the Convertible Notes due in May 2026. CNX actively manages its debt, including maturities and interest rates, in order to maintain financial flexibility and support long-term strategic objectives. Management may, from time to time, refinance existing indebtedness, adjust the mix of variable- and fixed-rate debt, or pursue alternative financing sources to meet the Company’s cash and operational needs. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
•Capital expenditures are expected to range between $475 million to $500 million for the year ended December 31, 2025. For the nine months ended September 30, 2025, CNX had capital expenditures of $321 million.
•Production volumes are expected to range between 620.0 Bcfe and 625.0 Bcfe for the year ended December 31, 2025. For the nine months ended September 30, 2025, CNX had production volumes of 476.7 Bcfe.
•Prices for natural gas and NGLs are volatile, and an extended decline in the prices we receive for our natural gas and NGLs will adversely affect our financial condition and cash flows.
•In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas and NGL swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of $349 million at September 30, 2025 and a net liability of $536 million at December 31, 2024. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q for further discussion of our commodity risk management.
54

Cash Flows (in millions)

| For the Nine Months Ended September 30,
| 2025 |  | 2024 |  | Change
Cash Provided by Operating Activities | $ | 732 |  |  | $ | 547 |  |  | $ | 185 |
Cash Used in Investing Activities | $ | (736) |  |  | $ | (414) |  |  | $ | (322) |
Cash Used in Financing Activities | $ | (33) |  |  | $ | (132) |  |  | $ | 99 |

Cash flows from operating activities changed in the period-to-period comparison primarily due to the following items:
•Net income increased $383 million in the period-to-period comparison.
•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $310 million net change in commodity derivative instruments, a $124 million net increase in deferred income taxes, a $104 million increase in (gain) loss on asset sales and abandonments, net and a $92 million net increase for various other changes in working capital.
Cash flows from investing activities changed in the period-to-period comparison primarily due to the following items:
•Capital expenditures decreased $114 million primarily due to a decrease in drilling and completions activity.
•Proceeds from asset sales increased $81 million primarily due to the sale of Marcellus Shale rights, other non-core oil and gas rights and various non-operated producing oil and gas assets primarily located in the Appalachian Basin. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
•During the nine months ended September 30, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $518 million, subject to certain post-closing adjustments. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Cash flows from financing activities changed in the period-to-period comparison primarily due to the following items:
•Proceeds from borrowings under the CNXM Credit Facility increased $59 million and repayments under the CNXM Credit Facility decreased $24 million.
•Proceeds from borrowings under the CNX Credit Facility increased $635 million and repayments under the CNX Credit Facility increased $532 million.
•During the nine months ended September 30, 2025, CNX issued an additional $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of par. This issuance also included an underwriter discount and other issuance costs of $1.5 million, for net cash proceeds of $198.5 million. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
•During the nine months ended September 30, 2024, CNX paid $357 million to repurchase $350 million aggregate principal amount of CNX 7.25% Senior Notes due March 2027 at a price of 101.9% of the principal amount. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
•During the nine months ended September 30, 2024, CNX issued $400 million aggregate principal amount of CNX 7.25% Senior Notes due March 2032 at par. The issuance included an underwriter discount and other issuance costs of $5 million, for net cash proceeds of $395 million. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
•In the nine months ended September 30, 2025, CNX repurchased $423 million of its common stock on the open market compared to $159 million during the nine months ended September 30, 2024.
•During the nine months ended September 30, 2025, debt issuance and financing fees decreased $14 million primarily due to amending both the CNX and CNXM Credit Facilities in the prior year. See Note 8 – Revolving Credit Facilities in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
55

Commitments and Significant Contractual and Other Material Cash Obligations
The following is a summary of the Company's significant contractual and other material cash obligations at September 30, 2025 (in thousands):

| Payments due by Year
| Less Than 1 Year |  | 1-3 Years |  | 3-5 Years |  | More Than 5 Years |  | Total
Purchase Order Firm Commitments | $ | 3,651 |  |  | $ | 6,784 |  |  | $ | 3,023 |  |  | $ | — |  |  | $ | 13,458 |
Gas Firm Transportation and Processing | 250,425 |  |  | 480,325 |  |  | 284,136 |  |  | 488,484 |  |  | 1,503,370 |
Long-Term Debt | 329,479 |  |  | — |  |  | 1,165,106 |  |  | 1,090,642 |  |  | 2,585,227 |
Interest on Long-Term Debt | 154,150 |  |  | 293,420 |  |  | 224,706 |  |  | 83,687 |  |  | 755,963 |
Finance Lease Obligations | 6,036 |  |  | 15,313 |  |  | 20,750 |  |  | 6,323 |  |  | 48,422 |
Interest on Finance Lease Obligations | 2,881 |  |  | 4,712 |  |  | 2,164 |  |  | 508 |  |  | 10,265 |
Operating Lease Obligations | 48,096 |  |  | 93,460 |  |  | 21,213 |  |  | 7,848 |  |  | 170,617 |
Interest on Operating Lease Obligations | 9,122 |  |  | 9,444 |  |  | 1,579 |  |  | 1,035 |  |  | 21,180 |
Long-Term Liabilities—Employee Related (a) | 2,175 |  |  | 4,547 |  |  | 4,943 |  |  | 20,549 |  |  | 32,214 |
Other Long-Term Liabilities (b) | 218,693 |  |  | 51,327 |  |  | 20,000 |  |  | 104,961 |  |  | 394,981 |
Total Contractual Obligations (c) | $ | 1,024,708 |  |  | $ | 959,332 |  |  | $ | 1,747,620 |  |  | $ | 1,804,037 |  |  | $ | 5,535,697 |

_________________________
(a)Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.
(b)Other long-term liabilities include royalties and other long-term liability costs.
(c)The table above does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
Debt
At September 30, 2025, CNX had total debt of $2,585 million, including the current portion of long-term debt of $329 million and excluding unamortized debt issuance costs. This long-term debt consisted of:
•An aggregate principal amount of $600 million of 7.25% Senior Notes due March 2032 less $5 million of unamortized discount. Interest on the notes is payable March 1 and September 1 of each year. Payment on 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).
•An aggregate principal amount of $500 million of 6.00% Senior Notes due January 2029. Interest on the notes is payable January 15 and July 15 of each year. 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).
•An aggregate principal amount of $500 million of 7.375% Senior Notes due January 2031, less $4 million of unamortized discount. Interest on the notes is payable January 15 and July 15 each year. 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).
•An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $3 million of unamortized discount. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of these notes.
•An aggregate principal amount of $330 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $1 million of unamortized discount and issuance costs. Interest on the notes is payable May 1 and November 1 of each year. 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). The Convertible Notes are classified as short-term debt at September 30, 2025.
•An aggregate principal amount of $247 million in outstanding borrowings under the CNX Credit Facility. Payment of the principal and interest on the CNX Credit Facility is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
•An aggregate principal amount of $21 million in outstanding borrowings under the CNXM Credit Facility. Payment of the principal and interest on the CNXM Credit Facility is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of the CNXM Facility.
56

Total Equity and Dividends
CNX had total equity of $4,116 million at September 30, 2025 compared to $4,098 million at December 31, 2024. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.
The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance can be given that CNX will pay dividends in the future. CNX has not paid dividends on its common stock since 2016. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX, and such other factors as CNX's Board of Directors deems relevant. In addition, CNX's ability to pay dividends is limited by the covenants in the agreement governing the CNX Credit Facility and the indentures governing certain of CNX's Senior Notes.
Off-Balance Sheet Transactions
CNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CNX uses a combination of surety bonds, corporate guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected in the Consolidated Balance Sheet at September 30, 2025. Management believes these items will expire without being funded. See Note 11 – Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CNX.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities, revenue and expenses and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements. Actual results could materially differ from those estimates.
This discussion and analysis of our consolidated results of operations and financial condition should be read in conjunction with our Consolidated Financial Statements included in this Form 10-Q. The 2024 financial statements, included in the 2024 Form 10-K filed with the SEC, provide additional information about our operations, financial condition, critical accounting policies, and accounting estimates, and should be read alongside this Form 10-Q. Our significant accounting policies are described in Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Part II, Item 8 of the 2024 Form 10-K.
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Forward-Looking Statements
We are including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Form 10-Q are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," "will," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe a strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Form 10-Q speak only as of the date of this Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
•prices for natural gas and natural gas liquids (“NGLs”) are volatile and can fluctuate widely based upon a number of factors beyond our control, including supply and demand for our products;
•if natural gas prices decrease or operational efforts are unsuccessful, CNX may be required to record write-downs of the quantity and value of our proved natural gas properties;
•competition and consolidation within the natural gas industry may adversely affect our ability to sell our products and midstream services or other parts of the business;
•deterioration in the economic conditions in any of the industries in which our customers or their customers operate, a domestic or worldwide financial downturn, or negative credit market conditions may have a material adverse effect on our liquidity, results of operations, business and financial condition that CNX cannot predict;
•our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
•negative public perception regarding our company or industry could have an adverse effect on our operations, financial results or stock price;
•events beyond our control, including a global or domestic health crisis or global instability and actual and threatened geopolitical conflict, may result in unexpected adverse operating and financial results;
•increasing attention to environmental, social and governance matters may adversely impact our business;
•our dependence on third party pipeline and processing systems could adversely affect our operations and limit sales of our natural gas and NGLs as a result of disruptions, capacity constraints, proximity issues or decreases in availability of pipelines or other midstream facilities;
•uncertainties exist in the estimation of the economic recovery of natural gas reserves;
•developing, producing and operating natural gas wells is subject to operating risks and hazards that could increase expenses, decrease our production levels and expose us to losses or liabilities that may not be fully covered under our insurance policies;
•our identified development locations are scheduled over multiple future years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their actual development;
•our exploration and development projects and midstream development require substantial capital expenditures and are subject to regulatory, environmental, political, legal and economic risks and if CNX fails to generate sufficient cash flow, obtain required capital or financing on satisfactory terms or respond to regulatory and political developments, our natural gas reserves may decline, and our operations and financial results may suffer;
•CNX may not be able to obtain the required personnel, services, equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our operations;
•if CNX cannot find adequate sources of water for our use or if CNX is unable to dispose of or recycle water produced from our operations at a reasonable cost and within applicable environmental rules, our ability to produce natural gas economically and in sufficient quantities could be impaired;
•failure to successfully replace our current natural gas reserves through economic development of our existing or acquired undeveloped assets or through acquisition of additional producing assets, would lead to a decline in our natural gas, NGL and oil production levels and reserves;
•CNX may incur losses as a result of title defects in the properties in which CNX invests or that it acquires or the loss of certain leasehold or other rights related to our midstream activities;
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•climate change risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets;
•environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;
•existing and future governmental laws, regulations, other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations;
•CNX may incur significant costs and liabilities as a result of pipeline operations and/or increases in the regulation of natural gas pipelines and midstream facilities;
•changes in federal or state tax laws focused on natural gas exploration and development could cause our financial position and profitability to deteriorate;
•our future tax liability may be greater than expected if our net operating loss carryforwards are limited, CNX does not generate expected deductions, or tax authorities challenge certain of our tax positions;
•we may be unable to qualify for existing federal and state level environmental attribute credits and new markets for environmental attributes are currently volatile, and otherwise may not develop as quickly or efficiently as we anticipate or at all;
•CNX and its subsidiaries are subject to various legal proceedings and investigations, which may have an adverse effect on our business;
•our current long-term debt obligations, the terms of the agreements that govern that debt, and the risks associated therewith, could adversely affect our business, financial condition, liquidity and results of operations;
•our borrowing base under our revolving credit facility could decrease for a variety of reasons including lower natural gas prices, declines in natural gas reserves, asset sales and lending requirements or regulations;
•the capped call transactions may affect the value of the Convertible Notes and our common stock, and subject CNX to counterparty performance risk;
•conversion of the Convertible Notes may dilute the ownership interest of existing shareholders or may otherwise depress the price of our common stock;
•CNX may be unable to raise the funds necessary to repurchase the Convertible Notes for cash following a fundamental change, or to pay any cash amounts due upon conversion, and our other indebtedness may impact our ability to repurchase the convertible notes or pay cash upon their conversion;
•the conditional conversion feature of the Convertible Notes, if triggered, may adversely affect our financial condition and operating results;
•provisions of our debt agreements, including the Convertible Notes, could delay or prevent an otherwise beneficial takeover of us;
•strategic determinations, including the allocation of capital and other resources to strategic opportunities, are subject to risk and uncertainties, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition;
•CNX does not completely control the timing of any divestitures that CNX may engage in, and they may not provide anticipated benefits. Additionally, CNX may be unable to acquire additional properties in the future and any acquired properties may not provide the anticipated benefits;
•there is no guarantee that CNX will continue to repurchase shares of our common stock under our current or any future share repurchase program at levels undertaken previously or at all;
•CNX may operate a portion of our business with one or more joint venture partners or in circumstances where CNX is not the operator, which may restrict our operational and corporate flexibility;
•in connection with the separation of our coal business, CONSOL Energy has agreed to indemnify us for certain liabilities, and we have agreed to indemnify CONSOL Energy for certain liabilities;
•cybersecurity incidents targeting our data systems, oil and natural gas industry systems and infrastructure, or the systems of our third-party service providers or business partners could materially adversely affect our business, financial condition or results of operations;
•terrorist activities could materially adversely affect our business and results of operations; and
•certain other factors addressed in this report and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024 under "Risk Factors".
Although forward-looking statements reflect our good faith beliefs at the time they are made, they involve known and unknown risks, uncertainties and other factors. For more information concerning factors that could cause actual results to differ materially from those conveyed in the forward-looking statements, including, among others, that our business plans may change as circumstances warrant, please refer to the “Risk Factors” and “Cautionary Statement regarding Forward-looking Statements” sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.
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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In addition to the risks inherent in operations, CNX is exposed to certain financial, market, political and economic risks. The following discussion provides additional detail regarding CNX's exposure to the risks of changing commodity prices, interest rates and foreign exchange rates.
CNX is exposed to market price risk in the normal course of selling natural gas and NGLs. CNX uses fixed-price contracts, options and derivative commodity instruments (over-the-counter swaps) to minimize exposure to market price volatility in the sale of natural gas and NGLs. Under our risk management policy, it is not our intent to engage in derivative activities for speculative purposes. Typically, CNX "sells" swaps under which it receives a fixed price from counterparties and pays a floating market price, but occasionally CNX may find it advantageous to purchase, rather than "sell", financial swaps.
CNX has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. The Company's market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within predefined risk parameters.
CNX believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates our exposure to material pricing risks. The use of derivative instruments without other risk assessment procedures could materially affect the Company's results of operations depending on market prices; however, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity due to our risk assessment procedures and internal controls.
For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.
CNX's open derivative instruments can cause earnings volatility relative to changes in market prices until the derivative contracts are either settled or are monetized prior to settlement. At September 30, 2025 and December 31, 2024 our open derivative instruments were in net liability positions with fair values of $349 million and $536 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at September 30, 2025 and December 31, 2024. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $440 million and $518 million at September 30, 2025 and December 31, 2024, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by $440 million and $518 million at September 30, 2025 and December 31, 2024, respectively.
CNX's interest expense is sensitive to changes in the general level of interest rates in the United States. The Company has used derivative instruments in the past in order to manage risk related to interest rates, although there are currently no active agreements (see Note 12 – Derivative Instruments in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for more information). At September 30, 2025 and December 31, 2024, CNX had $2,340 million and $2,132 million, respectively, of aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $9 million. At September 30, 2025 and December 31, 2024, CNX had $268 million and $59 million, respectively, of debt outstanding under variable-rate instruments. CNX’s primary exposure to market risk for changes in interest rates relates to the CNX Credit Facility, under which there were $247 million borrowings at September 30, 2025 and $43 million borrowings at December 31, 2024, and the CNXM Credit Facility, under which there were $21 million of borrowings at September 30, 2025 and $16 million at December 31, 2024. A hypothetical 100 basis-point increase in the average rate for CNX's variable-rate instruments would decrease pre-tax future earnings as of September 30, 2025 and December 31, 2024 by $3 million and $1 million, respectively, on an annualized basis.
All of the Company’s transactions are denominated in U.S. dollars and, as a result, it does not have material exposure to currency exchange-rate risks.
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Natural Gas Hedging Volumes
As o f October 8, 2025, the Company's hedged volumes for the periods indicated are as follows:

| For the Three Months Ended |  |
| March 31, |  | June 30, |  | September 30, |  | December 31, |  | Total Year
2025 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | N/A |  | N/A |  | N/A |  | 121.9 |  |  | 121.9 |
Weighted Average Hedge Price per Mcf | N/A |  | N/A |  | N/A |  | $ | 2.55 |  |  | $ | 2.55 |
2026 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 111.1 |  |  | 110.0 |  |  | 111.0 |  |  | 111.0 |  |  | 441.3*
Weighted Average Hedge Price per Mcf | $ | 2.77 |  |  | $ | 2.69 |  |  | $ | 2.69 |  |  | $ | 2.67 |  |  | $ | 2.70 |
2027 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 88.7 |  |  | 88.0 |  |  | 89.0 |  |  | 87.2 |  |  | 350.3*
Weighted Average Hedge Price per Mcf | $ | 3.26 |  |  | $ | 3.26 |  |  | $ | 3.26 |  |  | $ | 3.30 |  |  | $ | 3.26 |
2028 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 34.5 |  |  | 34.6 |  |  | 34.9 |  |  | 34.9 |  |  | 138.9 |
Weighted Average Hedge Price per Mcf | $ | 3.24 |  |  | $ | 3.24 |  |  | $ | 3.24 |  |  | $ | 3.24 |  |  | $ | 3.24 |
2029 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 4.3 |  | 4.3 |  | 4.3 |  | 4.4 |  | 17.3
Weighted Average Hedge Price per Mcf | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.02 |

*Quarterly volumes do not add to annual volumes inasmuch as a discrete condition in individual quarters, where basis hedge volumes exceed NYMEX hedge volumes, does not exist for the year taken as a whole.
ITEM 4.CONTROLS AND PROCEDURES
Disclosure controls and procedures. CNX, under the supervision and with the participation of its management, including CNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s "disclosure controls and procedures," as such term is defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this Form 10-Q. Based on that evaluation, CNX’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2025 to ensure that information required to be disclosed by CNX in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CNX in such reports is accumulated and communicated to CNX’s management, including CNX’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting. There were no changes in the Company's internal control over financial reporting that occurred during the last fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II: OTHER INFORMATION
ITEM 1.LEGAL PROCEEDINGS
The first through the third paragraphs of Note 11 – Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.
From time to time, CNX and federal, state, and local regulatory agencies that oversee CNX’s activities enter into agreements regarding notices of noncompliance. CNX is currently not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which the Company is subject to, that would have a material effect on future financial results.
ITEM 1A. RISK FACTORS
The financial conditions and operating results of the Company can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in "Item 1A. Risk Factors" in the 2024 Form 10-K. The risks described could materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. CNX may experience additional risks and uncertainties not currently known; or, as a result of developments occurring in the future, conditions that are currently deemed to be immaterial may also materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. Except for the risk factor disclosed in Part II, Item 1A of the first quarter 2025 Form 10-Q, which is hereby incorporated by reference into this Part II, Item 1A of this Form 10-Q, there have been no material changes to the Company’s risk factors as set forth in the 2024 Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth repurchases of our common stock during the three months ended September 30, 2025:

ISSUER PURCHASES OF EQUITY SECURITIES
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (000's omitted)
July 1, 2025 - July 31, 2025 | 1,227,882 |  | $ | 32.16 |  | 1,227,882 |  | $ | 672,149 |
August 1, 2025 - August 31, 2025 | 2,388,400 |  | $ | 28.85 |  | 2,380,183 |  | $ | 603,473 |
September 1, 2025 - September 30, 2025 | 2,447,912 |  | $ | 30.34 |  | 2,444,136 |  | $ | 529,319 |
Total | 6,064,194 |  |  | 6,052,201 |  |

(1) Includes shares of common stock withheld from employees to satisfy minimum tax withholding obligations associated with the vesting of restricted stock during the period.
(2) Shares repurchased as part of the Company's current $2,900 million share repurchase program authorized by CNX's Board of Directors and announced on September 5, 2017, which is not subject to an expiration date. See Note 15 – Stock Repurchase in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for more information.
ITEM 5. OTHER INFORMATION
Trading Arrangements
None of the Company’s directors or "officers," as defined in Rule 16a-1(f) of the Exchange Act adopted, modified, or terminated a "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408 of Regulation S-K, during the Company’s fiscal quarter ended September 30, 2025.
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ITEM 6.EXHIBITS

31.1* |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 |  |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 |  |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS |  | Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH* |  | Inline XBRL Taxonomy Extension Schema Document.
101.CAL* |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF* |  | Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB* |  | Inline XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE* |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104* |  | Cover Page Interactive Data File (embedded within the Inline XBRL document)

* Filed herewith
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: October 30, 2025

CNX RESOURCES CORPORATION
| By: |  | /S/ N ICHOLAS J. D EIULIIS
|  |  | Nicholas J. DeIuliis
|  |  | Director and Chief Executive Officer (Duly Authorized Officer and Principal Executive Officer)
| By: |  | /S/ ALAN K. SHEPARD
|  |  | Alan K. Shepard
|  |  | President and Chief Financial Officer (Duly Authorized Officer and Principal Financial and Accounting Officer)
| By: |  | /S/ JASON L. MUMFORD
|  |  | Jason L. Mumford
|  |  | Vice President and Controller

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