cnx-20260630

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 June 30, 2026


☐			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 July 15, 2026
Common stock, $0.01 par value						147,943,637

TABLE OF CONTENTS


		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Unaudited Condensed Consolidated Financial Statements
	Consolidated Statements of Income for the three and six months ended June 30, 2026 and 2025	5
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2026 and 2025	6
	Consolidated Balance Sheets at June 30, 2026 and December 31, 2025	7
	Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2026 and 2025	9
	Consolidated Statements of Cash Flows for the six months ended June 30, 2026 and 2025	11
	Notes to Unaudited Consolidated Financial Statements	12

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	57

ITEM 4.	Controls and Procedures	58

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	59

ITEM 1A.	Risk Factors	59

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59

ITEM 5.	Other Information	59

ITEM 6.	Exhibits	60

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				Six Months Ended
(Unaudited)	June 30,				June 30,
Revenue and Other Operating Income:	2026		2025		2026		2025
Natural Gas, NGLs and Oil Revenue	$	389,435	$	485,029	$	1,111,478	$	1,036,123
Gain (Loss) on Commodity Derivative Instruments	176,336		421,121		180,317		(107,099)
Purchased Gas Revenue	12,456		10,408		25,143		21,959

Other Revenue and Operating Income	40,257		45,864		88,200		93,828
Total Revenue and Other Operating Income	618,484		962,422		1,405,138		1,044,811
Costs and Expenses:
Operating Expense
Lease Operating Expense	21,262		26,256		43,032		49,588
Production, Ad Valorem and Other Fees	6,546		9,668		15,335		16,941
Transportation, Gathering and Compression	103,223		96,953		205,625		192,112
Depreciation, Depletion and Amortization	136,232		152,595		270,845		279,657
Exploration and Production Related Other Costs	2,750		1,770		6,928		3,853
Purchased Gas Costs	12,249		9,402		24,502		20,611


Selling, General, and Administrative Costs	33,837		29,068		66,082		68,082
Other Operating Expense	24,611		21,014		19,989		35,095
Total Operating Expense	340,710		346,726		652,338		665,939
Other Expense
Other Expense	1,183		3,729		1,691		7,676
Loss (Gain) on Asset Sales and Abandonments, net	626		(17,715)		(5,740)		(27,298)

Loss on Debt Extinguishment	—		—		12,009		—
Interest Expense	39,023		44,041		79,493		85,652
Total Other Expense	40,832		30,055		87,453		66,030
Total Costs and Expenses	381,542		376,781		739,791		731,969
Income Before Income Tax	236,942		585,641		665,347		312,842
Income Tax Expense	33,999		153,120		114,257		78,036


Net Income	$	202,943	$	432,521	$	551,090	$	234,806



Earnings per Share
Basic	$	1.37	$	3.02	$	3.80	$	1.61
Diluted	$	1.32	$	2.53	$	3.56	$	1.37

Dividends Declared	$	—	$	—	$	—	$	—

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended				Six Months Ended
(Dollars in thousands)	June 30,				June 30,
(Unaudited)	2026		2025		2026		2025
Net Income	$	202,943	$	432,521	$	551,090	$	234,806
Other Comprehensive Income:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $(27), $(26), $(54), $(52))	72		69		144		139



Comprehensive Income	$	203,015	$	432,590	$	551,234	$	234,945

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	(Unaudited)
(Dollars in thousands)	June 30, 2026		December 31, 2025
ASSETS
Current Assets:
Cash and Cash Equivalents	$	6,162	$	779
Restricted Cash	2,428		12,685
Accounts and Notes Receivable:
Trade, net	163,835		264,658
Other Receivables, net	25,771		61,249
Supplies Inventories	32,509		26,201


Derivative Instruments	220,712		106,068
Prepaid Expenses	19,938		18,697


Total Current Assets	471,355		490,337
Property, Plant and Equipment:
Property, Plant and Equipment	14,380,988		14,057,224
Less—Accumulated Depreciation, Depletion and Amortization	6,442,893		6,193,871


Total Property, Plant and Equipment—Net	7,938,095		7,863,353
Other Non-Current Assets:

Operating Lease Right-of-Use Assets	126,593		150,310

Derivative Instruments	165,543		134,396
Goodwill	323,314		323,314
Other Intangible Assets	54,057		57,333


Other	57,942		75,403

Total Other Non-Current Assets	727,449		740,756
TOTAL ASSETS	$	9,136,899	$	9,094,446

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	(Unaudited)
(Dollars in thousands, except per share data)	June 30, 2026		December 31, 2025
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	179,800	$	158,811
Derivative Instruments	174,882		377,945
Current Portion of Finance Lease Obligations	5,110		5,095
Current Portion of Long-Term Debt	—		208,095

Current Portion of Operating Lease Obligations	46,792		48,453
Other Accrued Liabilities	251,308		325,976


Total Current Liabilities	657,892		1,124,375
Non-Current Liabilities:
Long-Term Debt	2,223,745		2,213,264
Finance Lease Obligations	22,437		24,991
Operating Lease Obligations	82,024		104,955
Derivative Instruments	78,928		158,368
Deferred Income Taxes	969,080		857,367
Asset Retirement Obligations	165,693		163,051


Other	93,291		111,059

Total Non-Current Liabilities	3,635,198		3,633,055
TOTAL LIABILITIES	4,293,090		4,757,430
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 149,036,879 Issued and Outstanding at June 30, 2026; 142,590,509 Issued and Outstanding at December 31, 2025	1,491		1,427
Capital in Excess of Par Value	2,526,486		2,357,039
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—		—
Retained Earnings	2,321,367		1,984,229
Accumulated Other Comprehensive Loss	(5,535)		(5,679)



TOTAL STOCKHOLDERS' EQUITY	4,843,809		4,337,016
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,136,899	$	9,094,446

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

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
March 31, 2026	$	1,420	$	2,356,077	$	2,274,690	$	(5,607)	$	4,626,580
Net Income	—		—		202,943		—		202,943
Issuance of Common Stock	2		1,743		—		—		1,745
Purchase and Retirement of Common Stock	(57)		(45,585)		(156,266)		—		(201,908)
Convertible Debt Exchange for Shares	126		182,075		—		—		182,201
Settlement of Capped Call	—		26,351		—		—		26,351

Amortization of Stock-Based Compensation Awards	—		5,825		—		—		5,825


Other Comprehensive Income	—		—		—		72		72


June 30, 2026	$	1,491	$	2,526,486	$	2,321,367	$	(5,535)	$	4,843,809
(Dollars in thousands) (Unaudited)
March 31, 2025	$	1,456	$	2,324,116	$	1,450,844	$	(5,642)	$	3,770,774
Net Income	—		—		432,521		—		432,521
Issuance of Common Stock	—		110		—		—		110
Purchase and Retirement of Common Stock	(37)		(30,339)		(85,063)		—		(115,439)
Shares Withheld for Taxes	—		—		(406)		—		(406)
Amortization of Stock-Based Compensation Awards	1		5,083		—		—		5,084


Other Comprehensive Income	—		—		—		69		69


June 30, 2025	$	1,420	$	2,298,970	$	1,797,896	$	(5,573)	$	4,092,713

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

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, 2025	$	1,427	$	2,357,039	$	1,984,229	$	(5,679)	$	4,337,016
(Unaudited)
Net Income	—		—		551,090		—		551,090
Issuance of Common Stock	3		3,248		—		—		3,251
Purchase and Retirement of Common Stock	(72)		(53,733)		(198,736)		—		(252,541)
Convertible Debt Exchange for Shares	126		182,078		—		—		182,204
Settlement of Capped Call	—		26,351		—		—		26,351
Shares Withheld for Taxes	—		—		(15,216)		—		(15,216)
Amortization of Stock-Based Compensation Awards	7		11,503		—		—		11,510
Other Comprehensive Income	—		—		—		144		144


June 30, 2026	$	1,491	$	2,526,486	$	2,321,367	$	(5,535)	$	4,843,809
(Dollars in thousands)
December 31, 2024	$	1,490	$	2,348,959	$	1,753,293	$	(5,712)	$	4,098,030
(Unaudited)
Net Income	—		—		234,806		—		234,806
Issuance of Common Stock	1		929		—		—		930
Purchase and Retirement of Common Stock	(79)		(64,810)		(176,711)		—		(241,600)
Shares Withheld for Taxes	—		—		(13,492)		—		(13,492)
Amortization of Stock-Based Compensation Awards	8		13,892		—		—		13,900
Other Comprehensive Income	—		—		—		139		139


June 30, 2025	$	1,420	$	2,298,970	$	1,797,896	$	(5,573)	$	4,092,713

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


(Unaudited)	Six Months Ended
Dollars in Thousands	June 30,
Cash Flows from Operating Activities:	2026		2025
Net Income	$	551,090	$	234,806
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Depreciation, Depletion and Amortization	270,845		279,657
Amortization of Deferred Financing Costs	4,702		5,370


Stock-Based Compensation	11,510		13,900
Gain on Asset Sales and Abandonments, net	(5,740)		(27,298)

Loss on Debt Extinguishment	12,009		—
(Gain) Loss on Commodity Derivative Instruments	(180,317)		107,099

Net Cash Paid in Settlement of Commodity Derivative Instruments	(247,976)		(172,382)
Deferred Income Taxes	111,659		65,303
Other	1,108		491

Changes in Operating Assets:
Accounts and Notes Receivable	110,488		9,771

Supplies Inventories	(6,308)		(24,746)
Prepaid Expenses	(1,241)		(1,066)
Changes in Other Assets	14,702		23,174
Changes in Operating Liabilities:
Accounts Payable	(13,853)		(57)
Accrued Interest	(4,649)		5,916
Other Operating Liabilities	(53,402)		381
Changes in Other Liabilities	(17,595)		(22,172)



Net Cash Provided by Operating Activities	557,032		498,147
Cash Flows from Investing Activities:
Capital Expenditures	(311,906)		(245,030)

Proceeds from Asset Sales	32,795		37,413
Investment in Equity Affiliates	(565)		(3,303)
Apex Acquisition (Net of Cash Acquired)	(10,255)		(517,599)


Net Cash Used in Investing Activities	(289,931)		(728,519)
Cash Flows from Financing Activities:

Payments on Long-Term Notes	(507,965)		—
Proceeds from CNXM Revolving Credit Facility Borrowings	204,100		180,425
Repayments of CNXM Revolving Credit Facility Borrowings	(146,850)		(174,475)
Proceeds from CNX Revolving Credit Facility Borrowings	1,019,350		1,138,250
Repayments of CNX Revolving Credit Facility Borrowings	(1,063,700)		(895,250)
Proceeds from Issuance of CNX Senior Notes	500,000		198,500


Payments on Other Debt	(2,417)		(1,907)



Proceeds from Issuance of Common Stock	3,251		930
Shares Withheld for Taxes	(15,216)		(13,492)
Purchases of Common Stock	(254,438)		(240,852)
Debt Issuance and Financing Fees	(8,090)		(939)


Net Cash (Used in) Provided by Financing Activities	(271,975)		191,190
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(4,874)		(39,182)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	13,464		55,073
Cash, Cash Equivalents and Restricted Cash at End of Period	$	8,590	$	15,891

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

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 six months ended June 30, 2026 are not necessarily indicative of the results that may be expected for future periods.

The Consolidated Balance Sheet at December 31, 2025 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, 2025 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 10, 2026 (the "2025 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 $6,162 and $779 as of June 30, 2026 and December 31, 2025, 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:

Restricted cash of $2,428 at June 30, 2026 consists of funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire various rights-of-way, surface acreage and other oil and gas royalty interests from a third party.

Restricted cash of $12,685 at December 31, 2025 consists of funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire the natural gas upstream and associated midstream business of Apex Energy II, LLC, as well as funds that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire various rights-of-way, surface acreage and other oil and gas royalty interests from a third party. See Note 4 – Acquisitions and Dispositions for more information.

Trade Accounts Receivable and Allowance for Credit Losses:

As of June 30, 2026 and December 31, 2025, Accounts Receivable - Trade were $163,835 and $264,658, respectively, and Other Receivables were $25,771 and $61,249, 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.

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


	June 30,
	2026		2025
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	$	1,037	$	1,233

Provision for Expected Credit Losses	12		(39)

Allowance for Credit Losses - Other Receivables, End of Period	$	1,049	$	1,194

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 that were issuable upon conversion of CNX's outstanding 2.25% convertible senior notes in May 2026 (the "Convertible Notes") (See Note 10 – Long-Term Debt). The number of additional shares was calculated by assuming that outstanding stock options were exercised, that outstanding restricted stock units and performance share units were released, that the shares that were issuable from the conversion of the Convertible Notes were issued 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 June 30,		For the Six Months Ended June 30,
	2026	2025	2026	2025

Anti-Dilutive Restricted Stock Units	264,134	272,463	31,919	263,930
Anti-Dilutive Performance Share Units	119,313	—	119,313	—

	383,447	272,463	151,232	263,930

On January 28, 2026, in accordance with the indenture governing the Convertible Notes, CNX issued a notice of settlement method election for all of the outstanding Convertible Notes providing that CNX would settle any of the Convertible Notes outstanding by issuing shares of the Company's common stock, together, if applicable, with cash in lieu of fractional shares, as provided for in the indenture. Subsequently, on May 1, 2026, the Convertible Notes matured for a net settlement of 12,636,743 net shares delivered to the noteholders.

The table below sets forth the share-based awards that have been exercised or released:


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2026	2025	2026	2025
Options	130,155	15,999	279,430	98,006
Restricted Stock Units	63,118	98,695	659,417	731,083
Performance Share Units	—	—	455,069	483,570
	193,273	114,694	1,393,916	1,312,659

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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2026		2025		2026		2025
Net Income	$	202,943	$	432,521	$	551,090	$	234,806




Basic Earnings Available to Shareholders	$	202,943	$	432,521	$	551,090	$	234,806

Effect of Dilutive Securities:
Add Back Interest on Convertible Notes (Net of Tax)	$	324	$	1,396	$	1,295	$	2,791
Diluted Earnings Available to Shareholders	$	203,267	$	433,917	$	552,385	$	237,597

Weighted-Average Shares of Common Stock Outstanding	148,155,232		143,429,950		145,195,159		145,592,034
Effect of Diluted Shares:
Options	255,770		569,960		319,952		578,015
Restricted Stock Units	851,433		1,148,725		860,336		1,127,351
Performance Share Units	486,590		846,092		497,307		851,337
Convertible Notes	4,212,248		25,751,869		8,424,495		25,751,869
Weighted-Average Diluted Shares of Common Stock Outstanding	153,961,273		171,746,596		155,297,249		173,900,606

Earnings per Share:


Basic	$	1.37	$	3.02	$	3.80	$	1.61



Diluted	$	1.32	$	2.53	$	3.56	$	1.37

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, NGLs 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, NGLs 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, NGLs and oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

Included in Other Revenue and Operating Income in the Consolidated Statements of Income and in the below table are revenues generated from natural gas gathering services provided to third parties and sales of environmental attributes. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric based fees are based on actual volumes gathered. The Company generally considers the interruptible gathering of each unit (MMBtu) of natural gas as a separate performance obligation. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered. All sales of environmental attributes (which includes items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances) are under short-term contracts, and revenue is recognized when the environmental attribute is transferred to a third party.

Disaggregation of Revenue

The following table is a disaggregation of revenue by major source:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2026		2025		2026		2025
Revenue from Contracts with Customers:
Natural Gas Revenue	$	326,878	$	443,564	$	985,488	$	938,756
NGL Revenue	57,772		39,820		117,832		93,821
Oil/Condensate Revenue	4,785		1,645		8,158		3,546
Total Natural Gas, NGLs and Oil Revenue	389,435		485,029		1,111,478		1,036,123

Purchased Gas Revenue	12,456		10,408		25,143		21,959

Other Sources of Revenue and Other Operating Income:
Gain (Loss) on Commodity Derivative Instruments	176,336		421,121		180,317		(107,099)
Other Revenue and Operating Income	40,257		45,864		88,200		93,828
Total Revenue and Other Operating Income	$	618,484	$	962,422	$	1,405,138	$	1,044,811

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, NGLs and oil and purchased gas revenue is short-term in nature with a contract term of one year or less. For those contracts, CNX has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For revenue associated with contract terms greater than one year, a significant portion of the consideration in those contracts is variable in nature and the Company allocates the variable consideration in its contract entirely to each specific performance obligation to which it relates. Therefore, any remaining variable consideration in the transaction price is allocated entirely to wholly unsatisfied performance obligations. As such, the Company has not disclosed the value of unsatisfied performance obligations pursuant to the practical expedient.

For natural gas, NGLs 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 $10,712 as of June 30, 2026. The Company expects to recognize net revenue of $8,191 in the next 12 months and $1,982 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, NGLs 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 six months ended June 30, 2026 and 2025, 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.

In connection with the Apex Transaction, CNX maintained an escrow account pursuant to the purchase agreement to settle certain post‑closing adjustments, which was to be released on the one‑year anniversary of closing. During the six months ended June 30, 2026, approximately $10,255 previously classified as restricted cash was reflected in Apex Acquisitions (Net of Cash Acquired) in the Company’s Consolidated Statements of Cash Flows.

During the six months ended June 30, 2026, CNX made the first of three annual payments of $16,500 pursuant to an agreement that provides the Company with the right to acquire Utica Shale oil and gas interests underlying the legacy Apex Energy footprint, which was reflected in capital expenditures in the Company's Consolidated Statements of Cash Flows.

During the six months ended June 30, 2025, CNX acquired various rights-of-way, surface acreage and other oil and gas royalty interests from a third party for total cash consideration of $24,250 and subject to certain post-closing adjustments.

Additionally, Loss (Gain) on Asset Sales and Abandonments, net in the Consolidated Statements of Income for the three and six months ended June 30, 2026 and 2025 and Proceeds from Asset Sales in the Consolidated Statements of Cash Flows for the six months ended June 30, 2026 and 2025 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.

NOTE 5—INCOME TAXES:

The effective tax rates for the three and six months ended June 30, 2026 were 14.3% and 17.2%, respectively. The effective tax rates for the three and six months ended June 30, 2025 were 26.1% and 24.9%, respectively. The effective tax rate for the three and six months ended June 30, 2026 and 2025 differs from the U.S. federal statutory rate of 21% primarily due to the impact of equity compensation, federal tax credits, and state taxes. Specifically related to certain monetized federal tax credits, the Company recorded an increase in income tax benefit of $11,040 during the six months ended June 30, 2026. On July 1, 2026, the Company monetized these credits for approximately $30,000.

The total amount of uncertain tax positions at June 30, 2026 and December 31, 2025 was $131,334 and $129,034, respectively. If these uncertain tax positions were recognized, approximately $131,334 and $129,034 would affect CNX's effective tax rate at June 30, 2026 and December 31, 2025, respectively. In 2026, CNX recognized an increase in unrecognized tax benefits of $2,300 for tax benefits resulting from tax positions anticipated to be claimed on our 2026 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 June 30, 2026 and December 31, 2025, 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 2022.

NOTE 6—PROPERTY, PLANT AND EQUIPMENT:


	June 30, 2026		December 31, 2025
Intangible Drilling Cost	$	6,942,071	$	6,755,849
Gas Gathering Equipment	2,799,759		2,771,747
Gas Wells and Related Equipment	1,903,634		1,833,856
Proved Gas Properties	1,461,686		1,457,919
Unproved Gas Properties	780,460		747,528
Surface Land and Other Equipment	179,595		179,676
Other	313,783		310,649
Total Property, Plant and Equipment	14,380,988		14,057,224
Less: Accumulated Depreciation, Depletion and Amortization	6,442,893		6,193,871

Total Property, Plant and Equipment - Net	$	7,938,095	$	7,863,353

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 June 30, 2026 and December 31, 2025.

Other Intangible Assets:

The carrying amount and accumulated amortization of other intangible assets consist of the following:


	June 30, 2026		December 31, 2025
Other Intangible Assets:
Gross Amortizable Asset - Customer Relationships	$	109,752	$	109,752
Less: Accumulated Amortization - Customer Relationships	55,695		52,419
Total Other Intangible Assets, net	$	54,057	$	57,333

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 six months ended June 30, 2026 and 2025 was $1,638 and $3,276, 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. On May 13, 2026, the CNX Credit Facility borrowing base and elected commitments remained unchanged at $2,400,000 and $1,400,000, respectively, as part of the semi-annual redetermination.

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 1.75% to 2.75%.

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 June 30, 2026.

At June 30, 2026, the CNX Credit Facility had $155,650 of borrowings outstanding, with a weighted average interest rate of 6.15% and $27,997 of letters of credit outstanding, leaving $1,216,353 of unused capacity. At December 31, 2025, the CNX Credit Facility had $200,000 of borrowings outstanding, with a weighted average interest rate of 5.69% and $27,997 of letters of credit outstanding, leaving $1,172,003 of unused capacity.

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 SOFR rate plus a margin ranging from 1.75% to 3.00%.

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 June 30, 2026.

At June 30, 2026, the CNXM Credit Facility had $90,000 of borrowings outstanding, with a weighted average interest rate of 5.38% and no letters of credit outstanding, leaving $510,000 of unused capacity. At December 31, 2025, the CNXM Credit Facility had $32,750 of borrowings outstanding, with a weighted average interest rate of 5.58%, and no letters of credit outstanding, leaving $567,250 of unused capacity.

NOTE 9—OTHER ACCRUED LIABILITIES:


	June 30, 2026		December 31, 2025
Royalties	$	107,071	$	121,078
Accrued Interest	46,222		50,871
Transportation Charges	17,858		21,706
Current Portion Settlement - See Note 11	13,776		23,216
Deferred Revenue	12,014		14,589
Accrued Payroll & Benefits	7,398		6,884
Short-Term Incentive Compensation	6,265		22,658
Accrued Other Taxes	2,389		8,084
Purchased Gas Payable	312		554
Other	14,280		32,614
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations	21,075		21,075
Salary Retirement	2,648		2,647
Total Other Accrued Liabilities	$	251,308	$	325,976

NOTE 10—LONG-TERM DEBT:


	June 30, 2026		December 31, 2025
Senior Notes due March 2032 at 7.25% (Principal of $600,000 less Unamortized Discount of $4,742 and $5,160, respectively)	$	595,258	$	594,840
Senior Notes due March 2034 at 5.875%, Issued at Par Value	500,000		—
Senior Notes due January 2031 at 7.375% (Principal of $500,000 less Unamortized Discount of $3,423 and $3,800, respectively)	496,577		496,200
CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $2,212 and $2,500, respectively)*	397,788		397,500
CNX Revolving Credit Facility	155,650		200,000
CNX Midstream Partners LP Revolving Credit Facility*	90,000		32,750
Senior Notes due January 2029 at 6.00%, Issued at Par Value	—		500,000
Convertible Senior Notes due May 2026 at 2.25% (Principal of $208,556 less Unamortized Discount and Issuance Costs $425)	—		208,131
Less: Unamortized Debt Issuance Costs	11,528		8,062
	2,223,745		2,421,359
Less: Current Portion	—		208,095
Long-Term Debt	$	2,223,745	$	2,213,264

*CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or the CNXM Credit Facility.

During the six months ended June 30, 2026, CNX issued $500,000 aggregate principal amount of 5.875% Senior Notes due March 2034 (the "New Notes") at 100.0% of par. The New Notes, along with the related guarantees, were issued pursuant to an indenture, dated February 26, 2026, among the Company, the subsidiary guarantors party thereto and UMB Bank, N.A., as trustee. The New Notes are guaranteed by all of CNX's restricted subsidiaries that guarantee the CNX Credit Facility (see Note 8 – Revolving Credit Facilities). The New Notes accrue interest from February 26, 2026 at a rate of 5.875% per year. Interest on the New Notes is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2026.

During the six months ended June 30, 2026, CNX repurchased all $500,000 aggregate principal amount of its outstanding 6.00% Senior Notes due January 2029. As part of the transaction, a loss of $12,009 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income during the six months ended June 30, 2026.

In 2020, CNX issued $345,000 aggregate principal amount of the Convertible Notes (the “Convertible Notes”) in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933 (the “Securities Act”), 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 were senior, unsecured obligations of the Company. The Convertible Notes bore 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 were guaranteed by most of CNX's subsidiaries excluding CNXM (or its subsidiaries or general partner). In connection with the offering of the Convertible Notes, the Company entered into privately negotiated Capped Call Transactions (the "Capped Calls") with certain counterparties. The Capped Calls had an initial strike price of $12.84 per share, subject to certain adjustments, which correspond to the initial conversion price of the Convertible Notes.

On December 15, 2025, CNX entered into a privately negotiated exchange agreement (the “exchange agreement”) with a limited number of holders of the Convertible Notes to exchange approximately $122,098 principal amount of Convertible Notes conversion right exercises by issuing an aggregate 9,509,188 shares of CNX common stock to the converting holders representing an average conversion price of $12.84 per share. The shares of CNX common stock issued in the transaction were issued pursuant to the exemption from the registration requirements of the Securities Act, afforded by Section 4(a)(2) of the Securities Act in transactions not involving any public offering. The exchange agreement also included additional cash consideration of approximately $855, including accrued interest. As part of the transaction, a loss of $842 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income during the year ended December 31, 2025.

On May 1, 2026, the Convertible Notes matured. The remaining outstanding aggregate principal amount of $208,553 was fully settled through the issuance of 12,636,743 net shares of common stock to the noteholders pursuant to the physical settlement terms of the Indenture. No cash was exchanged at maturity. Concurrently, the privately negotiated Capped Calls entered into in connection with the initial issuance of the Convertible Notes expired. Pursuant to the net share settlement terms of the Capped Calls, the option counterparties delivered a total of 3,605,684 shares of common stock to CNX. Upon receipt from the counterparties, the shares were immediately and subsequently retired by CNX.

During the six months ended June 30, 2025, CNX issued $200,000 aggregate principal amount of additional 7.25% Senior Notes due March 2032 (the "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 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 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 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.

The net carrying amount of the liability and equity components of the Convertible Notes were as follows:


	June 30, 2026		December 31, 2025
Liability Component:
Principal	$	—	$	208,556

Unamortized Issuance Costs	—		(425)
Net Carrying Amount	$	—	$	208,131

Fair Value	$	—	$	596,798
Fair Value Hierarchy	—		Level 2

During the six months ended June 30, 2026, all outstanding Convertible Notes matured. Accordingly, there was no carrying value or fair value of Convertible Notes as of June 30, 2026.

Interest expense related to the Convertible Notes is as follows:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2026		2025		2026		2025
Contractual Interest Expense	$	391	$	1,860	$	1,564	$	3,720

Amortization of Issuance Costs	107		494		425		985
Total Interest Expense	$	498	$	2,354	$	1,989	$	4,705

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 Core Natural Resources, Inc., the successor by merger to CONSOL Energy (“Core”) to Murray Energy of the following possible last signatory operators: Consolidation Coal Company, McElroy Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Keystone Coal Mining Corp., and Eighty-Four Mining Company (the "Sold Subsidiaries"). On May 2, 2020, the Trustees of the UMWA 1992 Benefit Plan sued CNX and Core in federal court contending that the Sold Subsidiaries were last signatory operators and that CNX and Core are related persons to the Sold Subsidiaries and, as such, CNX and Core are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The 1992 Benefit Plan seeks, among other relief, a declaration that CNX and Core are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 plan; that CNX and Core are liable to post the security required by Section 9712; and, that CNX and Core are liable to pay per beneficiary premiums until the eligible retirees are enrolled in a Section 9711 plan, and other fees, costs and disbursements under the Coal Act. On March 29, 2022, the Court denied the Defendants’ Motions to Dismiss CNX and Core are now defending this action on the merits. Further, under the Separation and Distribution Agreement ("SDA") that was entered into at the time CNX spun-out its coal business in 2017, Core agreed to indemnify CNX for all coal-related liabilities, including this lawsuit. With respect to this matter, although a loss is possible, it is not probable, and accordingly no accrual has been recognized.

On July 22, 2021, CNX received a letter from the UMWA 1974 Pension Plan ("1974 Plan") requesting information related to the facts and circumstances surrounding the 2013 sale of certain of its coal subsidiaries to Murray Energy. The letter indicated that litigation related to potential withdrawal liabilities from the plan created by the 2019 bankruptcy of Murray Energy was reasonably foreseeable and at that time, no liability had been assessed. The 1974 Plan never issued an assessment to CNX. Following a period of discovery, CNX and the 1974 Plan mediated the claim in February 2024. By agreement dated March 4, 2024, CNX settled the 1974 Plan claim for $75,000 which is payable over five-years with the initial payment made at the end of March 2024. Under the SDA, Core became successor-in-interest to the “Coal Business” and accepted and agreed to assume and be responsible for all “Coal Liabilities.” The assumed “Coal Liabilities” are defined broadly in the SDA and specifically include claims, like the 1974 Plan claim, arising under ERISA; involving contributions or other obligations pursuant to any Benefits Plan; and any withdraw liabilities. Core also unequivocally agreed to defend and indemnify CNX for all liabilities relating to, arising out of or resulting from any “Coal Liabilities.” CNX timely tendered the 1974 Plan claim to Core for defense and indemnity in July 2021, which it denied. CNX continued to demand indemnity from Core including prior to, during and after the March 2024 mediation. After Core repudiated its contractual obligations to CNX, and after having timely fulfilled all SDA prerequisites for bringing the action, on March 7, 2024, CNX sued Core for breach of contract seeking an order requiring Core to indemnify CNX for the 1974 Plan claim settlement. On November 8, 2024, the court granted CNX’s Motion for Partial Summary Judgment (the “Summary Judgment Grant”), finding that Core is obligated to indemnify CNX for its settlement of the 1974 Plan claim and to reimburse CNX for its attorney’s fees and costs to defend and resolve the underlying 1974 Plan claim. As of June 30, 2026 and December 31, 2025, Core has reimbursed CNX for all settlement payments made to the 1974 Plan, plus interest. The present value of the $75,000 settlement, less payments made, is recognized in Other Liabilities in the Consolidated Balance Sheets as of June 30, 2026, 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 June 30, 2026, 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 June 30, 2026, 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.

Certain guarantees and indemnifications do not have a stated expiration date and therefore are presented in the ‘Indefinite’ column. These amounts represent the maximum potential future payments under such arrangements and are not indicative of the expected timing of any payments.


	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years		Indefinite
Letters of Credit:
Firm Transportation	$	25,077	$	25,077	$	—	$	—	$	—	$	—

Other	2,920		2,920		—		—		—		—
Total Letters of Credit	27,997		27,997		—		—		—		—
Surety Bonds:
Employee-Related	2,250		2,250		—		—		—		—
Environmental	46,988		46,988		—		—		—		—
Firm Transportation	129,336		129,336		—		—		—		—
Financial Guarantees	90,162		90,162		—		—		—		—
Other	12,920		12,817		103		—		—		—
Total Surety Bonds	281,656		281,553		103		—		—		—
Other Guarantees	29,956		10,892		6,724		840		—		11,500
Total Commitments	$	339,609	$	320,442	$	6,827	$	840	$	—	$	11,500

Excluded from the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business in November 2017. Although Core has agreed to indemnify CNX to the extent that CNX would be called upon to pay any of these liabilities, there is no assurance that Core will satisfy its obligations to indemnify CNX in the event that CNX is so called upon (See "Item 1A. Risk Factors" in the 2025 Form 10-K for additional information).

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 June 30, 2026, the purchase obligations for each of the next five years and beyond are as follows:


Obligations Due	Amount
Less than 1 year	$	257,256
1 - 3 years	408,488
3 - 5 years	240,667
More than 5 years	406,213
Total Purchase Obligations	$	1,312,624

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. There were no interest rate swap agreements entered into as of June 30, 2026.

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:


	June 30,	December 31,	Forecasted to
	2026	2025	Settle Through
Natural Gas Commodity Swaps (Bcf)	778.7	929.8	2028
Natural Gas Basis Swaps (Bcf)	508.6	585.5	2029
NGL Commodity Swaps (Mbbls)	1,068.6	180.0	2027

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


	June 30,		December 31,
	2026		2025
Current Assets:
Commodity Derivative Instruments:
Natural Gas Commodity Swaps	$	198,760	$	74,064
NGL Commodity Swaps	2,998		1,730
Natural Gas Basis Swaps	18,954		30,274

Total Current Assets	$	220,712	$	106,068

Other Non-Current Assets:
Commodity Derivative Instruments:
Natural Gas Commodity Swaps	$	146,448	$	117,524
Natural Gas Basis Swaps	19,095		16,872

Total Other Non-Current Assets	$	165,543	$	134,396

Current Liabilities:
Commodity Derivative Instruments:
Natural Gas Commodity Swaps	$	118,714	$	323,169
NGL Commodity Swaps	544		—
Natural Gas Basis Swaps	55,624		54,776

Total Current Liabilities	$	174,882	$	377,945

Non-Current Liabilities:
Commodity Derivative Instruments:
Natural Gas Commodity Swaps	$	46,296	$	101,387
Natural Gas Basis Swaps	32,632		56,981

Total Non-Current Liabilities	$	78,928	$	158,368

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


	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2026		2025		2026			2025
Realized Gain (Loss) on Commodity Derivative Instruments:
Natural Gas Commodity Swaps	$	49,201	$	(46,455)	$	(147,492)		$	(129,932)
Natural Gas Basis Swaps	(2,931)		10,888		(28,581)			(13,958)
NGL Commodity Swaps	(832)		163		(89)			(1,201)
Total Realized Gain (Loss) on Commodity Derivative Instruments	45,438		(35,404)		(176,162)		*	(145,091)		**

Unrealized Gain (Loss) on Commodity Derivative Instruments:
Natural Gas Commodity Swaps	138,527		424,019		348,133			(80,124)
Natural Gas Basis Swaps	(12,225)		29,971		7,312			115,965
NGL Commodity Swaps	4,596		2,535		1,034			2,151
Total Unrealized Gain on Commodity Derivative Instruments	130,898		456,525		356,479			37,992

Gain (Loss) on Commodity Derivative Instruments:
Natural Gas Commodity Swaps	187,728		377,564		200,641			(210,056)
Natural Gas Basis Swaps	(15,156)		40,859		(21,269)			102,007
NGL Commodity Swaps	3,764		2,698		945			950
Total Gain (Loss) on Commodity Derivative Instruments	$	176,336	$	421,121	$	180,317		$	(107,099)

*Includes $16,462 of commodity derivatives that have been settled but not received and $3,035 settled but not paid at June 30, 2026, and excludes $58,387 of commodity derivatives that were settled but not paid at December 31, 2025.

**Includes $7,961 of commodity derivatives that have been settled but not received and $1,573 that were settled but not paid at June 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.

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.

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 June 30, 2026							Fair Value Measurements at December 31, 2025
Description	Level 1		Level 2			Level 3		Level 1		Level 2			Level 3
Commodity Derivatives	$	—	$	132,445	*	$	—	$	—	$	(295,849)	**	$	—

*Includes $16,462 of commodity derivatives that have been settled but not received and $3,035 settled but not paid at June 30, 2026.

**Includes $58,387 of commodity derivatives that have been settled but not paid at December 31, 2025.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:


	June 30, 2026				December 31, 2025
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and Cash Equivalents	$	6,162	$	6,162	$	779	$	779
Restricted Cash*	$	2,428	$	2,428	$	12,685	$	12,685

Long-Term Debt (Excluding Debt Issuance Costs)	$	2,235,273	$	2,226,737	$	2,429,421	$	2,850,144

*The June 30, 2026 and December 31, 2025 restricted cash balance are located in current assets in the Consolidated Balance Sheets.

Cash and cash equivalents and restricted cash represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that is not actively traded is valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

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.

CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers, and the Company has two reportable segments that conduct those operations: Shale and Coalbed Methane. The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, sales of environmental attributes, as well as various other expenses that are managed outside the reportable segments as discussed below.

The CODM evaluates the performance of the Company’s reportable segments using Income (Loss) Before Income Tax to assess segment performance primarily by comparing it across segments for the current period as well as for prior periods. Income (Loss) Before Income Tax for each segment is based on revenue less identifiable operating and non-operating expenses. Certain expenses are managed outside the reportable segments and therefore are not allocated. These expenses include, but are not limited to, interest expense, other operating expense, and other corporate expenses such as selling, general and administrative costs.

Reportable segment results for the three months ended June 30, 2026 are:


	For the Three Months Ended June 30, 2026
	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	360,562	$	28,633	$	240	$	389,435	(A)
Gain on Commodity Derivative Instruments	42,388		3,037		130,911		176,336
Purchased Gas Revenue	—		—		12,456		12,456
Other Revenue and Operating Income	15,282		—		24,975		40,257		(B)
Total Revenue and Other Operating Income	$	418,232	$	31,670	$	168,582	$	618,484
Lease Operating Expense	14,564		6,290		408		21,262
Transportation, Gathering and Compression	86,683		15,199		1,341		103,223
Production, Ad Valorem, and Other Fees	4,952		1,584		10		6,546
Depreciation, Depletion and Amortization	114,559		14,874		6,799		136,232
Interest Expense	—		—		39,023		39,023
Other Segment Items	—		—		75,256		75,256
Total Costs and Expenses	$	220,758	$	37,947	$	122,837	$	381,542
Income (Loss) Before Income Tax	$	197,474	$	(6,277)	$	45,745	$	236,942
(A) Included in Natural Gas, NGLs and Oil Revenue are sales of $57,547 to NRG Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(B) Includes midstream revenue of $15,282 and equity in loss of unconsolidated affiliates of $645 for Shale and Other, respectively. Other also includes sales of environmental attributes of $14,436.


	For the Three Months Ended June 30, 2026
Other Segment Disclosures	Shale		Coalbed Methane		Other		Consolidated
Segment Assets	$	7,291,994	$	885,981	$	958,924	$	9,136,899	(C)
Capital Expenditures	$	134,119	$	6,286	$	1,595	$	142,000
(C) Includes investments in unconsolidated equity affiliates of $5,166.

Reportable segment results for the three months ended June 30, 2025 are:


	For the Three Months Ended June 30, 2025
	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	451,618	$	33,180	$	231	$	485,029	(D)
(Loss) Gain on Commodity Derivative Instruments	(33,256)		(2,133)		456,510		421,121
Purchased Gas Revenue	—		—		10,408		10,408
Other Revenue and Operating Income	17,432		—		28,432		45,864		(E)
Total Revenue and Other Operating Income	$	435,794	$	31,047	$	495,581	$	962,422
Lease Operating Expense	20,214		6,016		26		26,256
Transportation, Gathering and Compression	80,049		16,327		577		96,953
Production, Ad Valorem, and Other Fees	8,209		1,452		7		9,668
Depreciation, Depletion and Amortization	131,268		14,806		6,521		152,595
Interest Expense	—		—		44,041		44,041
Other Segment Items	—		—		47,268		47,268
Total Costs and Expenses	$	239,740	$	38,601	$	98,440	$	376,781
Income (Loss) Before Income Tax	$	196,054	$	(7,554)	$	397,141	$	585,641
(D) Included in Natural Gas, NGLs and Oil Revenue are sales of $59,948 to Citadel Energy Marketing LLC, $58,792 to NRG Business Marketing LLC, and $56,365 to DTE Energy Trading Inc., each of which comprises over 10% of revenue from contracts with external customers for the period.
(E) Includes midstream revenue of $17,432 and equity in earnings of unconsolidated affiliates of $605 for Shale and Other, respectively. Other also includes sales of environmental attributes of $20,400.


	For the Three Months Ended June 30, 2025
Other Segment Disclosures	Shale		Coalbed Methane		Other		Consolidated
Segment Assets	$	7,143,060	$	923,635	$	921,172	$	8,987,867	(F)
Capital Expenditures	$	85,556	$	26,505	$	1,504	$	113,565
(F) Includes investments in unconsolidated equity affiliates of $19,178.

Reportable segment results for the six months ended June 30, 2026 are:


	For the Six Months Ended June 30, 2026
	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	1,023,462	$	87,394	$	622	$	1,111,478	(G)
(Loss) Gain on Commodity Derivative Instruments	(165,952)		(10,160)		356,429		180,317
Purchased Gas Revenue	—		—		25,143		25,143
Other Revenue and Operating Income	31,651		—		56,549		88,200		(H)
Total Revenue and Other Operating Income	$	889,161	$	77,234	$	438,743	$	1,405,138
Lease Operating Expense	30,106		12,316		610		43,032
Transportation, Gathering and Compression	173,459		31,194		972		205,625
Production, Ad Valorem, and Other Fees	11,516		3,796		23		15,335
Depreciation, Depletion and Amortization	227,523		29,290		14,032		270,845
Interest Expense	—		—		79,493		79,493
Other Segment Items	—		—		125,461		125,461
Total Costs and Expenses	$	442,604	$	76,596	$	220,591	$	739,791
Income Before Income Tax	$	446,557	$	638	$	218,152	$	665,347
(G) Included in Natural Gas, NGLs and Oil Revenue are sales of $213,561 to NRG Business Marketing LLC and $118,454 to DTE Energy Trading, Inc., each of which comprises over 10% of revenue from contracts with external customers for the period.
(H) Includes midstream revenue of $31,651 and equity in loss of unconsolidated affiliates of $1,108 for Shale and Other, respectively. Other also includes sales of environmental attributes of $29,376.


	For the Six Months Ended June 30, 2026
Other Segment Disclosures	Shale		Coalbed Methane		Other		Consolidated
Segment Assets	$	7,291,994	$	885,981	$	958,924	$	9,136,899	(I)
Capital Expenditures	$	297,539	$	11,686	$	2,681	$	311,906
(I) Includes investments in unconsolidated equity affiliates of $5,166.

Reportable segment results for the six months ended June 30, 2025 are:


	For the Six Months Ended June 30, 2025
	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	959,173	$	76,458	$	492	$	1,036,123	(J)
(Loss) Gain on Commodity Derivative Instruments	(135,956)		(9,086)		37,943		(107,099)
Purchased Gas Revenue	—		—		21,959		21,959
Other Revenue and Operating Income	34,270		—		59,558		93,828		(K)
Total Revenue and Other Operating Income	$	857,487	$	67,372	$	119,952	$	1,044,811
Lease Operating Expense	37,433		11,985		170		49,588
Transportation, Gathering and Compression	158,099		33,110		903		192,112
Production, Ad Valorem, and Other Fees	13,709		3,218		14		16,941
Depreciation, Depletion and Amortization	237,628		28,618		13,411		279,657
Interest Expense	—		—		85,652		85,652
Other Segment Items	—		—		108,019		108,019
Total Costs and Expenses	$	446,869	$	76,931	$	208,169	$	731,969
Income (Loss) Before Income Tax	$	410,618	$	(9,559)	$	(88,217)	$	312,842
(J) Included in Natural Gas, NGLs and Oil Revenue are sales of $124,748 to Citadel Energy Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(K) Includes midstream revenue of $34,270 and equity in earnings of unconsolidated affiliates of $548 for Shale and Other, respectively. Other also includes sales of environmental attributes of $43,285.


	For the Six Months Ended June 30, 2025
Other Segment Disclosures	Shale		Coalbed Methane		Other		Consolidated
Segment Assets	$	7,143,060	$	923,635	$	921,172	$	8,987,867	(L)
Capital Expenditures	$	213,235	$	29,248	$	2,547	$	245,030
(L) Includes investments in unconsolidated equity affiliates of $19,178.

Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Operating Income:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2026		2025		2026		2025
Total Segment Revenue from Contracts with External Customers	$	417,173	$	512,869	$	1,168,272	$	1,092,352
Gain (Loss) on Commodity Derivative Instruments	176,336		421,121		180,317		(107,099)
Other Operating Income	24,975		28,432		56,549		59,558
Total Consolidated Revenue and Other Operating Income	$	618,484	$	962,422	$	1,405,138	$	1,044,811

NOTE 15—STOCK REPURCHASE:

The Company’s stock repurchase program was initially announced on September 5, 2017, pursuant to authorization from the Company’s Board of Directors. The Board has periodically increased the authorized dollar amount under the program since its inception. On January 29, 2026, the Company announced that its Board of Directors approved a $2,000,000 increase to the Company's existing stock repurchase program, increasing total authorized repurchases to $4,900,000. As of June 30, 2026, $2,171,897 remained available for repurchases under the program and it is not subject to a termination or expiration date. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans.

During the six months ended June 30, 2026, 7,181,455 shares were repurchased and retired at an average price of $35.66 per share for a total cost of $252,541. During the six months ended June 30, 2025, 7,844,436 shares were repurchased and retired at an average price of $30.51 per share for a total cost of $241,600. 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 June 30, 2026 and December 31, 2025, CNX purchased goods and services related to capital projects in the amount of $42,001 and $59,814, respectively, which are included in accounts payable.

The following table shows cash paid:


	For the Six Months Ended June 30,
	2026		2025
Interest	$	79,365	$	74,290
Income Taxes	$	5,849	$	4,850

NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:

In November 2024, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818). The standard establishes guidance for the recognition, measurement, presentation and disclosure of environmental credits and

environmental credit obligations. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2027, including interim reporting periods within those annual periods. Early adoption is permitted. The Company is evaluating the impact that adoption of this ASU will have on its consolidated financial statements and related disclosures.

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 the 2025 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 heightened geopolitical developments, including in the Middle East, uncertainties in global financial markets, and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, all of which have contributed to increased volatility in 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 differ materially from those of prior periods. The results presented in this Form 10-Q are not necessarily indicative of future operating results.

Natural Gas, NGLs 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 third quarter of 2026 is 116.0 Bcf. CNX's annual gas hedge position is shown in the table below:


	2026	2027
Volumes Hedged (Bcf), as of 7/8/26	460.4(1)	402.4

1Includes actual settlements of 207.9 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.

Results of Operations - Three Months Ended June 30, 2026 Compared with Three Months Ended June 30, 2025

Net Income

CNX reported net income of $203 million, or earnings per diluted share of $1.32, for the three months ended June 30, 2026, compared to net income of $433 million, or earnings per diluted share of $2.53, for the three months ended June 30, 2025.

Included in the earnings for the three months ended June 30, 2026 was an unrealized gain on commodity derivative instruments of $131 million and a net loss on asset sales and abandonments of $1 million. Included in the earnings for the three months ended June 30, 2025 was an unrealized gain on commodity derivative instruments of $456 million and a net gain on asset sales and abandonments of $18 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 loss (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, NGLs 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, NGLs 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, NGLs 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, NGLs and Oil, including cash settlements, Natural Gas, NGLs and Oil Production Costs and Natural Gas, NGLs and Oil Production Margin (which is derived by subtracting Natural Gas, NGLs and Oil Production Costs from Sales of Natural Gas, NGLs 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 June 30,
(Dollars in millions)	2026		2025
Total Revenue and Other Operating Income	$	618	$	962
Deduct:
Purchased Gas Revenue	(12)		(10)
Unrealized Gain on Commodity Derivative Instruments	(131)		(456)
Other Revenue and Operating Income	(40)		(46)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	435	$	450

Total Operating Expense	$	340	$	346
Deduct:
Depreciation, Depletion and Amortization (DD&A) - Corporate	(5)		(4)
Exploration and Production Related Other Costs	(3)		(2)
Purchased Gas Costs	(12)		(9)


Selling, General and Administrative Costs	(34)		(29)
Other Operating Expense	(24)		(21)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	262	$	281

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.

Selected Natural Gas, NGLs and Oil Production Financial Data

The following table presents a summary of our total sales volumes, sales of natural gas, NGLs and oil including cash settlements, natural gas, NGLs and oil production costs and natural gas, NGLs 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 June 30,
	2026				2025				Variance
	in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			151.5				167.6				(16.1)

Natural Gas, NGLs and Oil Revenue	$	390	$	2.54	$	485	$	2.91	$	(95)	$	(0.37)
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement	45		0.33		(35)		(0.23)		80		0.56
Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure	435		2.87		450		2.68		(15)		0.19
Lease Operating Expense	21		0.14		26		0.16		(5)		(0.02)
Production, Ad Valorem, and Other Fees	7		0.05		10		0.05		(3)		—
Transportation, Gathering and Compression	103		0.68		97		0.58		6		0.10
Depreciation, Depletion and Amortization (DD&A)	131		0.86		148		0.88		(17)		(0.02)
Natural Gas, NGLs and Oil Production Costs, a Non-GAAP Financial Measure	262		1.73		281		1.67		(19)		0.06
Natural Gas, NGLs and Oil Production Margin, a Non-GAAP Financial Measure	$	173	$	1.14	$	169	$	1.01	$	4	$	0.13

*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 NGLs, condensate, and natural gas prices.

The 16.1 Bcfe decrease in sales volumes was primarily due to normal production declines and the timing of when new wells were turned-in-line.

Changes in the average costs per Mcfe were primarily related to the following items:

•Lease operating expense decreased on a per unit basis primarily due to lower water disposal costs as more water was reused in well completion activities rather than taken to disposal. The decrease was offset, in part, by lower total sales volumes during the period.

•Transportation, gathering and compression expense increased on a per unit basis primarily due to the overall decrease in total sales volumes as well as higher repairs and maintenance and processing costs due to production mix.

•Depreciation, depletion and amortization expense decreased on a per unit basis primarily due to a slightly lower annual depletion rate. The decrease was offset, in part, by lower total sales volumes during the period.

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 June 30,
in thousands (unless noted)	2026		2025		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	14,796		11,109		3,687		33.2	%
Sales Volume (Mbbls)	2,466		1,852		614		33.2	%
Gross Price ($/Bbl)	$	23.40	$	21.48	$	1.92	8.9	%
Gross NGL Revenue	$	57,772	$	39,820	$	17,952	45.1	%

Oil/Condensate:
Sales Volume (MMcfe)	389		188		201		106.9	%
Sales Volume (Mbbls)	65		31		34		109.7	%
Gross Price ($/Bbl)	$	73.74	$	52.44	$	21.30	40.6	%
Gross Oil/Condensate Revenue	$	4,784	$	1,645	$	3,139	190.8	%

NATURAL GAS
Sales Volume (MMcf)	136,268		156,311		(20,043)		(12.8)	%
Sales Price ($/Mcf)	$	2.40	$	2.84	$	(0.44)	(15.5)	%
Gross Natural Gas Revenue	$	326,878	$	443,564	$	(116,686)	(26.3)	%

Hedging Impact ($/Mcf)	$	0.33	$	(0.23)	$	0.56	(243.5)	%
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement	$	45,438	$	(35,404)	$	80,842	(228.3)	%

The decrease in Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 16.1 Bcfe decrease in total sales volumes and the $0.44 per Mcf decrease in natural gas sales price, when excluding the impact of hedging. The decreases were offset, in part, by the impact of the change in the gain (loss) on commodity derivative instruments - cash settlement related to the Company's hedging program, the 3.7 Bcfe increase in NGL sales volumes and the $1.92 per Bbl increase in NGL prices.

SEGMENT ANALYSIS for the three months ended June 30, 2026 compared to the three months ended June 30, 2025:


	For the Three Months Ended								Difference to Three Months Ended
	June 30, 2026								June 30, 2025
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total
Natural Gas, NGLs and Oil Revenue	$	361	$	29	$	—	$	390	$	(91)	$	(4)	$	—	$	(95)
Gain on Commodity Derivative Instruments	42		3		131		176		75		5		(325)		(245)
Purchased Gas Revenue	—		—		12		12		—		—		2		2
Other Revenue and Operating Income	15		—		25		40		(2)		—		(4)		(6)
Total Revenue and Other Operating Income	418		32		168		618		(18)		1		(327)		(344)
Lease Operating Expense	15		6		—		21		(5)		—		—		(5)
Production, Ad Valorem, and Other Fees	5		2		—		7		(4)		1		—		(3)
Transportation, Gathering and Compression	87		15		1		103		7		(2)		1		6
Depreciation, Depletion and Amortization	114		15		7		136		(17)		—		1		(16)

Exploration and Production Related Other Costs	—		—		3		3		—		—		1		1
Purchased Gas Costs	—		—		12		12		—		—		3		3
Selling, General and Administrative Costs	—		—		34		34		—		—		5		5
Other Operating Expense	—		—		24		24		—		—		3		3
Total Operating Expense	221		38		81		340		(19)		(1)		14		(6)
Other Expense	—		—		1		1		—		—		(3)		(3)
Loss on Asset Sales and Abandonments, net	—		—		1		1		—		—		19		19

Interest Expense	—		—		39		39		—		—		(5)		(5)
Total Other Expense	—		—		41		41		—		—		11		11
Total Costs and Expenses	221		38		122		381		(19)		(1)		25		5
Earnings (Loss) Before Income Tax	$	197	$	(6)	$	46	$	237	$	1	$	2	$	(352)	$	(349)

SHALE SEGMENT

The Shale segment had earnings before income tax of $197 million for the three months ended June 30, 2026 compared to earnings before income tax of $196 million for the three months ended June 30, 2025.


	For the Three Months Ended June 30,
	2026		2025		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	126.5		146.9		(20.4)		(13.9)	%
NGLs Sales Volumes (Bcfe)*	14.8		11.1		3.7		33.3	%
Oil/Condensate Sales Volumes (Bcfe)*	0.4		0.2		0.2		100.0	%
Total Shale Sales Volumes (Bcfe)*	141.7		158.2		(16.5)		(10.4)	%

Average Sales Price - Natural Gas (per Mcf)	$	2.36	$	2.79	$	(0.43)	(15.4)	%
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	0.34	$	(0.23)	$	0.57	247.8	%
Average Sales Price - NGLs (per Mcfe)*	$	3.90	$	3.58	$	0.32	8.9	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	12.27	$	8.75	$	3.52	40.2	%

Total Average Shale Sales Price (per Mcfe)	$	2.84	$	2.64	$	0.20	7.6	%
Average Shale Lease Operating Expenses (per Mcfe)	0.10		0.13		(0.03)		(23.1)	%
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)	0.03		0.05		(0.02)		(40.0)	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.61		0.51		0.10		19.6	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.81		0.82		(0.01)		(1.2)	%
Total Average Shale Production Costs (per Mcfe)	$	1.55	$	1.51	$	0.04	2.6	%
Total Average Shale Production Margin (per Mcfe)	$	1.29	$	1.13	$	0.16	14.2	%

* 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, NGLs, condensate, and natural gas prices.

The decrease in total Shale sales volumes was primarily due to normal production declines and the timing of when new wells were turned-in-line.

The Shale segment had natural gas, NGLs and oil/condensate revenue of $361 million for the three months ended June 30, 2026 compared to $452 million for the three months ended June 30, 2025. The $91 million decrease was primarily due to a 15.4% decrease in the average sales price for natural gas and a 10.4% decrease in total Shale sales volumes. The decrease was offset, in part, by a 247.8% change in the gain (loss) on commodity derivative instruments and an 8.9% increase in the average sales price of NGLs.

The Shale segment had a gain on commodity derivative instruments - cash settlements of $42 million for the three months ended June 30, 2026 compared to a loss of $33 million for the three months ended June 30, 2025. The notional amounts associated with these financial hedges represented approximately 108.3 Bcf of the Company's produced Shale gas sales volumes for the three months ended June 30, 2026 at an average gain of $0.40 per Mcf hedged. For the three months ended June 30, 2025, these financial hedges represented approximately 113.6 Bcf at an average loss of $0.29 per Mcf hedged.

The increase in total average Shale sales price was primarily due to a $0.32 per Mcfe increase in the average NGL sales price and a $0.57 per Mcf change in the gain (loss) on commodity derivative instruments - cash settlements. These increases were offset, in part, by a $0.43 per Mcf decrease in average natural gas sales price.

Total operating costs and expenses for the Shale segment were $221 million for the three months ended June 30, 2026 compared to $240 million for the three months ended June 30, 2025. The decrease in total dollars and increase in unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $15 million for the three months ended June 30, 2026 compared to $20 million for the three months ended June 30, 2025. The decrease in total dollars and unit costs were primarily due to lower water disposal costs as more water was reused in well completion activities rather than taken to disposal. The decrease was offset, in part, by lower total sales volumes during the period.

•Shale production, ad valorem and other fees were $5 million for the three months ended June 30, 2026 compared to $9 million for the three months ended June 30, 2025. The decrease in total dollars and unit costs were primarily due to decreased realized prices on natural gas. The decrease in unit costs was offset, in part, by lower total sales volumes during the period.

•Shale transportation, gathering and compression costs were $87 million for the three months ended June 30, 2026 compared to $80 million for the three months ended June 30, 2025. The increase in total dollars and unit costs were primarily due to higher repairs and maintenance expense and processing costs due to production mix. The increase in unit costs was also due to the lower total sales volumes during the period.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $114 million for the three months ended June 30, 2026 compared to $131 million for the three months ended June 30, 2025. These amounts included depletion on a units of production basis of $0.70 per Mcfe and $0.68 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 $15 million for the three months ended June 30, 2026 compared to $17 million for the three months ended June 30, 2025. The decrease in the period-to-period comparison was primarily due to a decrease in third-party gathering volumes.

COALBED METHANE (CBM) SEGMENT

The CBM segment had a loss before income tax of $6 million for the three months ended June 30, 2026 compared to a loss before income tax of $8 million for the three months ended June 30, 2025.


	For the Three Months Ended June 30,
	2026		2025		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	9.7		9.4		0.3		3.2	%

Average Sales Price - Gas (per Mcf)	$	2.94	$	3.55	$	(0.61)	(17.2)	%
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	0.31	$	(0.23)	$	0.54	234.8	%

Total Average CBM Sales Price (per Mcf)	$	3.25	$	3.32	$	(0.07)	(2.1)	%
Average CBM Lease Operating Expenses (per Mcf)	0.65		0.64		0.01		1.6	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.16		0.16		—		—	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	1.56		1.75		(0.19)		(10.9)	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.52		1.58		(0.06)		(3.8)	%
Total Average CBM Production Costs (per Mcf)	$	3.89	$	4.13	$	(0.24)	(5.8)	%
Total Average CBM Production Margin (per Mcf)	$	(0.64)	$	(0.81)	$	0.17	21.0	%

The CBM segment had natural gas revenue of $29 million for the three months ended June 30, 2026 compared to $33 million for the three months ended June 30, 2025. The $4 million decrease was primarily due to a 17.2% decrease in the average sales price for natural gas in the current period offset, in part, by a 3.2% increase in CBM sales volumes due to the timing of when new wells were turned-in-line.

The total average CBM sales price decreased $0.07 per Mcf primarily due to a $0.61 per Mcf decrease in average gas sales price offset, in part, by a $0.54 per Mcf change in the gain (loss) on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 7.5 Bcf of the Company's produced CBM sales volumes for the three months ended June 30, 2026 at an average gain of $0.41 per Mcf hedged. For the three months ended June 30, 2025, these financial hedges represented approximately 6.8 Bcf at an average loss of $0.32 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $38 million for the three months ended June 30, 2026 compared to $39 million for the three months ended June 30, 2025. The decrease in total dollars and unit costs for the CBM segment were due to the following items:

•CBM lease operating expenses were $6 million for both the three months ended June 30, 2026 and 2025. The increase in per unit costs was due to an increase in repairs and maintenance expense, offset, in part, by the increase in total CBM

volumes.

•CBM transportation, gathering and compression costs were $15 million for the three months ended June 30, 2026 compared to $17 million for the three months ended June 30, 2025. The decrease in total dollars was primarily due to a decrease in repairs and maintenance expense. The decrease in unit costs was due to the increase in total CBM volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $15 million for both the three months ended June 30, 2026 and 2025. These amounts included depletion on a units of production basis of $0.80 per Mcfe and $0.86 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 $46 million for the three months ended June 30, 2026 compared to earnings before income tax of $398 million for the three months ended June 30, 2025. The decrease in total dollars is discussed below.


	For the Three Months Ended June 30,
	2026	2025	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.1	—	0.1	100.0	%

Unrealized Gain on Commodity Derivative Instruments

For the three months ended June 30, 2026, the Other Segment recognized an unrealized gain on commodity derivative instruments of $131 million. For the three months ended June 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $456 million. The unrealized gain 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 $12 million for the three months ended June 30, 2026 compared to $10 million for the three months ended June 30, 2025. Purchased gas costs were $12 million for the three months ended June 30, 2026 compared to $9 million for the three months ended June 30, 2025. The period-to-period increase in purchased gas revenue was due to an increase in purchased gas sales volumes offset, in part, by a decrease in average sales price.


	For the Three Months Ended June 30,
	2026		2025		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	5.4		3.5		1.9		54.3	%
Average Sales Price (per Mcf)	$	2.30	$	2.97	$	(0.67)	(22.6)	%
Purchased Gas Average Cost (per Mcf)	$	2.26	$	2.68	$	(0.42)	(15.7)	%

Other Operating Income


	For the Three Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Sales of Environmental Attributes	$	14	$	20	$	(6)	(30.0)	%
Equity (Loss) Income from Affiliates	(1)		1		(2)		200.0	%
Water Income	5		4		1		25.0	%
Excess Firm Transportation Income	7		4		3		75.0	%

Total Other Operating Income	$	25	$	29	$	(4)	(13.8)	%

•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 amount of environmental attributes sold and the price received.

•Equity (loss) income from affiliates represents CNX's proportionate share of the net earnings or losses of our unconsolidated investments accounted for under the equity method. Equity income increases earnings, while equity losses reduce earnings.

•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.

•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.

Exploration and Production Related Other Costs


	For the Three Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change

Lease Expiration Costs	$	2	$	1	$	1	100.0	%
Land Rentals	1		1		—		—	%



Total Exploration and Production Related Other Costs	$	3	$	2	$	1	50.0	%

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 also includes non-cash long-term equity-based compensation expense.


	For the Three Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Salaries, Wages and Employee Benefits	$	7	$	4	$	3	75.0	%
Contributions and Advertising	1		—		1		100.0	%
Long-Term Equity-Based Compensation (Non-Cash)	6		5		1		20.0	%
Short-Term Incentive Compensation	3		3		—		—	%
Other	17		17		—		—	%
Total SG&A	$	34	$	29	$	5	17.2	%

•Salaries, wages and employee benefits increased in the period-to-period comparison primarily due to higher compensation costs during the current period.

Other Operating Expense


	For the Three Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Mineral Interest Adjustment	$	7	$	—	$	7	100.0	%
Environmental Attribute Fees	2		2		—		—	%

Insurance Expense	1		1		—		—	%

Unutilized Firm Transportation and Processing Fees	12		15		(3)		(20.0)	%


Other	2		4		(2)		(50.0)	%
Total Other Operating Expense	$	24	$	22	$	2	9.1	%

•During the three months ended June 30, 2026, the Company recorded a $7 million adjustment related to the resolution of ownership-related matter involving certain oil and gas rights. As a result of the resolution, the Company's unleased mineral interest and net revenue interest in the affected wells were recalculated, resulting in a reduction to its net revenue interest.

•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. The decrease in period-to-period comparison was primarily due to lower fees in the current period.

•Other decreased in the period-to-period comparison due to multiple one-time items, none of which were individually material.

Other Expense


	For the Three Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Other Income

Litigation Recoveries	$	—	$	1	$	(1)	(100.0)	%

Other	3		1		2		200.0	%
Total Other Income	$	3	$	2	$	1	50.0	%

Other Expense

Professional Services	$	1	$	3	$	(2)	(66.7)	%
Bank Fees	3		3		—		—	%


Total Other Expense	$	4	$	6	$	(2)	(33.3)	%

Total Other Expense	$	1	$	4	$	(3)	(75.0)	%

•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.

Loss (Gain) on Asset Sales and Abandonments, net

A net loss on asset sales and abandonments of $1 million was recognized in the three months ended June 30, 2026 compared to a net gain of $18 million in the three months ended June 30, 2025. The net loss (gain) recognized during both the three months ended June 30, 2026 and 2025 relates 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.

Interest Expense


	For the Three Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Total Interest Expense	$	39	$	44	$	(5)	(11.4)	%

The $5 million decrease in total interest expense was primarily due to lower borrowings on the CNX Credit Facility offset, in part, by higher 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 June 30,
(in millions)	2026			2025			Variance			Percent Change
Total Company Earnings Before Income Tax	$	237		$	586		$	(349)		(59.6)	%
Income Tax Expense	$	34		$	153		$	(119)		(77.8)	%
Effective Income Tax Rate	14.3		%	26.1		%	(11.8)		%

The effective income tax rates for the three months ended June 30, 2026 and 2025 were 14.3% and 26.1%, respectively. The effective rate for the three months ended June 30, 2026 and 2025 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.

Results of Operations - Six Months Ended June 30, 2026 Compared with Six Months Ended June 30, 2025

Net Income

CNX had net income of $551 million, or earnings per diluted share of $3.56, for the six months ended June 30, 2026, compared to net income of $235 million, or earnings per diluted share of $1.37, for the six months ended June 30, 2025.

Included in the earnings for the six months ended June 30, 2026 was an unrealized gain on commodity derivative instruments of $356 million and a net gain on asset sales and abandonments of $6 million. Included in the earnings for the six months ended June 30, 2025 was an unrealized gain on commodity derivative instruments of $38 million and a net gain on asset sales and abandonments of $27 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, net.

Non-GAAP Financial Measures

Non-GAAP Financial Measures Reconciliation


	For the Six Months Ended June 30,
(Dollars in millions)	2026		2025
Total Revenue and Other Operating Income	$	1,405	$	1,045
Deduct:
Purchased Gas Revenue	(25)		(22)
Unrealized Gain on Commodity Derivative Instruments	(356)		(38)
Other Revenue and Operating Income	(89)		(94)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	935	$	891

Total Operating Expense	$	653	$	666
Deduct:
Depreciation, Depletion and Amortization (DD&A) - Corporate	(11)		(10)
Exploration and Production Related Other Costs	(7)		(4)
Purchased Gas Costs	(25)		(21)


Selling, General and Administrative Costs	(66)		(68)
Other Operating Expense	(20)		(35)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	524	$	528

Selected Natural Gas, NGLs and Oil Production Financial Data


	For the Six Months Ended June 30,
	2026				2025				Variance
	in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			303.8				315.4				(11.6)

Natural Gas, NGLs and Oil Revenue	$	1,111	$	3.72	$	1,036	$	3.32	$	75	$	0.40
Loss on Commodity Derivative Instruments - Cash Settlement	(176)		(0.64)		(145)		(0.50)		(31)		(0.14)
Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure	935		3.08		891		2.82		44		0.26
Lease Operating Expense	43		0.14		49		0.16		(6)		(0.02)
Production, Ad Valorem, and Other Fees	15		0.05		17		0.06		(2)		(0.01)
Transportation, Gathering and Compression	206		0.68		192		0.61		14		0.07
Depreciation, Depletion and Amortization (DD&A)	260		0.86		270		0.84		(10)		0.02
Natural Gas, NGLs and Oil Production Costs, a Non-GAAP Financial Measure	524		1.73		528		1.67		(4)		0.06
Natural Gas, NGLs and Oil Production Margin, a Non-GAAP Financial Measure	$	411	$	1.35	$	363	$	1.15	$	48	$	0.20

The 11.6 Bcfe decrease in sales volumes was primarily due to normal production declines and the timing of when new wells were turned-in-line.

Changes in the average costs per Mcfe were primarily related to the following items:

•Lease operating expense decreased on a per unit basis primarily due to a decrease in water disposal costs as more water was reused in well completions. The per unit decrease was offset, in part, by the overall decrease in total sales volumes.

•Production, ad valorem, and other fees decreased on a per unit basis primarily due to lower property taxes in the period to period comparison. The per unit decrease was offset, in part, by the overall decrease in total sales volumes.

•Transportation, gathering and compression expense increased on a per unit basis primarily due to the overall decrease in total sales volumes, higher repairs and maintenance expense, higher processing costs due to production mix and increased utilization of firm transportation capacity as volumes in our central Pennsylvania operating area have increased.

•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to the overall decrease in total sales volumes. The increase was offset, in part, by a slightly lower annual depletion rate.

Average Realized Price Reconciliation


	For the Six Months Ended June 30,
in thousands (unless noted)	2026		2025		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	27,877		23,314		4,563		19.6	%
Sales Volume (Mbbls)	4,646		3,886		760		19.6	%
Gross Price ($/Bbl)	$	25.38	$	24.12	$	1.26	5.2	%
Gross NGL Revenue	$	117,832	$	93,821	$	24,011	25.6	%

Oil/Condensate:
Sales Volume (MMcfe)	738		386		352		91.2	%
Sales Volume (Mbbls)	123		64		59		92.2	%
Gross Price ($/Bbl)	$	66.36	$	55.08	$	11.28	20.5	%
Gross Oil/Condensate Revenue	$	8,158	$	3,546	$	4,612	130.1	%

NATURAL GAS
Sales Volume (MMcf)	275,210		291,718		(16,508)		(5.7)	%
Sales Price ($/Mcf)	$	3.58	$	3.22	$	0.36	11.2	%
Gross Natural Gas Revenue	$	985,488	$	938,756	$	46,732	5.0	%

Hedging Impact ($/Mcf)	$	(0.64)	$	(0.50)	$	(0.14)	28.0	%
Loss on Commodity Derivative Instruments - Cash Settlement	$	(176,162)	$	(145,091)	$	(31,071)	21.4	%

The increase in Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the $0.36 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 on commodity derivative instruments - cash settlement related to the Company's hedging program and the 11.6 Bcfe decrease in total sales volumes.

SEGMENT ANALYSIS for the six months ended June 30, 2026 compared to the six months ended June 30, 2025:


	For the Six Months Ended								Difference to Six Months Ended
	June 30, 2026								June 30, 2025
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total



Natural Gas, NGLs and Oil Revenue	$	1,023	$	87	$	1	$	1,111	$	64	$	11	$	—	$	75
(Loss) Gain on Commodity Derivative Instruments	(166)		(10)		356		180		(30)		(1)		318		287
Purchased Gas Revenue	—		—		25		25		—		—		3		3
Other Revenue and Operating Income	32		—		57		89		(2)		—		(3)		(5)

Total Revenue and Other Operating Income	889		77		439		1,405		32		10		318		360
Lease Operating Expense	30		12		1		43		(7)		—		1		(6)
Production, Ad Valorem, and Other Fees	11		4		—		15		(3)		1		—		(2)
Transportation, Gathering and Compression	174		31		1		206		16		(2)		—		14
Depreciation, Depletion and Amortization	228		29		14		271		(10)		—		1		(9)


Exploration and Production Related Other Costs	—		—		7		7		—		—		3		3
Purchased Gas Costs	—		—		25		25		—		—		4		4
Selling, General and Administrative Costs	—		—		66		66		—		—		(2)		(2)
Other Operating Expense	—		—		20		20		—		—		(15)		(15)
Total Operating Expense	443		76		134		653		(4)		(1)		(8)		(13)
Other Expense	—		—		2		2		—		—		(5)		(5)
Gain on Asset Sales and Abandonments, net	—		—		(6)		(6)		—		—		21		21
Loss on Debt Extinguishment	—		—		12		12		—		—		12		12
Interest Expense	—		—		79		79		—		—		(7)		(7)
Total Other Expense	—		—		87		87		—		—		21		21
Total Costs and Expenses	443		76		221		740		(4)		(1)		13		8
Earnings Before Income Tax	$	446	$	1	$	218	$	665	$	36	$	11	$	305	$	352

SHALE SEGMENT

The Shale segment had earnings before income tax of $446 million for the six months ended June 30, 2026 compared to earnings before income tax of $410 million for the six months ended June 30, 2025.


	For the Six Months Ended June 30,
	2026		2025		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	256.3		272.9		(16.6)		(6.1)	%
NGLs Sales Volumes (Bcfe)*	27.9		23.3		4.6		19.7	%
Oil/Condensate Sales Volumes (Bcfe)*	0.7		0.4		0.3		75.0	%
Total Shale Sales Volumes (Bcfe)*	284.9		296.6		(11.7)		(3.9)	%

Average Shale Gas Sales Price (per Mcf)	$	3.50	$	3.16	$	0.34	10.8	%
Loss on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	(0.65)	$	(0.50)	$	(0.15)	(30.0)	%
Average Sales Price - NGLs (per Mcfe)*	$	4.23	$	4.02	$	0.21	5.2	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	11.04	$	9.18	$	1.86	20.3	%

Total Average Shale Sales Price (per Mcfe)	$	3.01	$	2.78	$	0.23	8.3	%
Average Shale Lease Operating Expenses (per Mcfe)	0.11		0.13		(0.02)		(15.4)	%
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)	0.04		0.04		—		—	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.61		0.53		0.08		15.1	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.79		0.81		(0.02)		(2.5)	%
Total Average Shale Production Costs (per Mcfe)	$	1.55	$	1.51	$	0.04	2.6	%
Total Average Shale Production Margin (per Mcfe)	$	1.46	$	1.27	$	0.19	15.0	%

* 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, NGLs, condensate, and natural gas prices.

The decrease in total Shale sales volumes was primarily due to normal production declines offset, in part, by new wells turned-in-line throughout the second half of 2025 and the first half of 2026.

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,023 million for the six months ended June 30, 2026 compared to $959 million for the six months ended June 30, 2025. The $64 million increase was primarily due to a 10.8% increase in the average sales price for natural gas and a 5.2% increase in the average sales price of NGLs. The increase was offset, in part, by the 30.0% change in the loss on commodity derivative instruments and a 3.9% decrease in total Shale sales volumes.

The Shale segment had a loss on commodity derivative instruments - cash settlements of $166 million for the six months ended June 30, 2026 compared to a loss of $136 million for the six months ended June 30, 2025. The notional amounts associated with these financial hedges represented approximately 214.3 Bcf of the Company's produced Shale gas sales volumes for the six months ended June 30, 2026 at an average loss of $0.77 per Mcf hedged. For the six months ended June 30, 2025, these financial hedges represented approximately 223.3 Bcf at an average loss of $0.60 per Mcf hedged.

The increase in total average Shale sales price was primarily due to a $0.34 per Mcf increase in average gas sales price and a $0.21 per Mcfe increase in the average NGL sales price. These increases were offset, in part, by a $0.15 per Mcf change in the loss on commodity derivative instruments - cash settlements.

Total operating costs and expenses for the Shale segment were $443 million for the six months ended June 30, 2026 compared to $447 million for the six months ended June 30, 2025. The decrease in total dollars and increase in unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $30 million for the six months ended June 30, 2026 compared to $37 million for the six months ended June 30, 2025. The decrease in total dollars and unit costs was primarily related to a decrease in water disposal costs as more water was reused in well completions. The per unit decrease was offset, in part, by the overall decrease in total sales volumes.

•Shale transportation, gathering and compression costs were $174 million for the six months ended June 30, 2026 compared to $158 million for the six months ended June 30, 2025. The increase in total dollars and unit costs was primarily due to higher repairs and maintenance expense, increased processing costs due to production mix and more utilization of firm transportation capacity as volumes in our central Pennsylvania operating area have increased. The per unit increase was also due to the overall decrease in total Shale sales volumes.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $228 million for the six months ended June 30, 2026 compared to $238 million for the six months ended June 30, 2025. These amounts included depletion on a unit of production basis of $0.69 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 $32 million for the six months ended June 30, 2026 compared to $34 million for the six months ended June 30, 2025. The decrease in the period-to-period comparison was primarily due to a decrease in third-party gathering volumes.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $1 million for the six months ended June 30, 2026 compared to a loss before income tax of $10 million for the six months ended June 30, 2025.


	For the Six Months Ended June 30,
	2026		2025		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	18.8		18.7		0.1		0.5	%

Average CBM Gas Sales Price (per Mcf)	$	4.64	$	4.09	$	0.55	13.4	%
Loss on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	(0.54)	$	(0.49)	$	(0.05)	(10.2)	%

Total Average CBM Sales Price (per Mcf)	$	4.10	$	3.60	$	0.50	13.9	%
Average CBM Lease Operating Expenses (per Mcf)	0.65		0.64		0.01		1.6	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.20		0.17		0.03		17.6	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	1.66		1.77		(0.11)		(6.2)	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.56		1.53		0.03		2.0	%
Total Average CBM Production Costs (per Mcf)	$	4.07	$	4.11	$	(0.04)	(1.0)	%
Total Average CBM Production Margin (per Mcf)	$	0.03	$	(0.51)	$	0.54	105.9	%

The CBM segment had natural gas revenue of $87 million for the six months ended June 30, 2026 compared to $76 million for the six months ended June 30, 2025. The $11 million increase was due to a 13.4% increase in the average sales price for natural gas in the current period and a 0.5% increase in CBM sales volumes due to the timing of when new wells were turned-in-line. The increase in CBM sales volumes was offset, in part, by normal production declines.

The total average CBM sales price increased $0.50 per Mcf due to a $0.55 per Mcf increase in average natural gas sales price offset, in part, by a $0.05 per Mcf change in the loss on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 14.3 Bcf of the Company's produced CBM sales volumes for the six months ended June 30, 2026 at an average loss of $0.71 per Mcf hedged. For the six months ended June 30, 2025, these financial hedges represented approximately 14.3 Bcf at an average loss of $0.63 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $76 million for the six months ended June 30, 2026 compared to $77 million for the six months ended June 30, 2025. The decrease in total dollars and unit costs for the CBM segment were due to the following items:

•CBM lease operating expenses were $12 million for both the six months ended June 30, 2026 and 2025. The increase in per unit costs was due to an increase in repairs and maintenance expense, offset, in part, by the increase in total CBM volumes.

•CBM production, ad valorem and other fees were $4 million for the six months ended June 30, 2026 compared to $3 million for the six months ended June 30, 2025. The increase in total dollars and unit costs was primarily due to the increase in the average CBM gas sales price.

•CBM transportation, gathering and compression costs were $31 million for the six months ended June 30, 2026 compared to $33 million for the six months ended June 30, 2025. The decrease in total dollars and unit costs was due to a decrease in electrical compression rates in the current period.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $29 million for both the six months ended June 30, 2026 and 2025. These amounts included depletion on a unit of production basis of $0.80 per Mcfe and $0.86 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 had earnings before income tax of $218 million for the six months ended June 30, 2026 compared to a loss before income tax of $87 million for the six months ended June 30, 2025. The increase in total dollars is discussed below.


	For the Six Months Ended June 30,
	2026	2025	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.1	—	0.1	100.0	%

Unrealized Gain on Commodity Derivative Instruments

For the six months ended June 30, 2026, the Other Segment recognized an unrealized gain on commodity derivative instruments of $356 million. For the six months ended June 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $38 million. The unrealized gain 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 $25 million for the six months ended June 30, 2026 compared to $22 million for the six months ended June 30, 2025. Purchased gas costs were $25 million for the six months ended June 30, 2026 compared to $21 million for the six months ended June 30, 2025. The period-to-period increase in purchased gas revenue was primarily due to an increase in purchased gas sales volumes offset, in part, by a decrease in average sales price.


	For the Six Months Ended June 30,
	2026		2025		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	7.8		6.1		1.7		27.9	%
Average Sales Price (per Mcf)	$	3.24	$	3.60	$	(0.36)	(10.0)	%
Purchased Gas Average Cost (per Mcf)	$	3.16	$	3.38	$	(0.22)	(6.5)	%

Other Operating Income


	For the Six Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Sales of Environmental Attributes	$	29	$	43	$	(14)	(32.6)	%
Equity (Loss) Income from Affiliates	(1)		1		(2)		(200.0)	%
Water Income	8		7		1		14.3	%
Excess Firm Transportation Income	21		9		12		133.3	%

Total Other Operating Income	$	57	$	60	$	(3)	(5.0)	%

•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 the price received.

Exploration and Production Related Other Costs


	For the Six Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Lease Expiration Costs	$	4	$	2	$	2	100.0	%
Permitting Expense	1		—		1		100.0	%
Land Rentals	2		2		—		—	%




Total Exploration and Production Related Other Costs	$	7	$	4	$	3	75.0	%

•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months. The increase in the six months ended June 30, 2026 was primarily due to an increase in the number of leases that were allowed to expire.

SG&A


	For the Six Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Long-term Equity-Based Compensation (Non-Cash)	$	12	$	14	$	(2)	(14.3)	%
Contributions and Advertising	3		3		—		—	%
Short-term Incentive Compensation	6		6		—		—	%
Salaries, Wages and Employee Benefits	15		13		2		15.4	%
Other	30		32		(2)		(6.3)	%
Total SG&A	$	66	$	68	$	(2)	(2.9)	%

•Long-term equity-based compensation (non-cash) decreased in the period-to-period comparison due to a decrease in the amount of equity awards.

•Salaries, wages and employee benefits increased in the period-to-period comparison primarily due to higher compensation costs during the current period.

•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.

Other Operating Expense


	For the Six Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	3	$	18	$	(15)	(83.3)	%
Inventory Adjustments	—		1		(1)		(100.0)	%
Idle Equipment and Service Charges	1		2		(1)		(50.0)	%
Insurance Expense	2		3		(1)		(33.3)	%

Environmental Attribute Fees	5		5		—		—	%
Water Expense	1		—		1		100.0	%
Mineral Interest Adjustment	7		—		7		100.0	%
Other	1		6		(5)		(83.3)	%
Total Other Operating Expense	$	20	$	35	$	(15)	(42.9)	%

•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Revenue and Operating Income.

•During the six months ended June 30, 2026, the Company recorded a $7 million adjustment related to the resolution of ownership-related matter involving certain oil and gas rights. As a result of the resolution, the Company's unleased mineral interest and net revenue interest in the affected wells were recalculated, resulting in a reduction to its net revenue interest.

Other Expense


	For the Six Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Other Income

Right-of-Way Sales	$	3	$	—	$	3	100.0	%
Litigation Recoveries	—		1		(1)		(100.0)	%

Other	4		2		2		100.0	%
Total Other Income	$	7	$	3	$	4	133.3	%

Other Expense

Professional Services	$	1	$	2	$	(1)	(50.0)	%
Bank Fees	5		5		—		—	%

Other Corporate Expense	3		3		—		—	%
Total Other Expense	$	9	$	10	$	(1)	(10.0)	%

Total Other Expense	$	2	$	7	$	(5)	(71.4)	%

•Right‑of‑way sales represent revenue generated from granting third‑party access across the Company’s surface acreage. The $3 million increase in the period-to-period comparison was due to higher right‑of‑way activity in the current period.

Gain on Asset Sales and Abandonments, net

A net gain on asset sales and abandonments of $6 million was recognized in the six months ended June 30, 2026 compared to a net gain of $27 million in the six months ended June 30, 2025. The net gain recognized in the six months ended June 30, 2026 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 gain recognized in the six months ended June 30, 2025 primarily relates to sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests), offset, in part, by a $6 million loss on the sale of a non-core midstream facility to a third party. 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 $12 million was recognized in the six months ended June 30, 2026 in connection with CNX's repurchase of $500 million aggregate principal amount of 6.00% Senior Notes due January 2029 at an average price equal to 101.6% 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 prior period.

Interest Expense


	For the Six Months Ended June 30,
(in millions)	2026		2025		Variance		Percent Change
Total Interest Expense	$	79	$	86	$	(7)	(8.1)	%

The $7 million decrease in total interest expense was primarily due to lower borrowings on the CNX Credit Facility and a reduction in the amount of Convertible Notes outstanding pursuant to the exchange agreement that was entered into in December 2025, offset, in part, by higher 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 Six Months Ended June 30,
(in millions)	2026			2025			Variance			Percent Change
Total Company Earnings Before Income Tax	$	665		$	313		$	352		112.5	%
Income Tax Expense	$	114		$	78		$	36		46.2	%
Effective Income Tax Rate	17.2		%	24.9		%	(7.7)		%

The effective income tax rates for the six months ended June 30, 2026 and 2025 were 17.2% and 24.9%, respectively. The effective tax rate for the six months ended June 30, 2026 and 2025 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.

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 June 30, 2026, 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 $9 million as of June 30, 2026 and $13 million as of December 31, 2025.

•Accounts and notes receivable - trade were $164 million as of June 30, 2026 and $265 million as of December 31, 2025. 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.

•Capital expenditures are expected to range between $556 million to $586 million for the year ended December 31, 2026. For the six months ended June 30, 2026, CNX had capital expenditures of $312 million.

•Production volumes are expected to range between 605.0 Bcfe and 620.0 Bcfe for the year ended December 31, 2026. For the six months ended June 30, 2026, CNX had production volumes of 303.8 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 asset of $132 million at June 30, 2026 and a net liability of $296 million at December 31, 2025. 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.

•CNX may from time to time seek to repurchase and retire outstanding debt, issue new debt, or repurchase a portion of its outstanding common stock 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 amounts involved in any such transactions may be material. 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 for discussion related to CNX’s outstanding debt and Note 15 – Stock Repurchase in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information for discussion related to the repurchase of CNXs outstanding common stock.

Cash Flows (in millions)


	For the Six Months Ended June 30,
	2026		2025		Change
Cash Provided by Operating Activities	$	557	$	498	$	59
Cash Used in Investing Activities	$	(290)	$	(729)	$	439
Cash (Used in) Provided by Financing Activities	$	(272)	$	191	$	(463)

Cash flows from operating activities changed in the period-to-period comparison primarily due to the following items:

•Net income increased $316 million in the period-to-period comparison.

•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $363 million net change in commodity derivative instruments, a $46 million net increase in deferred income taxes, a $22 million decrease in gain on asset sales and abandonments, a $12 million increase in loss on debt extinguishment and a $26 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 increased $67 million primarily due to an increase in drilling and completions activity.

•Proceeds from asset sales decreased $5 million primarily due to the sale in the prior period of non-core oil and gas rights and various non-operated producing oil and gas assets mainly 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 six months ended June 30, 2026, the Company released approximately $10 million of restricted cash 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, subject to certain post-closing adjustments. During the six months ended June 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 $24 million and repayments under the CNXM Credit Facility decreased $28 million.

•Proceeds from borrowings under the CNX Credit Facility decreased $119 million and repayments under the CNX Credit Facility increased $168 million.

•During the six months ended June 30, 2026, CNX issued $500 million aggregate principal amount of CNX 5.875% Senior Notes due March 2034 at par. 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 six months ended June 30, 2026, CNX paid $508 million to repurchase $500 million aggregate principal amount of CNX 6.00% Senior Notes due January 2029 at a price of 101.6% of their 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 six months ended June 30, 2025, CNX issued an additional $200 million aggregate principal amount of additional 7.25% Senior Notes due March 2032 at a price of 100.5% of their principal amount. 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.

•In the six months ended June 30, 2026, CNX repurchased $254 million of its common stock on the open market compared to $241 million during the six months ended June 30, 2025.

•During the six months ended June 30, 2026, debt issuance and financing fees increased $7 million primarily due to the issuance of the $500 million aggregate principal amount of 5.875% Senior Notes due March 2034. 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.

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 June 30, 2026 (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	$	5,251	$	5,296	$	1,180	$	—	$	11,727
Gas Firm Transportation and Processing	252,005		403,192		239,487		406,213		1,300,897
Long-Term Debt	—		245,650		894,365		1,095,258		2,235,273
Interest on Long-Term Debt	142,706		282,637		239,344		131,625		796,312
Finance Lease Obligations	5,102		13,839		4,800		3,929		27,670
Interest on Finance Lease Obligations	1,624		2,293		915		240		5,072
Operating Lease Obligations	46,735		66,737		12,250		3,094		128,816
Interest on Operating Lease Obligations	6,534		5,066		999		813		13,412
Long-Term Liabilities—Employee Related (a)	2,811		5,563		5,312		18,445		32,131
Other Long-Term Liabilities (b)	194,885		32,400		22,000		141,393		390,678
Total Contractual Obligations (c)	$	657,653	$	1,062,673	$	1,420,652	$	1,801,010	$	4,941,988

_________________________

(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 June 30, 2026, CNX had total debt of $2,235 million, 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 5.875% Senior Notes due March 2034. Interest on the notes is payable March 1 and September 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).

•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 $2 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 $156 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 $90 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.

Total Equity and Dividends

CNX had total equity of $4,844 million at June 30, 2026 compared to $4,337 million at December 31, 2025. 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 June 30, 2026. 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 2025 financial statements, included in the 2025 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 2025 Form 10-K.

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 NGLs are volatile and can fluctuate widely based upon a number of factors beyond our control, including supply and demand for our product;

•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, NGLs, 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;

•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;

•expectations of future revenue from sales of environmental attributes and the availability of various clean energy and environmental attribute credits, incentives, or grants are subject to price fluctuations, eligibility criteria, and compliance with specific voluntary or compliance program requirements, legislative changes, or regulatory actions that are outside of CNX control, and new markets for environmental attributes are 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;

•provisions of our unsecured debt agreements 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, Core, the successor by merger to CONSOL Energy Inc. has agreed to indemnify us for certain liabilities, and we have agreed to indemnify Core 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, 2025 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, 2025. 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.

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 2025 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 June 30, 2026, our open derivative instruments were in a net asset position with a fair value of $132 million. At December 31, 2025, our open derivative instruments were in a net liability position with a fair value of $296 million. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at June 30, 2026 and December 31, 2025. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $315 million and $423 million at June 30, 2026 and December 31, 2025, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by $315 million and $423 million at June 30, 2026 and December 31, 2025, 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 June 30, 2026 and December 31, 2025, CNX had $2,006 million and $2,219 million, respectively, of aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $12 million and $8 million, respectively. At June 30, 2026 and December 31, 2025, CNX had $246 million and $233 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 $156 million borrowings at June 30, 2026 and $200 million borrowings at December 31, 2025, and the CNXM Credit Facility, under which there were $90 million of borrowings at June 30, 2026 and $33 million at December 31, 2025. A hypothetical 100 basis-point increase in the average rate for CNX's variable-rate instruments would decrease pre-tax future earnings as of June 30, 2026 and December 31, 2025 by $2 million 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.

Natural Gas Hedging Volumes

As of July 8, 2026, 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
2026 Fixed Price Volumes
Hedged Bcf	N/A		N/A		116.0		115.3		231.3
Weighted Average Hedge Price per Mcf	N/A		N/A		$	2.74	$	2.74	$	2.74
2027 Fixed Price Volumes
Hedged Bcf	101.7		101.0		102.1		100.9		402.4*
Weighted Average Hedge Price per Mcf	$	3.31	$	3.30	$	3.30	$	3.34	$	3.31
2028 Fixed Price Volumes
Hedged Bcf	53.6		55.9		56.5		54.9		220.9
Weighted Average Hedge Price per Mcf	$	3.21	$	3.24	$	3.24	$	3.22	$	3.23

*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.

Note: Table excludes basis only hedges of 24.5 Bcf for 2029.

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 June 30, 2026 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.

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 2025 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. There have been no material changes to the Company’s risk factors as set forth in the 2025 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 June 30, 2026:


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)
April 1, 2026 - April 30, 2026	1,135,802	$	38.57	1,135,802	$	2,330,178
May 1, 2026 - May 31, 2026	1,936,819	$	35.78	1,936,819	$	2,260,870
June 1, 2026 - June 30, 2026	2,662,821	$	33.41	2,662,821	$	2,171,897
Total	5,735,442			5,735,442

(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 $4,900 million share repurchase program authorized by CNX's Board of Directors and announced on September 5, 2017, and January 29, 2026 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 June 30, 2026.

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.
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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: July 30, 2026


CNX RESOURCES CORPORATION

	By:	/S/ ALAN K. SHEPARD
		Alan K. Shepard
		Director, Chief Executive Officer and President (Duly Authorized Officer and Principal Executive Officer)

	By:	/S/ EVERETT W. GOOD
		Everett W. Good
		Chief Financial Officer (Duly Authorized Officer and Principal Financial and Accounting Officer)