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CNX Resources Corporation

10/29/2026 | Press release | Distributed by Public on 10/29/2026 11:47

Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)

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 fourth quarter of 2026 is 115.0 Bcf. CNX's annual gas hedge position is shown in the table below:


	2026	2027
Volumes Hedged (Bcf), as of 10/8/26	460.6(1)	411.4

1Includes actual settlements of 298.3 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 September 30, 2026 Compared with Three Months Ended September 30, 2025

Net Income

CNX reported net income of $165 million, or earnings per diluted share of $1.12, for the three months ended September 30, 2026, compared to net income of $202 million, or earnings per diluted share of $1.21, for the three months ended September 30, 2025.

Included in the earnings for the three months ended September 30, 2026 was an unrealized gain on commodity derivative instruments of $108 million and a net gain on asset sales and abandonments of $4 million. Included in the earnings for the three months ended September 30, 2025 was an unrealized gain on commodity derivative instruments of $110 million and a net gain on asset sales and abandonments of $68 million. See Note 4 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the gain on asset sales and abandonments.

Non-GAAP Financial Measures

CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company's operating performance. Sales of Natural Gas, 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 September 30,
(Dollars in millions)	2026		2025
Total Revenue and Other Operating Income	$	580	$	584
Deduct:
Purchased Gas Revenue	(4)		(9)
Unrealized Gain on Commodity Derivative Instruments	(108)		(110)
Other Revenue and Operating Income	(43)		(42)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	425	$	423

Total Operating Expense	$	321	$	341
Deduct:
Depreciation, Depletion and Amortization (DD&A) - Corporate	(6)		(5)
Exploration and Production Related Other Costs	(2)		(2)
Purchased Gas Costs	(5)		(9)
Selling, General and Administrative Costs	(35)		(30)
Other Operating Expense	(19)		(19)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	254	$	276

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 September 30,
	2026				2025				Variance
	in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			156.3				161.3				(5.0)

Natural Gas, NGLs and Oil Revenue	$	372	$	2.35	$	401	$	2.47	$	(29)	$	(0.12)
Gain on Commodity Derivative Instruments - Cash Settlement	53		0.37		22		0.15		31		0.22
Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure	425		2.72		423		2.62		2		0.10
Lease Operating Expense	24		0.15		27		0.17		(3)		(0.02)
Production, Ad Valorem, and Other Fees	6		0.05		8		0.05		(2)		-
Transportation, Gathering and Compression	95		0.61		97		0.60		(2)		0.01
Depreciation, Depletion and Amortization (DD&A)	129		0.82		144		0.89		(15)		(0.07)
Natural Gas, NGLs and Oil Production Costs, a Non-GAAP Financial Measure	254		1.63		276		1.71		(22)		(0.08)
Natural Gas, NGLs and Oil Production Margin, a Non-GAAP Financial Measure	$	171	$	1.09	$	147	$	0.91	$	24	$	0.18

*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 5.0 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. The increase was offset, in part, by lower repairs and maintenance and electrical compression.

•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 September 30,
in thousands (unless noted)	2026		2025		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	13,821		12,042		1,779		14.8	%
Sales Volume (Mbbls)	2,304		2,007		297		14.8	%
Gross Price ($/Bbl)	$	23.70	$	18.24	$	5.46	29.9	%
Gross NGL Revenue	$	54,613	$	36,663	$	17,950	49.0	%

Oil/Condensate:
Sales Volume (MMcfe)	178		319		(141)		(44.2)	%
Sales Volume (Mbbls)	30		53		(23)		(43.4)	%
Gross Price ($/Bbl)	$	75.24	$	56.94	$	18.30	32.1	%
Gross Oil/Condensate Revenue	$	2,234	$	3,027	$	(793)	(26.2)	%

NATURAL GAS
Sales Volume (MMcf)	142,328		148,940		(6,612)		(4.4)	%
Sales Price ($/Mcf)	$	2.22	$	2.43	$	(0.21)	(8.6)	%
Gross Natural Gas Revenue	$	315,669	$	361,300	$	(45,631)	(12.6)	%

Hedging Impact ($/Mcf)	$	0.37	$	0.15	$	0.22	146.7	%
Gain on Commodity Derivative Instruments - Cash Settlement	$	52,452	$	22,379	$	30,073	134.4	%

The increase in Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to a $30.1 million increase in gain on commodity derivative instruments - cash settlement related to the Company's hedging program, a 1.8 Bcfe increase in NGL sales volumes and a $5.46 per Bbl increase in NGL prices. The increases were offset, in part, by a 6.6 Bcfe decrease in natural gas sales volume and a $0.21 per Mcf decrease in natural gas sales price.

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


	For the Three Months Ended								Difference to Three Months Ended
	September 30, 2026								September 30, 2025
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total
Natural Gas, NGLs and Oil Revenue	$	341	$	31	$	-	$	372	$	(26)	$	(2)	$	(1)	$	(29)
Gain on Commodity Derivative Instruments	49		4		108		161		28		3		(2)		29
Purchased Gas Revenue	-		-		4		4		-		-		(5)		(5)
Other Revenue and Operating Income	15		-		28		43		(3)		-		4		1
Total Revenue and Other Operating Income	405		35		140		580		(1)		1		(4)		(4)
Lease Operating Expense	17		7		-		24		(4)		1		-		(3)
Production, Ad Valorem, and Other Fees	5		1		-		6		(1)		(1)		-		(2)
Transportation, Gathering and Compression	81		13		1		95		-		(3)		1		(2)
Depreciation, Depletion and Amortization	113		16		6		135		(14)		1		(1)		(14)
Exploration and Production Related Other Costs	-		-		2		2		-		-		-		-
Purchased Gas Costs	-		-		5		5		-		-		(4)		(4)
Selling, General and Administrative Costs	-		-		35		35		-		-		5		5
Other Operating Expense	-		-		19		19		-		-		-		-
Total Operating Expense	216		37		68		321		(19)		(2)		1		(20)
Other Expense	-		-		4		4		-		-		2		2
Gain on Asset Sales and Abandonments, net	-		-		(4)		(4)		-		-		64		64
Interest Expense	-		-		40		40		-		-		(3)		(3)
Total Other Expense	-		-		40		40		-		-		63		63
Total Costs and Expenses	216		37		108		361		(19)		(2)		64		43
Earnings (Loss) Before Income Tax	$	189	$	(2)	$	32	$	219	$	18	$	3	$	(68)	$	(47)

SHALE SEGMENT

The Shale segment had earnings before income tax of $189 million for the three months ended September 30, 2026 compared to earnings before income tax of $171 million for the three months ended September 30, 2025.


	For the Three Months Ended September 30,
	2026		2025		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	132.8		139.2		(6.4)		(4.6)	%
NGLs Sales Volumes (Bcfe)*	13.8		12.0		1.8		15.0	%
Oil/Condensate Sales Volumes (Bcfe)*	0.2		0.3		(0.1)		(33.3)	%
Total Shale Sales Volumes (Bcfe)*	146.8		151.5		(4.7)		(3.1)	%

Average Sales Price - Natural Gas (per Mcf)	$	2.14	$	2.36	$	(0.22)	(9.3)	%
Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	0.37	$	0.15	$	0.22	146.7	%
Average Sales Price - NGLs (per Mcfe)*	$	3.95	$	3.04	$	0.91	29.9	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	12.46	$	9.01	$	3.45	38.3	%

Total Average Shale Sales Price (per Mcfe)	$	2.66	$	2.56	$	0.10	3.9	%
Average Shale Lease Operating Expenses (per Mcfe)	0.12		0.14		(0.02)		(14.3)	%
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)	0.03		0.04		(0.01)		(25.0)	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.55		0.53		0.02		3.8	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.77		0.84		(0.07)		(8.3)	%
Total Average Shale Production Costs (per Mcfe)	$	1.47	$	1.55	$	(0.08)	(5.2)	%
Total Average Shale Production Margin (per Mcfe)	$	1.19	$	1.01	$	0.18	17.8	%

* 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 $341 million for the three months ended September 30, 2026 compared to $367 million for the three months ended September 30, 2025. The $26 million decrease was primarily due to a 9.3% decrease in the average sales price of natural gas and a 4.6% decrease in Shale gas sales volumes. These decreases were offset, in part, by a 29.9% increase in the average sales price of NGLs and a 15.0% increase in NGLs sales volumes.

The Shale segment had a gain on commodity derivative instruments - cash settlements of $49 million for the three months ended September 30, 2026 compared to a gain of $21 million for the three months ended September 30, 2025. The notional amounts associated with these financial hedges represented approximately 109.4 Bcf of the Company's produced Shale gas sales volumes for the three months ended September 30, 2026 at an average gain of $0.45 per Mcf hedged. For the three months ended September 30, 2025, these financial hedges represented approximately 115.7 Bcf at an average gain of $0.18 per Mcf hedged.

The $0.10 per Mcfe increase in total average Shale sales price was primarily due to a $0.91 per Mcfe increase in the average sales price of NGLs and a $0.22 per Mcf increase in the gain on commodity derivative instruments - cash settlements. These increases were offset, in part, by a $0.22 per Mcf decrease in the average sales price of natural gas.

Total operating costs and expenses for the Shale segment were $216 million for the three months ended September 30, 2026 compared to $235 million for the three months ended September 30, 2025. The decrease in total dollars and unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $17 million for the three months ended September 30, 2026 compared to $21 million for the three months ended September 30, 2025. The decrease in total dollars and unit costs was 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 September 30, 2026 compared to $6 million for the three months ended September 30, 2025. The decrease in total dollars and unit costs was primarily due to lower realized natural gas prices. The decrease in unit costs was offset, in part, by lower total sales volumes during the period.

•Shale transportation, gathering and compression costs were $81 million for both the three months ended September 30, 2026 and 2025. The increase in unit costs was primarily due to lower total sales volumes during the period.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $113 million for the three months ended September 30, 2026 compared to $127 million for the three months ended September 30, 2025. These amounts included depletion on a units of production basis of $0.66 per Mcfe and $0.74 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 September 30, 2026 compared to $18 million for the three months ended September 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 $2 million for the three months ended September 30, 2026 compared to a loss before income tax of $5 million for the three months ended September 30, 2025.


	For the Three Months Ended September 30,
	2026		2025		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	9.4		9.7		(0.3)		(3.1)	%

Average Sales Price - Gas (per Mcf)	$	3.26	$	3.39	$	(0.13)	(3.8)	%
Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	0.35	$	0.14	$	0.21	150.0	%

Total Average CBM Sales Price (per Mcf)	$	3.61	$	3.53	$	0.08	2.3	%
Average CBM Lease Operating Expenses (per Mcf)	0.69		0.65		0.04		6.2	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.15		0.16		(0.01)		(6.3)	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	1.38		1.68		(0.30)		(17.9)	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.57		1.55		0.02		1.3	%
Total Average CBM Production Costs (per Mcf)	$	3.79	$	4.04	$	(0.25)	(6.2)	%
Total Average CBM Production Margin (per Mcf)	$	(0.18)	$	(0.51)	$	0.33	64.7	%

The CBM segment had natural gas revenue of $31 million for the three months ended September 30, 2026 compared to $33 million for the three months ended September 30, 2025. The $2 million decrease was primarily due to a 3.8% decrease in the average sales price of natural gas and a 3.1% decrease in CBM gas sales volumes due to normal production declines.

The total average CBM sales price increased $0.08 per Mcf primarily due to a $0.21 per Mcf increase in the gain on commodity derivative instruments - cash settlements offset, in part, by a $0.13 per Mcf decrease in average gas sales price. The notional amounts associated with these financial hedges represented approximately 7.1 Bcf of the Company's produced CBM sales volumes for the three months ended September 30, 2026 at an average gain of $0.46 per Mcf hedged. For the three months ended September 30, 2025, these financial hedges represented approximately 7.4 Bcf at an average gain of $0.18 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $37 million for the three months ended September 30, 2026 compared to $39 million for the three months ended September 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 $7 million for the three months ended September 30, 2026 compared to $6 million for the three months ended September 30, 2025. The increase in total dollars and unit costs was primarily due to higher water disposal expenses and lower CBM gas sales volumes during the period.

•CBM production, ad valorem and other fees were $1 million for the three months ended September 30, 2026 compared to $2 million for the three months ended September 30, 2025. The decrease in total dollars and unit costs was primarily due to lower realized natural gas prices.

•CBM transportation, gathering and compression costs were $13 million for the three months ended September 30, 2026 compared to $16 million for the three months ended September 30, 2025. The decrease in total dollars and unit costs was primarily due to lower electrical compression expense. The decrease in unit costs was offset, in part, by the decrease in total CBM volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $16 million for the three months ended September 30, 2026 compared to $15 million for the three months ended September 30, 2025. These amounts included depletion on a units of production basis of $0.80 per Mcfe and $0.87 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 $32 million for the three months ended September 30, 2026 compared to earnings before income tax of $100 million for the three months ended September 30, 2025. The decrease in total dollars is discussed below.


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

Unrealized Gain on Commodity Derivative Instruments

For the three months ended September 30, 2026, the Other Segment recognized an unrealized gain on commodity derivative instruments of $108 million. For the three months ended September 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $110 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 $4 million for the three months ended September 30, 2026 compared to $9 million for the three months ended September 30, 2025. Purchased gas costs were $5 million for the three months ended September 30, 2026 compared to $9 million for the three months ended September 30, 2025. The period-to-period decrease in purchased gas revenue was primarily due to a decrease in the average sales price and a decrease in purchased gas sales volumes.


	For the Three Months Ended September 30,
	2026		2025		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	2.1		3.3		(1.2)		(36.4)	%
Average Sales Price (per Mcf)	$	2.12	$	2.73	$	(0.61)	(22.3)	%
Purchased Gas Average Cost (per Mcf)	$	2.52	$	2.55	$	(0.03)	(1.2)	%

Other Operating Income


	For the Three Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Excess Firm Transportation Income	$	7	$	4	$	3	75.0	%
Water Income	4		3		1		33.3	%
Equity Loss from Affiliates	-		(1)		1		(100.0)	%
Sales of Environmental Attributes	17		18		(1)		(5.6)	%
Total Other Operating Income	$	28	$	24	$	4	16.7	%

•Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in Total Other Operating Expense.

•Water income represents revenue generated when CNX accepts deliveries of produced water from third parties for reuse in the Company's hydraulic fracturing operations, as well as from sales of freshwater to third parties.

•Equity loss 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.

•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 lower prices received for environmental attributes sold.

Exploration and Production Related Other Costs


	For the Three Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Land Rentals	$	1	$	2	$	(1)	(50.0)	%
Other	1		-		1		100.0	%
Total Exploration and Production Related Other Costs	$	2	$	2	$	-	-	%

SG&A

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


	For the Three Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	$	7	$	5	$	2	40.0	%
Contributions and Advertising	1		-		1		100.0	%
Salaries, Wages and Employee Benefits	7		6		1		16.7	%
Short-Term Incentive Compensation	3		3		-		-	%
Other	17		16		1		6.3	%
Total SG&A	$	35	$	30	$	5	16.7	%

•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in the amount of equity awards.

Other Operating Expense


	For the Three Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	11	$	12	$	(1)	(8.3)	%
Environmental Attribute Fees	3		3		-		-	%
Insurance Expense	1		1		-		-	%
Other	4		3		1		33.3	%
Total Other Operating Expense	$	19	$	19	$	-	-	%

•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 the period-to-period comparison was primarily due to improved utilization of minimum processing commitments, which reduced unutilized processing fees.

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

Other Expense


	For the Three Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Other Income
Right-of-Way Sales	$	2	$	1	$	1	100.0	%
Other	5		1		4		400.0	%
Total Other Income	$	7	$	2	$	5	250.0	%

Other Expense
Professional Services	$	6	$	-	$	6	100.0	%
Bank Fees	3		3		-		-	%
Other Corporate Expense	2		1		1		100.0	%
Total Other Expense	$	11	$	4	$	7	175.0	%

Total Other Expense	$	4	$	2	$	2	100.0	%

•The increase in other income was primarily due to proceeds received in connection with the settlement of a contractual matter.

•The increase in professional services expense was primarily attributable to transaction costs related to the monetization of federal tax credits.

Gain on Asset Sales and Abandonments, net

A net gain on asset sales and abandonments of $4 million was recognized in the three months ended September 30, 2026 compared to a net gain of $68 million in the three months ended September 30, 2025. The net gain recognized during the three months ended September 30, 2026 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.

The net gain recognized during the three months ended September 30, 2025 primarily related to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million and 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 September 30,
(in millions)	2026		2025		Variance		Percent Change
Total Interest Expense	$	40	$	43	$	(3)	(7.0)	%

The $3 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 September 30,
(in millions)	2026			2025			Variance			Percent Change
Total Company Earnings Before Income Tax	$	219		$	266		$	(47)		(17.7)	%
Income Tax Expense	$	54		$	64		$	(10)		(15.6)	%
Effective Income Tax Rate	24.6		%	23.9		%	0.7		%

The effective income tax rates for the three months ended September 30, 2026 and 2025 were 24.6% and 23.9%, respectively. The effective rate for the three months ended September 30, 2026 and 2025 differs from the U.S. federal statutory rate of 21% primarily due to the impact of federal tax credits, equity compensation 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 - Nine Months Ended September 30, 2026 Compared with Nine Months Ended September 30, 2025

Net Income

CNX had net income of $716 million, or earnings per diluted share of $4.70, for the nine months ended September 30, 2026, compared to net income of $437 million, or earnings per diluted share of $2.57, for the nine months ended September 30, 2025.

Included in the earnings for the nine months ended September 30, 2026 was an unrealized gain on commodity derivative instruments of $465 million and a net gain on asset sales and abandonments of $9 million. Included in the earnings for the nine months ended September 30, 2025 was an unrealized gain on commodity derivative instruments of $148 million and a net gain on asset sales and abandonments of $95 million. 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 Nine Months Ended September 30,
(Dollars in millions)	2026		2025
Total Revenue and Other Operating Income	$	1,985	$	1,629
Deduct:
Purchased Gas Revenue	(30)		(31)
Unrealized Gain on Commodity Derivative Instruments	(465)		(148)
Other Revenue and Operating Income	(130)		(136)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	1,360	$	1,314

Total Operating Expense	$	973	$	1,007
Deduct:
Depreciation, Depletion and Amortization (DD&A) - Corporate	(16)		(17)
Exploration and Production Related Other Costs	(9)		(6)
Purchased Gas Costs	(30)		(29)
Selling, General and Administrative Costs	(101)		(98)
Other Operating Expense	(39)		(54)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	778	$	803

Selected Natural Gas, NGLs and Oil Production Financial Data


	For the Nine Months Ended September 30,
	2026				2025				Variance
	in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			460.2				476.7				(16.5)

Natural Gas, NGLs and Oil Revenue	$	1,484	$	3.26	$	1,437	$	3.04	$	47	$	0.22
Loss on Commodity Derivative Instruments - Cash Settlement	(124)		(0.30)		(123)		(0.28)		(1)		(0.02)
Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure	1,360		2.96		1,314		2.76		46		0.20
Lease Operating Expense	67		0.15		77		0.16		(10)		(0.01)
Production, Ad Valorem, and Other Fees	22		0.04		25		0.06		(3)		(0.02)
Transportation, Gathering and Compression	300		0.65		289		0.61		11		0.04
Depreciation, Depletion and Amortization (DD&A)	389		0.85		412		0.86		(23)		(0.01)
Natural Gas, NGLs and Oil Production Costs, a Non-GAAP Financial Measure	778		1.69		803		1.69		(25)		-
Natural Gas, NGLs and Oil Production Margin, a Non-GAAP Financial Measure	$	582	$	1.27	$	511	$	1.07	$	71	$	0.20

The 16.5 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:

•Production, ad valorem, and other fees decreased on a per unit basis primarily due to lower property taxes. 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 lower total sales volumes, higher repairs and maintenance expense, higher processing costs resulting from production mix and increased utilization of firm transportation capacity in our central Pennsylvania operating area.

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

Average Realized Price Reconciliation


	For the Nine Months Ended September 30,
in thousands (unless noted)	2026		2025		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	41,698		35,356		6,342		17.9	%
Sales Volume (Mbbls)	6,950		5,893		1,057		17.9	%
Gross Price ($/Bbl)	$	24.84	$	22.14	$	2.70	12.2	%
Gross NGL Revenue	$	172,445	$	130,483	$	41,962	32.2	%

Oil/Condensate:
Sales Volume (MMcfe)	916		705		211		29.9	%
Sales Volume (Mbbls)	153		118		35		29.7	%
Gross Price ($/Bbl)	$	68.04	$	55.92	$	12.12	21.7	%
Gross Oil/Condensate Revenue	$	10,392	$	6,574	$	3,818	58.1	%

NATURAL GAS
Sales Volume (MMcf)	417,538		440,658		(23,120)		(5.2)	%
Sales Price ($/Mcf)	$	3.12	$	2.95	$	0.17	5.8	%
Gross Natural Gas Revenue	$	1,301,157	$	1,300,056	$	1,101	0.1	%

Hedging Impact ($/Mcf)	$	(0.30)	$	(0.28)	$	(0.02)	7.1	%
Loss on Commodity Derivative Instruments - Cash Settlement	$	(123,710)	$	(122,712)	$	(998)	0.8	%

The increase in Sales of Natural Gas, NGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to a $2.70 per Bbl increase in NGL prices and a $0.17 per Mcf increase in natural gas sales prices. These increases were offset, in part, by the 16.5 Bcfe decrease in total sales volumes and the impact of the change in the loss on commodity derivative instruments - cash settlement related to the Company's hedging program.

SEGMENT ANALYSIS for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025:


	For the Nine Months Ended								Difference to Nine Months Ended
	September 30, 2026								September 30, 2025
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total
Natural Gas, NGLs and Oil Revenue	$	1,365	$	118	$	1	$	1,484	$	39	$	9	$	(1)	$	47
(Loss) Gain on Commodity Derivative Instruments	(117)		(7)		465		341		(2)		1		317		316
Purchased Gas Revenue	-		-		30		30		-		-		(1)		(1)
Other Revenue and Operating Income	46		-		84		130		(6)		-		-		(6)
Total Revenue and Other Operating Income	1,294		111		580		1,985		31		10		315		356
Lease Operating Expense	47		19		1		67		(12)		1		1		(10)
Production, Ad Valorem, and Other Fees	17		5		-		22		(3)		-		-		(3)
Transportation, Gathering and Compression	255		44		1		300		17		(5)		(1)		11
Depreciation, Depletion and Amortization	339		44		22		405		(26)		1		1		(24)
Exploration and Production Related Other Costs	-		-		9		9		-		-		3		3
Purchased Gas Costs	-		-		30		30		-		-		1		1
Selling, General and Administrative Costs	-		-		101		101		-		-		3		3
Other Operating Expense	-		-		39		39		-		-		(15)		(15)
Total Operating Expense	658		112		203		973		(24)		(3)		(7)		(34)
Other Expense	-		-		6		6		-		-		(3)		(3)
Gain on Asset Sales and Abandonments, net	-		-		(9)		(9)		-		-		86		86
Loss on Debt Extinguishment	-		-		12		12		-		-		12		12
Interest Expense	-		-		119		119		-		-		(10)		(10)
Total Other Expense	-		-		128		128		-		-		85		85
Total Costs and Expenses	658		112		331		1,101		(24)		(3)		78		51
Earnings (Loss) Before Income Tax	$	636	$	(1)	$	249	$	884	$	55	$	13	$	237	$	305

SHALE SEGMENT

The Shale segment had earnings before income tax of $636 million for the nine months ended September 30, 2026 compared to earnings before income tax of $581 million for the nine months ended September 30, 2025.


	For the Nine Months Ended September 30,
	2026		2025		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	389.1		412.2		(23.1)		(5.6)	%
NGLs Sales Volumes (Bcfe)*	41.7		35.3		6.4		18.1	%
Oil/Condensate Sales Volumes (Bcfe)*	0.9		0.6		0.3		50.0	%
Total Shale Sales Volumes (Bcfe)*	431.7		448.1		(16.4)		(3.7)	%

Average Shale Gas Sales Price (per Mcf)	$	3.04	$	2.89	$	0.15	5.2	%
Loss on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	(0.30)	$	(0.28)	$	(0.02)	(7.1)	%
Average Sales Price - NGLs (per Mcfe)*	$	4.14	$	3.69	$	0.45	12.2	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	11.32	$	9.11	$	2.21	24.3	%

Total Average Shale Sales Price (per Mcfe)	$	2.89	$	2.70	$	0.19	7.0	%
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)	0.59		0.53		0.06		11.3	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.79		0.82		(0.03)		(3.7)	%
Total Average Shale Production Costs (per Mcfe)	$	1.53	$	1.52	$	0.01	0.7	%
Total Average Shale Production Margin (per Mcfe)	$	1.36	$	1.18	$	0.18	15.3	%

* 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 last quarter of 2025 and throughout 2026.

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,365 million for the nine months ended September 30, 2026 compared to $1,326 million for the nine months ended September 30, 2025. The $39 million increase was primarily due to a 5.2% increase in the average sales price for natural gas and a 12.2% increase in the average sales price of NGLs. These increases were offset, in part, by a 7.1% increase in the loss on commodity derivative instruments and a 3.7% decrease in total Shale sales volumes.

The Shale segment had a loss on commodity derivative instruments - cash settlements of $117 million for the nine months ended September 30, 2026 compared to a loss of $115 million for the nine months ended September 30, 2025. The notional amounts associated with these financial hedges represented approximately 323.7 Bcf of the Company's produced Shale gas sales volumes for the nine months ended September 30, 2026 at an average loss of $0.36 per Mcf hedged. For the nine months ended September 30, 2025, these financial hedges represented approximately 339.0 Bcf at an average loss of $0.34 per Mcf hedged.

The $0.19 per Mcfe increase in total average Shale sales price was primarily due to a $0.15 per Mcf increase in average gas sales price and a $0.45 per Mcfe increase in the average NGL sales price. These increases were offset, in part, by a $0.02 per Mcf change in the loss on commodity derivative instruments - cash settlements.

Total operating costs and expenses for the Shale segment were $658 million for the nine months ended September 30, 2026 compared to $682 million for the nine months ended September 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 $47 million for the nine months ended September 30, 2026 compared to $59 million for the nine months ended September 30, 2025. The decrease in total dollars and unit costs was primarily due to lower water disposal costs as more water was reused in well completion activities rather than taken to disposal. The per unit decrease was offset, in part, by the overall decrease in total sales volumes.

•Shale production, ad valorem and other fees were $17 million for the nine months ended September 30, 2026 compared to $20 million for the nine months ended September 30, 2025. The decrease in total dollars was primarily due to lower Shale gas sales volumes, while unit costs remained flat in the period-to-period comparison.

•Shale transportation, gathering and compression costs were $255 million for the nine months ended September 30, 2026 compared to $238 million for the nine months ended September 30, 2025. The increase in total dollars and unit costs was primarily due to higher repairs and maintenance expense, increased processing costs resulting from production mix and increased utilization of firm transportation capacity in our central Pennsylvania operating area. 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 $339 million for the nine months ended September 30, 2026 compared to $365 million for the nine months ended September 30, 2025. These amounts included depletion on a unit of production basis of $0.68 per Mcfe and $0.71 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 $46 million for the nine months ended September 30, 2026 compared to $52 million for the nine months ended September 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 $1 million for the nine months ended September 30, 2026 compared to a loss before income tax of $14 million for the nine months ended September 30, 2025.


	For the Nine Months Ended September 30,
	2026		2025		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	28.3		28.4		(0.1)		(0.4)	%

Average CBM Gas Sales Price (per Mcf)	$	4.18	$	3.85	$	0.33	8.6	%
Loss on Commodity Derivative Instruments - Cash Settlement (per Mcf)	$	(0.24)	$	(0.27)	$	0.03	11.1	%

Total Average CBM Sales Price (per Mcf)	$	3.94	$	3.58	$	0.36	10.1	%
Average CBM Lease Operating Expenses (per Mcf)	0.67		0.65		0.02		3.1	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.18		0.17		0.01		5.9	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	1.56		1.74		(0.18)		(10.3)	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.57		1.53		0.04		2.6	%
Total Average CBM Production Costs (per Mcf)	$	3.98	$	4.09	$	(0.11)	(2.7)	%
Total Average CBM Production Margin (per Mcf)	$	(0.04)	$	(0.51)	$	0.47	92.2	%

The CBM segment had natural gas revenue of $118 million for the nine months ended September 30, 2026 compared to $109 million for the nine months ended September 30, 2025. The $9 million increase was due to an 8.6% increase in the average sales price for natural gas in the current period, offset, in part, by a 0.4% decrease in CBM gas sales volumes due to normal production declines.

The total average CBM sales price increased $0.36 per Mcf due to a $0.33 per Mcf increase in average natural gas sales price and a $0.03 per Mcf decrease in the loss on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 21.5 Bcf of the Company's produced CBM sales volumes for the nine months ended September 30, 2026 at an average loss of $0.32 per Mcf hedged. For the nine months ended September 30, 2025, these financial hedges represented approximately 21.8 Bcf at an average loss of $0.36 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $112 million for the nine months ended September 30, 2026 compared to $115 million for the nine months ended September 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 $19 million for the nine months ended September 30, 2026 compared to $18

million for the nine months ended September 30, 2025. The increase in total dollars and unit costs was primarily due to an increase in repairs and maintenance expense.

•CBM production, ad valorem and other fees were $5 million for both the nine months ended September 30, 2026 and 2025. The increase in unit costs was primarily due to higher realized natural gas prices.

•CBM transportation, gathering and compression costs were $44 million for the nine months ended September 30, 2026 compared to $49 million for the nine months ended September 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 $44 million for the nine months ended September 30, 2026 compared to $43 million for the nine months ended September 30, 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 $249 million for the nine months ended September 30, 2026 compared to earnings before income tax of $12 million for the nine months ended September 30, 2025. The increase in total dollars is discussed below.


	For the Nine Months Ended September 30,
	2026	2025	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.2	0.2	-	-	%

Unrealized Gain on Commodity Derivative Instruments

For the nine months ended September 30, 2026, the Other Segment recognized an unrealized gain on commodity derivative instruments of $465 million. For the nine months ended September 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $148 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 $30 million for the nine months ended September 30, 2026 compared to $31 million for the nine months ended September 30, 2025. Purchased gas costs were $30 million for the nine months ended September 30, 2026 compared to $29 million for the nine months ended September 30, 2025. The period-to-period decrease in purchased gas revenue was primarily due to a decrease in average sales price offset, in part, by an increase in purchased gas sales volumes.


	For the Nine Months Ended September 30,
	2026		2025		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	9.8		9.4		0.4		4.3	%
Average Sales Price (per Mcf)	$	3.00	$	3.29	$	(0.29)	(8.8)	%
Purchased Gas Average Cost (per Mcf)	$	3.02	$	3.09	$	(0.07)	(2.3)	%

Other Operating Income


	For the Nine Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Excess Firm Transportation Income	$	28	$	12	$	16	133.3	%
Equity Loss from Affiliates	(2)		(1)		(1)		(100.0)	%
Water Income	11		12		(1)		(8.3)	%
Sales of Environmental Attributes	47		61		(14)		(23.0)	%
Total Other Operating Income	$	84	$	84	$	-	-	%

•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 Nine Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Lease Expiration Costs	$	4	$	1	$	3	300.0	%
Land Rentals	4		5		(1)		(20.0)	%
Other	1		-		1		100.0	%
Total Exploration and Production Related Other Costs	$	9	$	6	$	3	50.0	%

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

SG&A


	For the Nine Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Short-term Incentive Compensation	$	9	$	8	$	1	12.5	%
Salaries, Wages and Employee Benefits	22		22		-		-	%
Long-term Equity-Based Compensation (Non-Cash)	19		19		-		-	%
Contributions and Advertising	4		5		(1)		(20.0)	%
Other	47		44		3		6.8	%
Total SG&A	$	101	$	98	$	3	3.1	%

•Other increased in the period-to-period comparison primarily due to various other one-time items, none of which were individually material.

Other Operating Expense


	For the Nine Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	14	$	30	$	(16)	(53.3)	%
Idle Equipment and Service Charges	1		3		(2)		(66.7)	%
Inventory Adjustments	-		1		(1)		(100.0)	%
Insurance Expense	2		3		(1)		(33.3)	%
Environmental Attribute Fees	7		8		(1)		(12.5)	%
Water Expense	2		1		1		100.0	%
Other	13		8		5		62.5	%
Total Other Operating Expense	$	39	$	54	$	(15)	(27.8)	%

•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, including net credits recognized related to capacity optimization driven by colder weather earlier in the year, which reduced the Company's overall expenses.

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

•Other increased in the period-to-period comparison due to an adjustment related to the resolution of ownership-related matter involving certain oil and gas rights, which resulted in a reduction of the Company's net revenue interest in the affected wells.

Other Expense


	For the Nine Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Other Income
Right-of-Way Sales	$	5	$	2	$	3	150.0	%
Interest Income	1		1		-		-	%
Other	8		3		5		166.7	%
Total Other Income	$	14	$	6	$	8	133.3	%

Other Expense
Professional Services	$	7	$	3	$	4	133.3	%
Bank Fees	8		8		-		-	%
Other Corporate Expense	5		4		1		25.0	%
Total Other Expense	$	20	$	15	$	5	33.3	%

Total Other Expense	$	6	$	9	$	(3)	(33.3)	%

•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.

•The increase in other income was primarily due to proceeds received in connection with the settlement of a contractual matter.

•The increase in professional services expense was primarily attributable to transaction costs related to the monetization of federal tax credits.

Gain on Asset Sales and Abandonments, net

A net gain on asset sales and abandonments of $9 million was recognized in the nine months ended September 30, 2026 compared to a net gain of $95 million in the nine months ended September 30, 2025. The net gain recognized in the nine months ended September 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 nine months ended September 30, 2025 primarily relates to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million. The remaining net gain during the period primarily relates to sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material. 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 nine months ended September 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 Nine Months Ended September 30,
(in millions)	2026		2025		Variance		Percent Change
Total Interest Expense	$	119	$	129	$	(10)	(7.8)	%

The $10 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 Nine Months Ended September 30,
(in millions)	2026			2025			Variance			Percent Change
Total Company Earnings Before Income Tax	$	885		$	579		$	306		52.8	%
Income Tax Expense	$	168		$	142		$	26		18.3	%
Effective Income Tax Rate	19.0		%	24.5		%	(5.5)		%

The effective income tax rates for the nine months ended September 30, 2026 and 2025 were 19.0% and 24.5%, respectively. The effective tax rate for the nine months ended September 30, 2026 and 2025 differs from the U.S. federal statutory rate of 21% primarily due to the impact of federal tax credits, equity compensation 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 September 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 $4 million as of September 30, 2026 and $13 million as of December 31, 2025.

•Accounts and notes receivable - trade were $141 million as of September 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 $571 million to $586 million for the year ended December 31, 2026. For the nine months ended September 30, 2026, CNX had capital expenditures of $451 million.

•Production volumes are expected to range between 612.5 Bcfe and 617.5 Bcfe for the year ended December 31, 2026. For the nine months ended September 30, 2026, CNX had production volumes of 460.2 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 $254 million at September 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 Nine Months Ended September 30,
	2026		2025		Change
Cash Provided by Operating Activities	$	811	$	732	$	79
Cash Used in Investing Activities	$	(418)	$	(736)	$	318
Cash Used in Financing Activities	$	(401)	$	(33)	$	(368)

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

•Net income increased $279 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, partially offset by an $86 million decrease in gain on asset sales and abandonments, a $20 million net increase in deferred income taxes, a $12 million increase in loss on debt extinguishment and a $45 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 $130 million primarily due to an increase in drilling and completions activity.

•Proceeds from asset sales decreased $56 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 nine months ended September 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 nine months ended September 30, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $518 million, subject to certain post-closing adjustments See Note 4 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

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

•Proceeds from borrowings under the CNXM Credit Facility increased $20 million and repayments under the CNXM Credit Facility decreased $10 million.

•Proceeds from borrowings under the CNX Credit Facility decreased $25 million and repayments under the CNX Credit Facility increased $146 million.

•During the nine months ended September 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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2026, CNX repurchased $435 million of its common stock on the open market compared to $423 million during the nine months ended September 30, 2025.

•During the nine months ended September 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 September 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	$	4,632	$	5,398	$	590	$	-	$	10,620
Gas Firm Transportation and Processing	251,912		372,908		230,766		382,278		1,237,864
Long-Term Debt	-		299,850		894,698		1,095,467		2,290,015
Interest on Long-Term Debt	145,578		284,144		220,907		95,188		745,817
Finance Lease Obligations	5,753		14,351		6,033		7,108		33,245
Interest on Finance Lease Obligations	1,943		2,694		1,328		411		6,376
Operating Lease Obligations	45,364		57,491		10,861		3,025		116,741
Interest on Operating Lease Obligations	5,809		4,075		850		768		11,502
Long-Term Liabilities-Employee Related (a)	2,810		5,508		5,299		17,942		31,559
Other Long-Term Liabilities (b)	199,365		32,400		22,000		143,968		397,733
Total Contractual Obligations (c)	$	663,166	$	1,078,819	$	1,393,332	$	1,746,155	$	4,881,472

_________________________

(a)Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.

(b)Other long-term liabilities include royalties and other long-term liability costs.

(c)The table above does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

Debt

At September 30, 2026, CNX had total debt of $2,290 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 $3 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 $233 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 $67 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 $4,834 million at September 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 September 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.

CNX Resources Corporation published this content on October 29, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on October 29, 2026 at 17:47 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]

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