CNX

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. 30 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. 31 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. 32 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. 33 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) 34 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. 35 •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 36 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) % 37 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. 38 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. 39 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. 40 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 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 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 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. 41 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 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 *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 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. 42 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 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. 43 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 44 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. 45 •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. 46 •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 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 $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) % 47 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. •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 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 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 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) % 48 •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) % •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. •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) % 49 •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. 50 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. 51 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. 52 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. 53 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 54 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; 55 •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. 56