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Item 7. Management’s Discussion and Analysis

2026-02-10 compared with 2025-02-11 · 128 added, 131 removed, 433 unchanged (37% of the section changed)

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CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations.

Examples include global events such as the conflict between Russia and Ukraine and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, both of which have had an impact on global commodity prices.

Examples include global events such as the current uncertainties in global financial markets, geopolitical tensions and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, all of which have had an impact on global commodity prices.

These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years.

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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.

New Technologies Update

For the years ended December 31, 2024 and 2023, CNX recognized $95 million and $41 million of sales of environmental attributes which includes items such as (but is 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.

These sales are included as part of Other Revenue and Operating Income in the Other Segment.

For the year ended December 31, 2024 and 2023, CNX incurred $15 million and $7 million of environmental attribute fees which represent costs related to the sale of environmental attributes and are included in Other Operating Expense in the Other Segment.

On January 3, 2025, the Department of the Treasury issued final rules regarding the Inflation Reduction Act’s Section 45V Hydrogen Production Tax Credit.

The Department of Treasury's recognition of captured waste coal mine methane (CMM) as a feedstock for hydrogen production is validation of its inherent environmental and economic benefits and an important step in continuing to monetize the value of this unique asset.

The Company has now successfully validated the premium pricing that low-carbon intensity waste methane capture (CMM) blends enjoy in the manufacturing, hydrogen production, and power generation sectors.

However, CNX believes that the final 45V implementation rules are overly restrictive across a range of feedstocks and do not currently appear to create sufficient economic incentives for the Company to expand its CMM capture operations for hydrogen end use.

Notwithstanding the specifics of the 45V rule, the Company intends to utilize this important validation of the product to pursue other incentive pathways across these sectors, as well as establish similar markets in artificial intelligence (AI) data centers, transportation, aviation, voluntary market platforms, and government/regulatory platforms arenas.

2025 Highlights:

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• Shale sales volumes of 590.8 Bcfe

• Repurchased 7.2 million shares of CNX common stock for $179 million on the open market at an average price of $24.68.

• Repurchased 16.9 million shares of CNX common stock for $528 million on the open market at an average price of $31.00 (see Note 5 – Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).

• On January 27, 2025, CNX completed the acquisition of Apex Energy II, LLC, (“the Apex Transaction”) for cash consideration of approximately $518 million (see Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).

2026 Outlook:

• On January 21, 2025, the Company closed on a private offering of $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of their principal amount, plus accrued interest from September 1, 2024 to the date of closing.

See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

• On January 27, 2025, the Company completed the acquisition of the natural gas upstream and associated midstream business of Apex Energy II, LLC (“the Apex Transaction") for total cash consideration of approximately $505 million, subject to certain adjustments.

See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

• Our 2026 annual sales volumes are expected to be approximately 605 - 620 Bcfe.

• Our 2026 capital expenditures are expected to be approximately $556 - $586 million.

• Our 2025 sales of environmental attributes, net of corresponding fees, are expected to be approximately $75 million.

However, our ability to sell environmental attributes can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in "Item 1A.

Risk Factors" of this Form 10-K.

• CNX’s 2026 capital expenditures includes the first of three annual payments of $16 million associated with an agreement that grants CNX the right to acquire Utica Shale oil and gas rights that sit beneath the legacy Apex Energy footprint.

Results of Operations:

The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 2025 to the year ended December 31, 2024.

A similar discussion and analysis that compares year ended December 31, 2023 to the fiscal year ended December 31, 2022 is omitted from this Form 10-K and may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.

Net (Loss) Income

CNX reported a net loss of $90 million, or a loss per diluted share of $0.60, for the year ended December 31, 2024, compared to net income of $1,721 million, or earnings per diluted share of $8.99, for the year ended December 31, 2023.

Included in the net loss for the year ended December 31, 2024 was an unrealized loss on commodity derivative instruments of $453 million and a net gain on asset sales and abandonments of $25 million.

A similar discussion and analysis that compares year ended December 31, 2024 to the fiscal year ended December 31, 2023 is omitted from this Annual Report on Form 10-K and may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Annual Report on Form 10-K for the year ended December 31, 2024, which is incorporated herein by reference.

Net Income (Loss)

CNX reported net income of $633 million, or earnings per diluted share of $3.98, for the year ended December 31, 2025, compared to a net loss of $90 million, or a loss per diluted share of $0.60, for the year ended December 31, 2024.

Included in earnings for the year ended December 31, 2025 was an unrealized gain on commodity derivative instruments of $278 million and a net gain on asset sales and abandonments of $97 million.

Included in the net loss for the year ended December 31, 2024 was an unrealized loss on commodity derivative instruments of $453 million and a net gain on asset sales and abandonments of $25 million.

See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the gain on asset sales and abandonments.

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Purchased Gas Revenue (45) (59)

Loss (Gain) on Commodity Derivative Instruments - Unrealized 453 (1,765)

(Gain) Loss on Commodity Derivative Instruments - Unrealized (278) 453

Other Revenue and Operating Income (183) (194)

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Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1

$ 1,065 $ 950

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

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Natural Gas, NGL and Oil Revenue $ 1,914 $ 3.06 $ 1,186 $ 2.09 $ 728 $ 0.97

Gain on Commodity Derivative Instruments - Cash Settlement 281 0.57 163 0.32 118 0.25

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement (181) (0.31) 281 0.57 (462) (0.88)

Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure

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*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.

The 9.6 Bcfe decrease in total sales volumes in the period-to-period comparison was primarily due to a 17.7 Bcfe decrease in natural gas sales volumes resulting from normal production declines and the timing of when new wells were turned-in-line after the 2023 period.

The decrease was offset, in part, by an 8.5 Bcfe increase in NGL sales volumes primarily due to an increase in ethane recoveries.

The 78.2 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information) and the timing of when new wells were turned-in-line.

The increase in volumes was offset, in part, by normal production declines.

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

• Lease operating expense increased on a per unit basis primarily due to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense.

• Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a higher annual depletion rate for 2024.

The increases were offset, in part, by the overall increase in total sales volumes.

• Transportation, gathering and compression expense decreased on a per unit basis primarily due to the overall increase in total sales volumes, a decrease in processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes.

The per unit decreases were offset, in part, by higher repairs and maintenance expense.

• Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate.

The increases were offset, in part, by the overall increase in total sales volumes.

Average Realized Price Reconciliation

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Hedging Impact ($/Mcf) $ (0.31) $ 0.57 $ (0.88) (154.4) %

Gain on Commodity Derivative Instruments - Cash Settlement $ 281,195 $ 163,026 $ 118,169 (72.5) %

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure, was primarily due to the impact of the change in the gain on commodity derivative instruments - cash settlement related to the Company's hedging program, the 8.5 Bcfe increase in NGL sales volumes and the $0.36 per barrel increase in NGL prices.

These increases were offset, in-part, by the $0.22 per Mcf decrease in natural gas sales price, when excluding the impact of hedging, and the 17.7 Bcf decrease in natural gas sales volume.

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement $ (181,020) $ 281,195 $ (462,215) (164.4) %

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure, was primarily due to the 83.7 Bcf increase in natural gas sales volumes and the $1.01 per Mcf increase in natural gas sales price, when excluding the impact of hedging.

These increases were offset, in-part, by the impact of the change in the (loss) gain on commodity derivative instruments - cash settlement related to the Company's hedging program, the 5.5 Bcfe decrease in NGL sales volumes and the $0.30 per barrel decrease in NGL prices.

SEGMENT ANALYSIS for the year ended December 31, 2025 compared to the year ended December 31, 2024:

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Natural Gas, NGLs and Oil Revenue $ 1,764 $ 148 $ 2 $ 1,914 $ 684 $ 43 $ 1 $ 728

Gain (Loss) on Commodity Derivative Instruments 260 21 (453) (172) 109 9 (2,218) (2,100)

(Loss) Gain on Commodity Derivative Instruments (170) (11) 278 97 (430) (32) 731 269

Purchased Gas Revenue — — 45 45 — — (14) (14)

Other Revenue and Operating Income 69 — 114 183 1 — (12) (11)

Total Revenue (Loss) and Other Operating Income 1,408 126 (267) 1,267 20 (17) (2,171) (2,168)

Total Revenue and Other Operating Income 1,663 137 439 2,239 255 11 706 972

Lease Operating Expense 73 24 — 97 25 2 — 27

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Total Operating Costs and Expenses 903 154 291 1,348 112 2 (26) 88

Other (Income) Expense — — (6) (6) — — (15) (15)

Other Expense — — 14 14 — — 20 20

Gain on Asset Sales and Abandonments, net — — (97) (97) — — (72) (72)

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Average Sales Price - Gas (per Mcf) $ 2.93 $ 1.92 $ 1.01 52.6 %

Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) $ 0.57 $ 0.32 $ 0.25 78.1 %

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) $ (0.31) $ 0.57 $ (0.88) (154.4) %

Average Sales Price - NGLs (per Mcfe)* $ 3.55 $ 3.60 $ (0.05) (1.4) %

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The increase in total Shale sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information) and the timing of when new wells were turned-in-line.

The increase in volumes was offset, in part, by normal production declines.

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,764 million for the year ended December 31, 2025 compared to $1,080 million for the year ended December 31, 2024.

The $90 million decrease was due primarily to a 9.0% decrease in the average sales price for natural gas and a 3.4% decrease in Shale gas sales volumes primarily due to normal production declines and the timing of when new wells were turned-in-line.

The decrease was offset, in part, by a 19.1% increase in NGLs sales volumes due to an increase in ethane recoveries and a 1.7% increase in the average sales price for NGLs.

The increase in total average Shale sales price was primarily due to a $0.25 per Mcf change in the gain on commodity derivative instruments - cash settlement and a $0.06 per Mcfe increase in the average NGL sales price.

These increases were offset in part by a $0.19 per Mcf decrease in average gas sales price.

The notional amounts associated with these financial hedges represented approximately 389.7 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2024 at an average gain of $0.67 per Mcf hedged.

The $684 million increase was due primarily to a 52.6% increase in the average sales price for natural gas and an 18.6% increase in Shale gas sales volumes.

These increases were offset, in part, by a 10.6% decrease in NGLs sales volumes and a 1.4% decrease in the average sales price for NGLs.

The increase in total average Shale sales price was primarily due to a $1.01 per Mcf increase in average gas sales price.

These increases were offset, in part, by a $0.88 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements and a $0.05 per Mcfe decrease in the average NGL sales price.

The notional amounts associated with these financial hedges represented approximately 452.6 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2025 at an average loss of $0.38 per Mcf hedged.

For the year ended December 31, 2024, these financial hedges represented approximately 389.7 Bcf at an average gain of $0.67 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $903 million for the year ended December 31, 2025 compared to $791 million for the year ended December 31, 2024.

The increases in total dollars and unit costs for the Shale segment were due to the following items:

The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:

• Shale lease operating expenses were $73 million for the year ended December 31, 2025 compared to $48 million for the year ended December 31, 2024.

The increase in total dollars was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense.

• Shale transportation, gathering and compression costs were $316 million for both the years ended December 31, 2024 and 2023.

The increase in unit costs was due to the decrease in total Shale sales volumes.

The increase in total dollars and unit costs was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions, higher well tending expense and higher repairs and maintenance expense.

The increase in unit costs was offset, in part, by the increase in total Shale sales volumes.

• Shale production, ad valorem and other fees were $25 million for the year ended December 31, 2025 compared to $22 million for the year ended December 31, 2024.

The increase in total dollars was primarily due to increased realized prices on natural gas and a change in production mix by state.

Unit costs remained flat in the period-to-period comparison due to the overall increase in volumes.

• Shale transportation, gathering and compression costs were $317 million for the year ended December 31, 2025 compared to $316 million for the year ended December 31, 2024.

The increase in total dollars was primarily due to higher repairs and maintenance and electrical compression expense offset, in part, by lower processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes.

The decrease in unit costs was due to the increase in total Shale sales volumes.

• Depreciation, depletion and amortization costs attributable to the Shale segment were $488 million for the year ended December 31, 2025 compared to $405 million for the year ended December 31, 2024.

These amounts included depletion on a unit of production basis of $0.72 per Mcfe and $0.68 per Mcfe, respectively.

The increase in the units of production depreciation, depletion and amortization rate in the current period is primarily due to a higher annual depletion rate for 2024.

The increase in rate is primarily attributable to downward reserve revisions due to adjustments to the five-year development plan that lowered proved undeveloped reserves, price changes, and the sale of various non-operated producing oil and gas assets The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

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.

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COALBED METHANE (CBM) SEGMENT

The CBM segment had a loss before income tax of $26 million for the year ended December 31, 2024 compared to earnings before income tax of $1 million for the year ended December 31, 2023.

The CBM segment had a loss before income tax of $17 million for the year ended December 31, 2025 compared to a loss before income tax of $26 million for the year ended December 31, 2024.

For the Years Ended December 31,

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Average Sales Price - Gas (per Mcf) $ 3.91 $ 2.69 $ 1.22 45.4 %

Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.53 $ 0.28 $ 0.25 89.3 %

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ (0.30) $ 0.53 $ (0.83) (156.6) %

Total Average CBM Sales Price (per Mcf) $ 3.61 $ 3.21 $ 0.40 12.5 %

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The CBM segment had natural gas revenue of $148 million for the year ended December 31, 2025 compared to $105 million for the year ended December 31, 2024.

The $26 million decrease was primarily due to a 16.5% decrease in the average sales price for natural gas in the current period and a 3.7% decrease in CBM gas sales volumes due to normal production declines.

The total average CBM sales price decreased $0.30 per Mcf due to a $0.53 per Mcf decrease in average gas sales price, offset, in part, by a $0.25 per Mcf change in the gain on commodity derivative instruments - cash settlement resulting from the Company's hedging program.

The notional amounts associated with these financial hedges represented approximately 30.6 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2024 at an average gain of $0.67 per Mcf hedged.

The $43 million increase was primarily due to a 45.4% increase in the average sales price for natural gas in the current period offset, in part, by a 3.3% decrease in CBM sales volumes due to normal production declines.

The total average CBM sales price increased $0.40 per Mcf due to a $1.22 per Mcf increase in average gas sales price, offset, in part, by a $0.83 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements.

The notional amounts associated with these financial hedges represented approximately 29.5 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2025 at an average loss of $0.39 per Mcf hedged.

For the year ended December 31, 2024, these financial hedges represented approximately 30.6 Bcf at an average gain of $0.67 per Mcf hedged.

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• CBM lease operating expense was $24 million for the year ended December 31, 2025 compared to $22 million for the year ended December 31, 2024.

The increase in total dollars and unit costs was primarily due to an increase in well tending expense and water disposal costs.

The increase in total dollars and unit costs was primarily due to an increase in repair and maintenance and well tending expense.

The increase in per unit costs was also due to the decrease in total CBM volumes.

• CBM production, ad valorem and other fees were $6 million for the year ended December 31, 2024 compared to $7 million for the year ended December 31, 2023.

The decreases in total dollars and unit costs were primarily due to decreased realized prices on natural gas.

• CBM transportation, gathering and compression costs were $64 million for the year ended December 31, 2024 compared to $66 million for the year ended December 31, 2023.

The decrease in total dollars was primarily due to a decrease in repairs and maintenance expense offset, in part, by an increase in electrical compression expense.

The increase in per unit costs was due to the decrease in CBM gas sales volumes.

• Depreciation, depletion and amortization costs attributable to the CBM segment were $60 million for the year ended December 31, 2024 compared to $50 million for the year ended December 31, 2023.

These amounts included depletion on a unit of production basis of $0.85 per Mcfe and $0.64 per Mcfe, respectively.

The increase in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a higher 2024 annual depletion rate.

The increase in rate is primarily attributable to downward reserve revisions due to higher operating costs and price changes.

• CBM production, ad valorem and other fees were $6 million for both the years ended December 31, 2025 and 2024.

The increase in unit costs was primarily due to the decrease in total CBM volumes.

• CBM transportation, gathering and compression costs were $64 million for both the years ended December 31, 2025 and 2024.

The increase in per unit costs was also due to the decrease in CBM gas sales volumes.

• Depreciation, depletion and amortization costs attributable to the CBM segment were $60 million for both the years ended December 31, 2025 and 2024.

These amounts also included depletion on a unit of production basis of $0.85 per Mcfe for both periods.

The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

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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, New Technologies, 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 (“SG&A”), interest expense and income taxes.

The Other Segment had a loss before income tax of $711 million for the year ended December 31, 2024 compared to earnings before income tax of $1,580 million for the year ended December 31, 2023.

The decrease in total dollars is discussed below.

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 $60 million for the year ended December 31, 2025 compared to a loss before income tax of $711 million for the year ended December 31, 2024.

The increase in total dollars is discussed below.

For the Years Ended December 31,

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Other Gas Sales Volumes (Bcf) 0.3 0.3 — — %

(Loss) Gain on Commodity Derivative Instruments - Unrealized

For the year ended December 31, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $453 million.

Oil/Condensate Sales Volumes (Bcfe)* 0.1 — 0.1 100.0 %

Total Other Sales Volumes (Bcfe)* 0.4 0.3 0.1 33.3 %

*Oil/Condensate is 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 and natural gas prices.

Unrealized Gain (Loss) on Commodity Derivative Instruments

For the year ended December 31, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $278 million.

The unrealized loss or 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.

For the year ended December 31, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $453 million.

The unrealized gain (loss) on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.

Purchased Gas Revenue and Costs

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Purchased gas costs were $43 million for the year ended December 31, 2025 compared to $57 million for the year ended December 31, 2024.

The period-to-period decrease in purchased gas revenue was due to a decrease in average sales price.

The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes.

For the Years Ended December 31,

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Sales of Environmental Attributes $ 78 $ 95 $ (17) (17.9) %

Water Income 12 3 9 300.0 %

Excess Firm Transportation Income 22 20 2 10.0 %

(Loss) Equity Income from Affiliates (1) 3 (4) (133.3) %

Water Income 15 12 3 25.0 %

Equity Loss from Affiliates (1) (1) — — %

Total Other Revenue and Operating Income $ 114 $ 126 $ (12) (9.5) %

• Sales of environmental attributes includes items such as (but are not limited to):

• 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 increase in the period-to-period comparison was due to an increase in the amount of environmental attributes sold.

• Water income increased in the period-to-period comparison due to higher third-party sales in the current period.

The decrease in the period-to-period comparison was due to a decrease in the amount of environmental attributes sold and a decrease in the price received.

• Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third parties.

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The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in Total Other Operating Expense.

• (Loss) equity income from affiliates represents CNX’s share of earnings and losses from various entities, including interests in various oilfield service companies and an interest in a gas-fired generation facility located within CNX’s CBM field.

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

Water income increased in the period-to-period comparison primarily due to an increase in third-party sales in the current period.

Exploration and Production Related Other Costs

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(in millions) 2025 2024 Variance Percent Change

Lease Expiration Costs $ 4 $ 6 $ (2) (33.3) %

Seismic Activity $ 2 $ — $ 2 100.0 %

Land Rentals 4 3 1 33.3 %

Lease Expiration Costs 3 4 (1) (25.0) %

Other Expense 2 1 1 100.0 %

Total Exploration and Production Related Other Costs $ 11 $ 8 $ 3 37.5 %

• Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months.

The decrease in the year ended December 31, 2024 was primarily due to a decrease in the number of acres that were allowed to expire.

• Seismic activity expense in the current period primarily relates to the acquisition of three-dimensional seismic data.

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.

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(in millions) 2025 2024 Variance Percent Change

Salaries, Wages and Employee Benefits $ 26 $ 30 $ (4) (13.3) %

Short-Term Incentive Compensation 22 23 (1) (4.3) %

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Long-Term Equity-Based Compensation (Non-Cash) 24 20 4 20.0 %

Salaries, Wages and Employee Benefits 30 31 (1) (3.2) %

Other 62 68 (6) (8.8) %

Total SG&A $ 140 $ 146 $ (6) (4.1) %

• Short-term incentive compensation increased $12 million due to higher projected payouts for the current period.

• Other increased in the period-to-period comparison primarily due to higher professional services and consulting fees, as well as increased software costs.

• Salaries, wages and employee benefits decreased in the period-to-period comparison due to a reduction in headcount that occurred at the end of the first quarter of 2025.

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

• 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

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(in millions) 2025 2024 Variance Percent Change

Unutilized Firm Transportation and Processing Fees $ 38 $ 48 $ (10) (20.8) %

Environmental Attribute Fees 11 15 (4) (26.7) %

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Insurance Expense 4 4 — — %

Virginia Flood Expense (1) 2 (3) (150.0) %

Inventory Adjustments 2 2 — — %

Unutilized Firm Transportation and Processing Fees 48 53 (5) (9.4) %

Virginia Flood Expense — (1) 1 (100.0) %

Other 9 9 — — %

Total Other Operating Expense $ 69 $ 83 $ (14) (16.9) %

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

The increase in fees in the period-to-period comparison relates to the increase in sales above.

• Idle equipment and service charges relate to the temporary idling of certain equipment and other services that may be needed in the natural gas drilling and completions process.

• Virginia flood expense includes costs to cleanup and repair areas that were impacted by flooding that occurred in Buchanan County, Virginia in July 2022.

The income in the current period relates to an insurance reimbursement for prior expenses incurred.

• Inventory adjustments represent required adjustments made to record inventory at the lower of cost or net realizable value.

• 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.

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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 results primarily from lower unused processing costs due to the higher NGL volumes in the 2024 period.

• Other includes several one-time items in the period-to-period comparison, including $2 million of expenses for our previously announced radical transparency program and a $3 million charge related to a prior-year sales and use tax audit settlement that occurred in the current period.

Both periods also include various other one-time items, none of which are individually material.

Other (Income) Expense

The decrease in period-to-period comparison was primarily due to lower fees in the current period, resulting from capacity optimization driven by colder weather in the earlier part of the year.

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

The decrease in fees in the period-to-period comparison relates to the decrease in sales above.

Other Expense (Income)

For the Years Ended December 31,

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Litigation Recoveries $ 1 $ 20 $ (19) (95.0) %

Interest Income 1 2 (1) (50.0) %

Right-of-Way Sales 2 1 1 100.0 %

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Other Expense

Other Land Rental Expense $ 3 $ 3 $ — — %

Professional Services 4 5 (1) (20.0) %

Bank Fees 10 11 (1) (9.1) %

Other Land Rental Expense 3 3 — — %

Other Corporate Expense 4 — 4 100.0 %

Total Other Expense $ 21 $ 19 $ 2 10.5 %

Total Other (Income) Expense $ (6) $ 9 $ (15) (166.7) %

• Right of way sales relate to additional revenue generated from the Company's extensive surface rights.

The decrease of $4 million in the period-to-period comparison was due to fewer sales in the current period.

• Professional services increased in the period-to-period comparison primarily due to higher fees associated with various one-time items such as the Apex Transaction that closed on January 27, 2025 (See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).

Total Other Expense (Income) $ 14 $ (6) $ 20 333.3 %

• CNX pursues legal recoveries when certain circumstances arise.

The increase in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in the current period.

No such transactions occurred in the prior period.

The decrease in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in the prior period.

• Other corporate expense primarily consists of severance expense related to the reduction in headcount that occurred at the end of the first quarter of 2025.

Gain on Asset Sales and Abandonments, net

A net gain on asset sales of $25 million was recognized in the year ended December 31, 2024, compared to a gain of $132 million in the year ended December 31, 2023.

The net gain recognized during the year ended December 31, 2024 primarily relates to a $51 million gain on the sales of various non-core assets (primarily rights-of-way, surface acreage and the interest in various non-operated oil and gas assets), none of which were individually material.

A net gain on asset sales of $97 million was recognized in the year ended December 31, 2025, compared to a net gain of $25 million in the year ended December 31, 2024.

The net gain recognized during the year ended December 31, 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.

The remaining net gain during the period primarily relates to sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material.

The net gain during the year ended December 31, 2024 primarily relates to a $51 million gain on the sale of various non-core assets (primarily rights-of-way, surface acreage and the interest in various non-operated oil and gas assets), none of which were individually material.

These gains were offset, in part, by a $26 million loss on the sale of a non-core pipeline to a third party.

The net gain during the year ended December 31, 2023 primarily relates to a $100 million gain on the sale of various non-operated producing oil and gas assets primarily located in the Appalachian Basin to a third party (See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The remaining gain relates to the sale of various non-core assets (primarily rights-of-way and surface acreage), none of which were individually material.

See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Loss on Debt Extinguishment

A loss on debt extinguishment of $7 million was recognized in the year ended December 31, 2024 in connection with CNX’s repurchase of $350 million of the 7.25% Senior Notes due March 2027 at an average price equal to 101.9% of their principal amount.

A loss on debt extinguishment of $1 million was recognized in the year ended December 31, 2025, compared to $7 million in the year ended December 31, 2024.

The loss recognized during the year ended December 31, 2025 was in connection with CNX’s issuance of common stock in exchange for $122 million aggregate principal amount of its 2.25% Convertible Notes due May 2026.

See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

No such transactions occurred in the prior period.

The loss recognized during the year ended December 31, 2024 was in connection with CNX’s repurchase of $350 million aggregate principal amount of its 7.25% Senior Notes due March 2027 at an average price equal to 101.9% of their principal amount.

See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Interest Expense

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Total Interest Expense $ 170 $ 151 $ 19 12.6 %

The $8 million increase in total interest expense was primarily due to higher borrowings on the CNX Credit Facility at higher interest rates and higher principal balances related to the long-term debt that was issued in February 2024.

The increase was offset, in part, by lower borrowings on the CNXM Credit Facility.

The $19 million increase in total interest expense was primarily due to higher borrowings on both the CNX and CNXM Credit Facilities and higher principal balances related to the long-term debt that was issued in 2025.

The increase was offset, in part, by lower weighted average interest rates on both the CNX and CNXM Credit Facilities.

See Note 10 – Revolving Credit Facilities and Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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(in millions) 2025 2024 Variance Percent Change

Total Company (Loss) Income Before Income Tax $ (120) $ 2,223 $ (2,343) 105.4 %

Income Tax (Benefit) Expense $ (30) $ 502 $ (532) 106.0 %

Total Company Income (Loss) Before Income Tax $ 803 $ (120) $ 923 769.2 %

Income Tax Expense (Benefit) $ 170 $ (30) $ 200 666.7 %

Effective Income Tax Rate 21.1 % 24.8 % (3.7) %

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• The Company’s cash on hand and access to additional liquidity.

Cash, cash equivalents and restricted cash were $55 million as of December 31, 2024 and nominal as of December 31, 2023.

Cash, cash equivalents and restricted cash were $13 million as of December 31, 2025 and $55 million as of December 31, 2024.

• Accounts and notes receivable - trade as of December 31, 2025 and 2024 were $265 million and $180 million, respectively.

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For the year ended December 31, 2025, CNX had capital expenditures of $495.0 million.

• On January 27, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $505 million, subject to certain post-closing adjustments.

See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

• Production volumes are expected to range between 605 Bcfe and 620 Bcfe for the year ended December 31, 2026.

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See Item 7A., “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-K 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.

Long Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information for discussion related to CNX’s outstanding debt and Note 5 – Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information for discussion related to the repurchase of CNXs outstanding common stock.

Cash Flows (in millions)

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Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:

• Net income decreased $1,811 million in the period-to-period comparison.

• Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $2,329 million net change in commodity derivative instruments, a $531 million net decrease in deferred income taxes, a $108 million change in the gain on asset sales and abandonments, net, and a $94 million net decrease from various other changes in working capital.

• Net income increased $724 million in the period-to-period comparison.

• Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $721 million net change in commodity derivative instruments, a $195 million net increase in deferred income taxes, a $72 million change in the gain on asset sales and abandonments, net, and an $87 million net increase from various other changes in working capital.

Cash used in investing activities changed in the period-to-period comparison primarily due to the following items:

• Capital expenditures decreased $45 million primarily due to a decrease in drilling and completions activity in Marcellus Shale.

• Proceeds from asset sales decreased $109 million primarily due to the sale of various non-operated producing oil and gas assets primarily located in the Appalachian Basin to a third party in the year ended December 31, 2023 for cash proceeds of $125 million.

The remaining variance includes the sale of various non-core assets in both periods.

• Proceeds from asset sales increased $47 million primarily due to the sale of Marcellus Shale rights primarily located in Monroe County, Ohio to a third party during the year ended December 31, 2025 for cash proceeds of $57 million.

The remaining variance includes the sale of various non-core assets, rights-of-way, surface acreage and other oil and gas royalty interest in both periods.

See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

• During the year ended December 31, 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 Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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

• Proceeds from borrowings under the CNXM Credit Facility decreased $68 million and repayments under the CNXM Credit Facility decreased $28 million.

• Proceeds from borrowings under the CNX Credit Facility decreased $454 million and repayments under the CNX Credit Facility decreased $393 million.

• During the year ended December 31, 2024, CNX paid $357 million to repurchase $350 million of CNX 7.25% Senior Notes due March 2027 at a price of 101.9% of their principal amount.

See Note 12 – Long-Term Debt in the

Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

• Proceeds from borrowings under the CNXM Credit Facility increased $74 million and repayments under the CNXM Credit Facility decreased $32 million.

• Proceeds from borrowings under the CNX Credit Facility increased $793 million and repayments under the CNX Credit Facility increased $627 million.

• During the year ended December 31, 2025, CNX issued an additional $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of par.

This issuance also included an underwriter discount and other issuance costs of $1.5 million, for net cash proceeds of $198.5 million.

See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

• During the year ended December 31, 2024, CNX paid $357 million to repurchase $350 million aggregate principal amount of CNX 7.25% Senior Notes due March 2027 at a price of 101.9% of their principal amount.

See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

• During the year ended December 31, 2024, CNX issued $400 million aggregate principal amount of CNX 7.25% Senior Notes due March 2032 at par.

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• During the years ended December 31, 2025 and 2024, CNX repurchased $524 million and $184 million, respectively, of its common stock on the open market.

• During the year ended December 31, 2024, debt issuance and financing fees increased $15 million primarily due to amending both the CNX and CNXM Credit Facilities.

• During the year ended December 31, 2025, debt issuance and financing fees decreased $14 million primarily due to amending both the CNX and CNXM Credit Facilities in 2024.

See Note 10 – Revolving Credit Facilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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This long-term debt consisted of:

• An aggregate principal amount of $600 million of 7.25% Senior Notes due March 2032 less $5 million of unamortized discount.

Interest on the notes is payable March 1 and September 1 of each year.

Payment on the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

• An aggregate principal amount of $500 million of 6.00% Senior Notes due January 2029.

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• 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.

Interest on the notes is payable January 15 and July 15 of each year.

Payment of the principal and interest on the notes is guaranteed by most of CNX’s subsidiaries but does not include CNXM (or its subsidiaries or general partner).

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CNX is not a guarantor of these notes.

• An aggregate principal amount of $400 million of 7.25% Senior Notes due March 2032 less $4 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 $209 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $1 million of unamortized discount and issuance costs.

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CNX is not a guarantor of the CNXM Facility.

On January 21, 2025, the Company closed on a private offering of $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of their principal amount, plus accrued interest from September 1, 2024 to the date of closing.

See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

During the year ended December 31, 2025, CNX entered into a privately negotiated exchange agreement with a limited number of holders of its 2.25% Convertible Senior Notes due 2026 to exchange approximately $122 million aggregate principal amount of Notes for consideration consisting of an aggregate of approximately $1 million in cash (including accrued interest) and 9,509,188 shares of common stock.

See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

During the year ended December 31, 2025, CNX issued $200 million aggregate principal amount of additional 7.25% senior notes due 2032 (the "New Notes") at a price of 100.5% of par, plus accrued interest from September 1, 2024 to the date of closing less an underwriter discount and other issuance costs of $2 million.

See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

Total Equity and Dividends

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Management believes that the estimates utilized are reasonable.

The following critical

accounting estimates are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

The following critical accounting estimates are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary differences between the book and tax basis of recorded assets and liabilities.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis