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Item 7. Management’s Discussion and Analysis

2025-02-11 compared with 2024-02-08 · 158 added, 185 removed, 406 unchanged (46% of the section changed)

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This discussion contains forward‑looking statements that are based on the views and beliefs of management, as well as assumptions and estimates made by management.

Actual results could differ materially from such forward‑looking statements as a result of various risk factors, including those that may not be in the control of 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.

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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 the announcement by the Organization of the Petroleum Exporting Countries (OPEC) to extend production cuts through the first quarter of 2024, both of which have had an impact on global commodity prices.

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.

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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However, this market volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

Heightened levels of inflation, primarily related to steel, diesel fuel and labor, continue to present risk for CNX and the broader natural gas industry.

If inflation continues at its current levels or increases further 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.

Rising interest rates increased our costs on borrowings under our Credit Facility in 2023, but it is currently anticipated that the Federal Reserve will make cuts to relevant interest rates in 2024.

CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset any additional cost increases from 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.

New Technologies Update

As previously disclosed, CNX continues to devote resources to the development of unique, proprietary technologies to further enable vertical and horizontal business growth.

This includes the development and use of proprietary technology to enhance and alter manufacturing processes for the extraction and delivery of natural gas through the development and commercialization of emerging technologies, as well as the development and sale of environmental attributes from our operations.

CNX is also focusing on forging strategic partnerships for the use of low carbon intensity feedstocks and creation of derivative products.

For the year ended December 31, 2023, CNX had $41 million of sales of environmental attributes which includes items such as (but is not limited to):

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, 2023, CNX incurred $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 December 15, 2023, citing delays and increasing uncertainty over implementation rules guiding the use of the 45V hydrogen production tax credit provisions of the Inflation Reduction Act (IRA) and an inability to reach final commercial terms with project developers, CNX announced it had ended coordination with the Adams Fork project.

The Company continues to evaluate several viable alternative sites in southern West Virginia for clean hydrogen projects.

The Company remains committed to supporting the Appalachian Regional Clean Hydrogen Hub (ARCH2) via use of its local, low cost, low carbon intensity feedstock, which is ideal for affordable, clean hydrogen production in historically disadvantaged energy communities across Appalachia.

CNX's final investment decision remains contingent upon the future issuance of tax credit guidance that unambiguously supports low carbon intensity feedstock projects that will facilitate development of the regional clean hydrogen hubs, including ARCH2.

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.

2024 Highlights:

• Proved developed reserves of 6.0 Tcfe.

• Proved developed reserves of 6.1 Tcfe as of December 31, 2024

• Total sales volumes of 550.8 Bcfe

• Shale sales volumes of 511.4 Bcfe

• Repurchased 17.6 million shares of CNX common stock for $322 million on the open market.

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

2025 Outlook:

• Our 2024 annual sales volumes are expected to be approximately 570-590 Bcfe (This includes approximately 15-18 Bcfe of CMM.

See New Technologies section in “Item 1.

Business” of this Form 10-K for additional information).

• 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 2025 annual sales volumes are expected to be approximately 605-620 Bcfe.

• Our 2025 capital expenditures are expected to be approximately $450-$500 million.

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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 Income (Loss)

CNX reported net income of $1,721 million, or earnings per diluted share of $8.99, for the year ended December 31, 2023, compared to a net loss of $142 million, or a loss per diluted share of $0.75, for the year ended December 31, 2022.

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.

Included in earnings for the year ended December 31, 2023 was an unrealized gain on commodity derivative instruments of $1,765 million and a net gain on asset sales and abandonments of $132 million.

Included in the loss for the year ended December 31, 2022 was an unrealized loss on commodity derivative instruments of $851 million and a net gain on asset sales and abandonments of $9 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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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 generally accepted accounting principles (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.

Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance.

Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments.

Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities.

Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 21 – Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs.

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Purchased Gas Revenue (59) (75)

(Gain) Loss on Commodity Derivative Instruments (1,765) 851

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

Other Revenue and Operating Income (194) (130)

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Natural Gas, NGL and Oil Revenue $ 1,186 $ 2.09 $ 1,302 $ 2.29 $ (116) $ (0.20)

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement 163 0.32 (1,813) (3.35) 1,976 3.67

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

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 19.8 Bcfe decrease in volumes in the period-to period comparison was primarily due to various operational delays and challenges that occurred in 2022 which impacted current period production due to the timing of wells being turned-in-line.

The remaining variance is primarily due to normal production declines offset, in part, by an increase in NGL sales volume from new wells turned-in-line and an increase in ethane recoveries.

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.

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

• Production, ad valorem and other fees decreased on a per unit basis primarily due to decreased realized prices on natural gas.

• Transportation, gathering and compression expense increased on a per unit basis primarily due to increased processing fees, increased electrical compression expense, increased repairs and maintenance expense and lower volumes.

• Depreciation, depletion and amortization expense decreased on a per unit basis due to a lower annual depletion rate primarily resulting from low-cost reserve additions from development during the 2022 period.

• 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.

Average Realized Price Reconciliation

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Hedging Impact ($/Mcf) $ 0.57 $ 0.32 $ 0.25 (78.1) %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement $ 163,026 $ (1,812,777) $ 1,975,803 109.0 %

The decrease in gross revenue was primarily the result of the $4.07 per Mcf decrease in natural gas prices, when excluding the impact of hedging, the $16.92 per Bbl decrease in NGL prices, and the 19.8 Bcfe decrease in sales volume.

These 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.

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.

SEGMENT ANALYSIS for the year ended December 31, 2024 compared to the year ended December 31, 2023:

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Natural Gas, NGLs and Oil Revenue $ 1,080 $ 105 $ 1 $ 1,186 $ (90) $ (26) $ — $ (116)

Gain on Commodity Derivative Instruments 151 12 1,765 1,928 1,824 151 2,617 4,592

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

Purchased Gas Revenue — — 59 59 — — (16) (16)

Other Revenue and Operating Income 68 — 126 194 1 — 63 64

Total Revenue and Other Operating Income 1,388 143 1,904 3,435 (343) (33) 2,550 2,174

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

Lease Operating Expense 48 22 — 70 4 3 — 7

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Total Operating Costs and Expenses 791 152 317 1,260 45 10 13 68

Other Expense — — 9 9 — — (1) (1)

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

Gain on Asset Sales and Abandonments, net — — (25) (25) — — 107 107

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Total Costs and Expenses 791 152 444 1,387 45 10 120 175

Earnings Before Income Tax $ 642 $ 1 $ 1,580 $ 2,223 $ (298) $ (43) $ 2,776 $ 2,435

Earnings (Loss) Before Income Tax $ 617 $ (26) $ (711) $ (120) $ (25) $ (27) $ (2,291) $ (2,343)

SHALE SEGMENT

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Average Sales Price - Gas (per Mcf) $ 1.92 $ 2.11 $ (0.19) (9.0) %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf) $ 0.32 $ (3.37) $ 3.69 109.5 %

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

Average Sales Price - NGLs (per Mcfe)* $ 3.60 $ 3.54 $ 0.06 1.7 %

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The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,080 million for the year ended December 31, 2024 compared to $1,170 million for the year ended December 31, 2023.

The $2,165 million decrease was due primarily to a 65.9% decrease in the average sales price for natural gas, a 44.3% decrease in the average sales price of NGLs, and a 3.1% decrease in total Shale gas sales volumes.

The decrease in total Shale sales volumes was primarily due to various operational delays and challenges that occurred in 2022, which impacted current period production due to the timing of wells being turned-in-line.

The remaining variance is primarily due to normal production declines offset, in part, by an increase in NGL sales volume from new wells turned-in-line and an increase in ethane recoveries.

The decrease in total average Shale sales price was primarily due to a $4.08 per Mcf decrease in average gas sales price and a $2.82 per Mcfe decrease in the average NGL sales price.

These decreases were offset in part by a $3.69 per Mcf change in the realized gain (loss) on commodity derivative instruments.

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.

For the year ended December 31, 2022, these financial hedges represented approximately 424.7 Bcf at an average loss of $3.94 per Mcf hedged.

For the year ended December 31, 2023, these financial hedges represented approximately 399.2 Bcf at an average gain of $0.37 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $791 million for the year ended December 31, 2024 compared to $746 million for the year ended December 31, 2023.

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

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

• Shale lease operating expenses were $48 million for the year ended December 31, 2024 compared to $44 million for the year ended December 31, 2023.

The decrease in total dollars was primarily related to a decrease in water disposal costs as more water was able to be reused in well completions instead of being taken to disposal.

• Shale production, ad valorem and other fees were $21 million for the year ended December 31, 2023 compared to $33 million for the year ended December 31, 2022.

The decrease in total dollars was primarily due to decreased realized prices on natural gas.

• Shale transportation, gathering and compression costs were $316 million for the year ended December 31, 2023 compared to $319 million for the year ended December 31, 2022.

The decrease in total dollars was primarily related to a decrease in firm transportation expense due to the lower Shale sales volumes.

The decrease was offset, in part, by an increase in repairs and maintenance expense and an increase in processing costs due to an increase in ethane extraction and processing rates.

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.

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These amounts included depletion on a unit of production basis of $0.68 per Mcfe and $0.59 per Mcfe, respectively.

The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a lower annual depletion rate related to low-cost reserve additions from development in the 2022 period.

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

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.

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 $68 million for the year ended December 31, 2024 compared to $67 million for the year ended December 31, 2023.

The decrease in the period-to-period comparison was primarily due to lower third-party gathering volumes due to normal production declines.

The increase in the period-to-period comparison was primarily due to an increase in third-party gathering volumes.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $1 million for the year ended December 31, 2023 compared to earnings before income tax of $44 million for the year ended December 31, 2022.

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.

For the Years Ended December 31,

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Average Sales Price - Gas (per Mcf) $ 2.69 $ 3.22 $ (0.53) (16.5) %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.28 $ (3.18) $ 3.46 108.8 %

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

Total Average CBM Sales Price (per Mcf) $ 3.21 $ 3.51 $ (0.30) (8.5) %

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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 $0.50 per Mcf due to a $3.98 per Mcf decrease in average gas sales price, offset in part by a $3.46 per Mcf change in the realized gain (loss) on commodity derivative instruments resulting from the Company's hedging program.

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.

For the year ended December 31, 2022, these financial hedges represented approximately 35.5 Bcf at an average loss of $3.92 per Mcf hedged.

For the year ended December 31, 2023, these financial hedges represented approximately 31.9 Bcf at an average gain of $0.36 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $152 million for the year ended December 31, 2024 compared to $142 million for the year ended December 31, 2023.

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

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

• CBM lease operating expense was $22 million for the year ended December 31, 2024 compared to $19 million for the year ended December 31, 2023.

The increases in total dollars and unit costs were primarily due to increases in water disposal costs and repairs and maintenance expense.

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 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.

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• 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 increases in total dollars and unit cost were primarily due to an increase in electrical compression expense and repairs and maintenance expense.

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.

The decrease in total dollars and increase in unit costs was primarily due to the lower volumes in the current period.

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.

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 SG&A, interest expense and income taxes.

The Other Segment had earnings before income tax of $1,580 million for the year ended December 31, 2023 compared to a loss before income tax of $1,196 million for the year ended December 31, 2022.

The increase in total dollars is discussed below.

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.

For the Years Ended December 31,

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

Unrealized Gain (Loss) on Commodity Derivative Instruments

(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.

For the year ended December 31, 2023, the Other Segment recognized an unrealized gain on commodity derivative instruments of $1,765 million.

For the year ended December 31, 2022, the Other Segment recognized an unrealized loss on commodity derivative instruments of $851 million, as well as cash settlements paid of $1 million.

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

See Note 19 – Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the cash settlements.

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.

Purchased Gas Revenue and Costs

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Purchased gas costs were $57 million for the year ended December 31, 2024 compared to $70 million for the year ended December 31, 2023.

The period-to-period decrease in purchased gas revenue was due to a decrease in average sales price, offset in part by an increase in purchased gas sales volumes.

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

For the Years Ended December 31,

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Purchased Gas Average Cost (per Mcf) $ 1.84 $ 2.25 $ (0.41) (18.2) %

Other Operating Income

Other Revenue and Operating Income

For the Years Ended December 31,

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Sales of Environmental Attributes $ 95 $ 41 $ 54 131.7 %

Excess Firm Transportation Income 16 12 4 33.3 %

Equity Income from Affiliates 3 1 2 200.0 %

Water Income 12 3 9 300.0 %

Total Other Operating Income $ 63 $ 18 $ 45 250.0 %

Excess Firm Transportation Income 20 16 4 25.0 %

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

Total Other Revenue and Operating Income $ 126 $ 63 $ 63 100.0 %

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

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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.

• 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.

• Equity income from affiliates primarily represents CNX’s share of earnings from a 50% interest in a power plant located within CNX’s CBM field.

Power generated from the facility is sold into wholesale electricity markets during times of peak energy consumption.

Due to the plant consuming coal mine methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy Credits.

• Water income decreased in the period-to-period comparison due to fewer third-party sales in the current period.

• (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.

Exploration and Production Related Other Costs

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Land Rentals 3 4 (1) (25.0) %

Seismic Activity — 3 (3) (100.0) %

Other Expense 1 — 1 100.0 %

Total Exploration and Production Related Other Costs $ 8 $ 10 $ (2) (20.0) %

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

The increase in the year ended December 31, 2023 was primarily due to an increase in the number of leases that were allowed to expire.

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

Selling, General and Administrative (“SG&A”)

SG&A costs include 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.

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.

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

SG&A costs also include non-cash long-term equity-based compensation expense.

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(in millions) 2024 2023 Variance Percent Change

Short-Term Incentive Compensation $ 23 $ 11 $ 12 109.1 %

Contributions and Advertising 5 4 1 25.0 %

Long-Term Equity-Based Compensation (Non-Cash) 20 20 — — %

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

Contributions and Advertising 4 5 (1) (20.0) %

Short-Term Incentive Compensation 11 20 (9) (45.0) %

Other 68 59 9 15.3 %

Total SG&A $ 146 $ 125 $ 21 16.8 %

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

• Short-term incentive compensation decreased $9 million due to lower projected payouts for the current period.

• Other increased in the period-to-period comparison primarily due to an increase in professional services and consulting fees related to cyber security, legal matters and regulatory reporting.

• 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.

Other Operating Expense

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Environmental Attribute Fees $ 15 $ 7 $ 8 114.3 %

Inventory Adjustments 6 — 6 100.0 %

Water Expense 2 1 1 100.0 %

Idle Equipment and Service Charges 4 4 — — %

Unutilized Firm Transportation and Processing Fees 53 52 1 1.9 %

Insurance Expense 4 4 — — %

Water Expense 1 1 — — %

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

Litigation Settlements — 3 (3) (100.0) %

Inventory Adjustments 2 6 (4) (66.7) %

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

Other 9 3 6 200.0 %

Total Other Operating Expense $ 83 $ 80 $ 3 3.8 %

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

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

• 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 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 Inc ome.

• Virginia flood expense includes the continuing cleanup and repair costs related to fl ooding that occurred in Buchanan County, Virginia in July 2022.

• CNX and its subsidiaries are subject to various lawsuits and claims in the normal course of business.

CNX accrues the estimated loss for these lawsuits and claims as litigation settlements when the loss is probable and can be estimated.

(See Note 20 – Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The decrease in litigation settlements in the period-to-period comparison was the result of various items, none of which were individually material.

Other Expense

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

For the Years Ended December 31,

(in millions) 2024 2023 Variance Percent Change

Litigation Recoveries $ 20 $ — $ 20 100.0 %

Right-of-Way Sales 1 5 (4) (80.0) %

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Total Other Expense $ 19 $ 18 $ 1 5.6 %

Total Other Expense $ 9 $ 10 $ (1) (10.0) %

• Professional services decreased in the period-to-period comparison primarily due to a decrease in legal fees.

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).

• 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.

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 during the year ended December 31, 2023 primarily relates to the sale of various non-operated oil and gas assets (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, 2022, the Company chose to plug and abandon a Shale wellbore.

This well was originally part of future development plans, and in order to not delay other wells, CNX plugged the wellbore and planned to access the reserves at a future date.

This loss was offset in part by sales of various non-core assets, primarily rights-of-way, surface acreage and other non-core oil and gas interests.

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.

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.

Loss on Debt Extinguishment

A loss on debt extinguishment of $23 million was recognized in the year ended December 31, 2022 following CNX’s purchase of a portion of the Convertible Notes due May 2026 and $350 million of the 7.25% Senior Notes due March 2027 at an average price equal to 102.5% of the principal amount.

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.

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 current period.

No such transactions occurred in the prior period.

Interest Expense

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Total Interest Expense $ 151 $ 143 $ 8 5.6 %

The $15 million increase in total interest expense was primarily due a $3 million unrealized loss on interest rate swaps in the current period compared to a $10 million unrealized gain in the prior period.

The increase was also due to slightly higher interest paid on long-term debt that was issued in September 2022.

These increases were offset in part by lower borrowings on the Credit Facility.

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.

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.

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.

For the Years Ended December 31,

(in millions) 2024 2023 Variance Percent Change

Total Company Earnings (Loss) Before Income Tax $ 2,223 $ (212) $ 2,435 1,148.6 %

Income Tax Expense (Benefit) $ 502 $ (70) $ 572 817.1 %

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

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

Effective Income Tax Rate 24.8 % 22.6 % 2.2 %

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federal statutory rate of 21% primarily due to federal tax credits, state income taxes including tax rate changes, equity compensation, and the impact of changes in certain state deferred tax asset valuation allowances.

The unrealized gains and losses represent changes in the fair value of the Company’s existing commodity hedges on a mark-to-market basis.

See Note 6 – Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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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 the current fiscal year.

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.

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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 costs were to increase significantly, our cash flows and liquidity could be reduced.

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 December 31, 2024, CNX was in compliance with all of its debt covenants.

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

Cash and cash equivalents were nominal as of December 31, 2023 and $21 million as of December 31, 2022.

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

• Accounts and notes receivable - trade as of December 31, 2024 and 2023 were $180 million and $116 million, respectively.

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For the year ended December 31, 2024, CNX had capital expenditures of $540.3 million.

Accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring an increase in costs in the future.

• 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 605.0 Bcfe and 620.0 Bcfe for the year ended December 31, 2025.

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The Company has not experienced any issues of non-performance by derivative counterparties.

See Item 7A., “Quantitative and Qualitative Disclosures About Market Risk” for further discussion of our commodity risk management.

See Item 7A., “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-K for further discussion of our commodity risk management.

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 increased $1,863 million in the period-to-period comparison.

• Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $2,778 million net change in commodity derivative instruments, a $573 million benefit from the change in deferred income taxes, a $123 million increase in gain on asset sales and abandonments, net, and a $45 million net benefit from various other changes in working capital.

• 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.

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

• Capital expenditures increased $114 million primarily due to an increase in drilling and completions activity and an overall increase in costs related to inflation.

• Proceeds from asset sales increased $133 million primarily due to the sale of various non-operated oil and gas assets (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).

• Capital expenditures decreased $139 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.

(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 $10 million and repayments under the CNXM Credit Facility increased $7 million.

• 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, 2022, CNX closed on $500 million aggregate principal amount of CNX 7.375% Senior Notes due January 2031 at a price of 98.8% for cash proceeds of $494 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, 2022, CNX paid $359 million to repurchase $350 million of CNX 7.25% Senior Notes due March 2027 at 102.5% of the 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, 2022, CNX paid $27 million to repurchase $14 million of the 2026 Convertible Notes at 188.0% of the principal amount.

• 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.

• 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.

The issuance included an underwriter discount and other issuance costs of $5 million, for net cash proceeds of $395 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 years ended December 31, 2024 and 2023, CNX repurchased $184 million and $320 million, respectively, of its common stock on the open market.

Commitments and Significant Contractual Obligations

The following is a summary of the Company's significant contractual obligations at December 31, 2023 (in thousands):

• 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.

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.

Commitments and Significant Contractual and Other Obligations

The following is a summary of the Company's significant contractual and other obligations at December 31, 2024 (in thousands):

Payments due by Year

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This long-term debt consisted of:

• An aggregate principal amount of $500 million of 7.375% Senior Notes due January 2031, less $5 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 $500 million of 6.00% Senior Notes due January 2029.

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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 $5 million of unamortized discount.

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

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

• An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $3 million of unamortized discount.

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CNX is not a guarantor of these notes.

• An aggregate principal amount of $350 million of 7.25% Senior Notes due March 2027 plus $2 million of unamortized premium.

• 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 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).

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 $331 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $3 million of unamortized discount and issuance costs.

Interest on the notes

is payable May 1 and November 1 of each year.

Interest on the notes is payable May 1 and November 1 of each year.

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

At December 31, 2023, the conditions of allowing holders of the Convertible Notes to exercise their conversion right were met and as of December 31, 2023, the Convertible Notes were convertible.

The Convertible Notes are therefore classified as short-term debt at December 31, 2023.

The Convertible Notes are classified as short-term debt at December 31, 2024.

• An aggregate principal amount of $43 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 $16 million in outstanding borrowings under the CNXM Credit Facility.

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CNX is not a guarantor of the CNXM Facility.

• An aggregate principal amount of $52 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).

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.

Total Equity and Dividends

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CNX has not paid dividends on its common stock since 2016.

The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX, and such other factors as the Board of Directors deems relevant.

CNX's Credit Facility limits its ability to pay dividends in excess of an annual rate of $0.10 per share when the Company's net leverage ratio exceeds 3.00 to 1.00 and is subject to availability under the Credit Facility of at least 20% of the aggregate commitments and there being no borrowing base deficiency.

The Credit Facility does not permit such dividend payments when an event of default has occurred and is continuing.

The indentures to the 7.25% Senior Notes due March 2027, the 6.00% Senior Notes due January 2029, and the 7.375% Senior Notes due January 2031 limit dividends to $0.50 per share annually unless several conditions are met.

These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures.

There were no defaults in the year ended December 31, 2023.

Critical Accounting Policies

In addition, CNX’s ability to pay dividends is limited by the covenants governing the CNX Credit Facility and the indentures governing certain of CNX’s Senior Notes.

Critical Accounting 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 reported amounts of assets and liabilities, revenues and expenses and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements.

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Management believes that the estimates utilized are reasonable.

The following critical accounting policies 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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A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained.

The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other

assumptions that we believe are reasonable under the circumstances.

The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances.

The results of these estimates, which are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability.

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See Note 6 – Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company’s uncertain tax liabilities.

The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise judgment regarding the amount of financial statement benefit to record for uncertain tax positions.

When evaluating whether or not a valuation allowance must be established on deferred tax assets, the Company exercises judgment in determining whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized.

The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed, including carrybacks, tax planning strategies and reversal of deferred tax assets and liabilities.

In making the determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit.

To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.

Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

Natural Gas, NGL, Condensate and Oil Reserve (“Natural Gas Reserve”) Values

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The Company groups its assets by geological and geographical characteristics.

If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is

determined based on discounted cash flow techniques using a market-specific weighted average cost of capital.

There were no impairments related to proved properties in the years ended December 31, 2023 or 2022.

If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital.

There were no indicators of impairment related to the Company's proved oil and gas properties in the years ended December 31, 2024 or 2023.

CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis.

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If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made.

There were no impairments related to unproved properties in the years ended December 31, 2023 or 2022.

There were no indicators of impairment related to the Company’s unproved properties in the years ended December 31, 2024 or 2023.

The Company believes that the accounting estimates related to the impairment of long-lived assets are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results.

In addition, the Company must determine the estimated undiscounted future cash flows as well as the impact of commodity price outlooks.

In addition, when indicators are identified the Company must determine the estimated undiscounted future cash flows as well as the impact of commodity price outlooks.

The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate;

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Although we believe our estimates of fair value are reasonable, actual financial results could differ from those estimates due to the inherent uncertainty involved in making such estimates.

Changes in assumptions concerning future financial results or other underlying assumptions

could have a significant impact on either the fair value of the reporting unit, the amount of any goodwill impairment charge, or both.

Changes in assumptions concerning future financial results or other underlying assumptions could have a significant impact on either the fair value of the reporting unit, the amount of any goodwill impairment charge, or both.

For the Company’s annual impairment assessment during the fourth quarter of 2024, the Company elected to perform a qualitative impairment test on its goodwill and concluded that it is more likely than not that the fair value exceeded the carrying value and goodwill was not impaired.

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Additionally, future estimates may differ materially from current estimates and assumptions.

Impairment of Definite-Lived Intangible Assets

Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed for impairment when indicators of impairment are present.

Impairment tests require that the Company first compare future undiscounted cash flows to their respective carrying values.

If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the asset to its estimated fair value is required.

There were no impairments related to definite-lived intangible assets in the years ended December 31, 2023 or 2022.

The Company believes that the accounting estimates related to the impairment of definite-lived intangible assets are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results.

The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate;

however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about the impairment of definite-lived intangible assets which could materially impact the Company’s results of operations and financial position.

Additionally, future estimates may differ materially from current estimates and assumptions.

Derivative Instruments.

We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of natural gas production.

See Note 18 – Fair Value of Financial Instruments to the Consolidated Financial Statements for a description of the fair value hierarchy.

The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change.

We believe derivative instruments are "critical accounting estimates" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis.

Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" of this Form 10-K for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.

Recent Accounting Pronouncements

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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