CNX Resources Corp

Previous wording

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 current uncertainties in global financial markets, the conflict between Russia and Ukraine 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. The results presented in this Form 10-Q are not necessarily indicative of future operating results.

Current wording

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 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. The results presented in this Form 10-Q are not necessarily indicative of future operating results.

Previous wording

Total hedged natural gas production for the second quarter of 2025 is 120.7 Bcf. CNX's annual gas hedge position is shown in the table below:

Current wording

Total hedged natural gas production for the third quarter of 2025 is 121.9 Bcf. CNX's annual gas hedge position is shown in the table below:

Previous wording

1 Includes actual settlements of 111.0 Bcf.

Current wording

1 Includes actual settlements of 199 Bcf.

Previous wording

During the three months ended March 31, 2025, CNX completed the acquisition of Apex Energy II, LLC, (“the Apex Transaction") (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). The Apex Transaction expands CNX's existing Shale undeveloped leasehold in the central Pennsylvania region and provides an existing infrastructure footprint that can be leveraged for future development.

Current wording

During the six months ended June 30, 2025, CNX completed the acquisition of Apex Energy II, LLC, (“the Apex Transaction") (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). The Apex Transaction expands CNX's existing Shale undeveloped leasehold in the central Pennsylvania region and provides an existing infrastructure footprint that can be leveraged for future development.

Previous wording

CNX reported a net loss of $198 million, or loss per diluted share of $1.34, for the three months ended March 31, 2025, compared to net income of $7 million, or earnings per diluted share of $0.04, for the three months ended March 31, 2024.

Current wording

CNX reported net income of $433 million, or earnings per diluted share of $2.53, for the three months ended June 30, 2025, compared to a net loss of $18 million, or loss per diluted share of $0.12, for the three months ended June 30, 2024.

Previous wording

•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 repairs and maintenance expense.

Current wording

•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 repairs and maintenance expense. The increases were offset, in part, by the overall increase in total sales volumes.

Previous wording

The Shale segment had earnings before income tax of $215 million for the three months ended March 31, 2025 compared to earnings before income tax of $161 million for the three months ended March 31, 2024.

Current wording

The Shale segment had earnings before income tax of $196 million for the three months ended June 30, 2025 compared to earnings before income tax of $143 million for the three months ended June 30, 2024.

Previous wording

The Shale segment had natural gas, NGLs and oil/condensate revenue of $508 million for the three months ended March 31, 2025 compared to $292 million for the three months ended March 31, 2024. The $216 million increase was due primarily to a 73.8% increase in the average sales price for natural gas, a 5.8% increase in total Shale sales volumes and a 10.8% increase in the average sales price of NGLs. 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 Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), the timing of when new wells were turned-in-line and an increase in NGL sales volumes due to an increase in ethane recoveries. The increase in volumes was offset, in part, by normal production declines.

Current wording

The Shale segment had natural gas, NGLs and oil/condensate revenue of $452 million for the three months ended June 30, 2025 compared to $216 million for the three months ended June 30, 2024. The $236 million increase was primarily due to an 80.0% increase in the average sales price for natural gas, a 27.4% increase in total Shale sales volumes and a 9.1% increase in the average sales price of NGLs. The increase was offset, in part, by the 125.3% change in (loss) gain on commodity derivative instruments.

Previous wording

The increase in total average Shale sales price was primarily due to a $1.52 per Mcf increase in average gas sales price and a $0.43 per Mcfe increase in the average NGL sales price. These increases were offset in part by a $1.24 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 109.7 Bcf of the Company's produced Shale gas sales volumes for the three months ended March 31, 2025 at an average loss of $0.92 per Mcf hedged. For the three months ended March 31, 2024, these financial hedges represented approximately 92.2 Bcf at an average gain of $0.55 per Mcf hedged.

Current wording

The increase in total average Shale sales price was primarily due to a $1.24 per Mcf increase in average natural gas sales price and a $0.30 per Mcfe increase in the average NGL sales price. These increases were offset, in part, by a $1.14 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 113.6 Bcf of the Company's produced Shale gas sales volumes for the three months ended June 30, 2025 at an average loss of $0.29 per Mcf hedged. For the three months ended June 30, 2024, these financial hedges represented approximately 97.4 Bcf at an average gain of $1.04 per Mcf hedged.

Previous wording

Total operating costs and expenses for the Shale segment were $207 million for the three months ended March 31, 2025 compared to $198 million for the three months ended March 31, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:

Current wording

Total operating costs and expenses for the Shale segment were $240 million for the three months ended June 30, 2025 compared to $191 million for the three months ended June 30, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:

Previous wording

The CBM segment had natural gas revenue of $43 million for the three months ended March 31, 2025 compared to $33 million for the three months ended March 31, 2024. The $10 million increase was due to a 33.8% increase in the average sales price for natural gas in the current period offset, in part, by a 2.1% decrease in CBM sales volumes due to normal production declines.

Current wording

The CBM segment had natural gas revenue of $33 million for the three months ended June 30, 2025 compared to $20 million for the three months ended June 30, 2024. The $13 million increase was primarily due to a 67.5% increase in the average sales price for natural gas in the current period offset, in part, by a 3.1% decrease in CBM sales volumes due to normal production declines.

Previous wording

The total average CBM sales price increased $0.02 per Mcf due to a $1.17 per Mcf increase in average natural gas sales price offset, in part, by a $1.15 per Mcf change in the realized (loss) gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 7.6 Bcf of the Company's produced CBM sales volumes for the three months ended March 31, 2025 at an average loss of $0.92 per Mcf hedged. For the three months ended March 31, 2024, these financial hedges represented approximately 6.9 Bcf at an average gain of $0.55 per Mcf hedged.

Current wording

The total average CBM sales price increased $0.37 per Mcf primarily due to a $1.43 per Mcf increase in average gas sales price offset, in part, by a $1.07 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 6.8 Bcf of the Company's produced CBM sales volumes for the three months ended June 30, 2025 at an average loss of $0.32 per Mcf hedged. For the three months ended June 30, 2024, these financial hedges represented approximately 7.8 Bcf at an average gain of $1.05 per Mcf hedged.

Previous wording

Total operating costs and expenses for the CBM segment were $38 million for the three months ended March 31, 2025 compared to $37 million for the three months ended March 31, 2024. The increase in total dollars and unit costs for the CBM segment were due to the following items:

Current wording

Total operating costs and expenses for the CBM segment were $39 million for the three months ended June 30, 2025 compared to $37 million for the three months ended June 30, 2024. The increases in total dollars unit costs for the CBM segment were due to the following items:

Previous wording

•CBM transportation, gathering and compression costs were $16 million for both the three months ended March 31, 2025 and 2024. The increase in per unit costs was due to the decrease in CBM gas sales volumes.

Current wording

•CBM lease operating expenses were $6 million for both the three months ended June 30, 2025 and 2024. The increase in per unit costs was due to the decrease in total CBM volumes.

Previous wording

The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, sales of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative (“SG&A”), interest expense and income taxes.

Current wording

The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, sales of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative expense (“SG&A”), interest expense and income taxes.

Previous wording

The Other Segment had a loss before income tax of $486 million for the three months ended March 31, 2025 compared to a loss before income tax of $155 million for the three months ended March 31, 2024. The decrease in total dollars is discussed below.

Current wording

The Other Segment had earnings before income tax of $398 million for the three months ended June 30, 2025 compared to a loss before income tax of $149 million for the three months ended June 30, 2024. The increase in total dollars is discussed below.

Previous wording

For the three months ended March 31, 2025, the Other Segment recognized an unrealized loss on commodity derivative instruments of $418 million. For the three months ended March 31, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $47 million. The unrealized 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.

Current wording

For the three months ended June 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $456 million. For the three months ended June 30, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $96 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.

Previous wording

•CNX pursues legal recoveries when certain circumstances arise. The decrease in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in the prior period. No such transactions occurred in the current period.

Current wording

•CNX pursues legal recoveries when certain circumstances arise. The decrease in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in each period.

Previous wording

The effective income tax rates for the three months ended March 31, 2025 and 2024 were 27.5% and (8.4)%, respectively. The effective tax rate for the three months ended March 31, 2025 and 2024 differs from the U.S. federal statutory rate of 21% primarily due to the impact of equity compensation, federal tax credits, and state taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Current wording

The effective income tax rates for the three months ended June 30, 2025 and 2024 were 26.1% and (19.8)%, respectively. The effective rate for the three months ended June 30, 2025 and 2024 differs from the U.S. federal statutory rate of 21% primarily due to the impact equity compensation, federal tax credits and state taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Previous wording

Included in the loss for the three months ended March 31, 2025 was an unrealized loss on commodity derivative instruments of $418 million and a net gain on asset sales and abandonments of $10 million. Included in the earnings for the three months ended March 31, 2024 was an unrealized loss on commodity derivative instruments of $47 million and a net loss on asset sales and abandonments of $20 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the (gain) loss on asset sales and abandonments.

Current wording

Included in the earnings for the six months ended June 30, 2025 was an unrealized gain on commodity derivative instruments of $38 million and a net gain on asset sales and abandonments of $27 million. Included in the loss for the six months ended June 30, 2024 was an unrealized loss on commodity derivative instruments of $143 million and a net loss on asset sales and abandonments of $20 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the (gain) loss on asset sales and abandonments.

Previous wording

•Transportation, gathering and compression expense decreased on a per unit basis due to a decrease in processing costs. The decrease in processing costs was primarily related to the change in production mix in the period-to-period comparison, which included an increase in dry gas volumes related to the Apex Transaction and an increase in lower cost ethane volumes. The decrease was also due to the overall increase in total sales volumes.

Current wording

•Transportation, gathering and compression expense decreased on a per unit basis primarily due to the overall increase in total sales volumes and 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 was offset, in part, by higher repairs and maintenance expense and higher electrical compression expense.

Previous wording

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 7.4 Bcfe increase in total sales volumes, the $1.49 per Mcf increase in natural gas sales price, when excluding the impact of hedging and the $2.58 per barrel increase in NGL prices. 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.

Current wording

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 41.0 Bcfe increase in total sales volumes, the $1.33 per Mcf increase in natural gas sales price, when excluding the impact of hedging and the $2.40 per barrel increase in NGL prices. 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.

Previous wording

•Shale lease operating expenses were $17 million for the three months ended March 31, 2025 compared to $12 million for the three months ended March 31, 2024. 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 and an increase in well tending expense.

Current wording

•Shale lease operating expenses were $37 million for the six months ended June 30, 2025 compared to $24 million for the six months ended June 30, 2024. 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 and an increase in well tending expense.

Previous wording

•Shale transportation, gathering and compression costs were $78 million for the three months ended March 31, 2025 compared to $81 million for the three months ended March 31, 2024. The decrease in total dollars and unit costs was primarily due to 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 also due to the increase in total Shale sales volumes.

Current wording

•Shale transportation, gathering and compression costs were $158 million for the six months ended June 30, 2025 compared to $156 million for the six months ended June 30, 2024. The increase in total dollars was primarily due to higher repairs and maintenance expense and higher 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.

Previous wording

•Depreciation, depletion and amortization costs attributable to the Shale segment were $106 million for the three months ended March 31, 2025 compared to $99 million for the three months ended March 31, 2024. These amounts included depletion on a unit of production basis of $0.66 per Mcfe and $0.65 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

Current wording

•Depreciation, depletion and amortization costs attributable to the Shale segment were $238 million for the six months ended June 30, 2025 compared to $197 million for the six months ended June 30, 2024. These amounts included depletion on a unit of production basis of $0.67 per Mcfe and $0.66 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

Previous wording

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 $17 million for the three months ended March 31, 2025 compared to $16 million for the three months ended March 31, 2024. The increase in the period-to-period comparison was primarily due to an increase in third-party gathering volumes.

Current wording

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 $34 million for the six months ended June 30, 2025 compared to $32 million for the six months ended June 30, 2024. The increase in the period-to-period comparison was primarily due to an increase in third-party gathering volumes.

Previous wording

•CBM lease operating expenses were $6 million for the three months ended March 31, 2025 compared to $5 million for the three months ended March 31, 2024. The increase in total dollars and unit costs was primarily due to an increase in well tending expense and repairs and maintenance. The increase in per unit costs was also due to the decrease in total CBM volumes.

Current wording

•CBM lease operating expenses were $12 million for the six months ended June 30, 2025 compared to $11 million for the six months ended June 30, 2024. The increase in total dollars and unit costs was primarily due to an increase in water disposal costs and well tending expense. The increase in per unit costs was also due to the decrease in total CBM volumes.

Previous wording

•Depreciation, depletion and amortization costs attributable to the CBM segment were $14 million for both the three months ended March 31, 2025 and 2024. These amounts included depletion on a unit of production basis of $0.87 per Mcfe and $0.85 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

Current wording

•Depreciation, depletion and amortization costs attributable to the CBM segment were $29 million for the six months ended June 30, 2025 and $29 million or the six months ended June 30, 2024. These amounts included depletion on a unit of production basis of $0.86 per Mcfe and $0.85 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

Previous wording

Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $11 million for the three months ended March 31, 2025 compared to $14 million for the three months ended March 31, 2024. Purchased gas costs were $11 million for the three months ended March 31, 2025 compared to $13 million for the three months ended March 31, 2024. The period-to-period decrease in purchased gas revenue was primarily due to a decrease in purchased gas sales volumes.

Current wording

Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $22 million for the six months ended June 30, 2025 compared to $25 million for the six months ended June 30, 2024. Purchased gas costs were $21 million for the six months ended June 30, 2025 compared to $24 million for the six months ended June 30, 2024. The period-to-period decrease in purchased gas revenue was primarily due to a decrease in purchased gas sales volumes.

Previous wording

•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.

Current wording

•Sales of environmental attributes include items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The decrease in the period-to-period comparison was due to a decrease in the amount of environmental attributes sold.

Previous wording

•Equity loss 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.

Current wording

•Equity income (loss) 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.

Previous wording

•Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Income. The decrease in period-to-period comparison was primarily due to lower fees in the current period, resulting from capacity optimization driven by colder weather.

Current wording

•Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Income. The decrease in period-to-period comparison was primarily due to lower fees in the current period, resulting from capacity optimization driven by colder weather in the earlier part of the year.

Previous wording

•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.

Current wording

•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.

Previous wording

A net gain on asset sales and abandonments of $10 million was recognized in the three months ended March 31, 2025 compared to a net loss of $20 million in the three months ended March 31, 2024. The net gain recognized in the three months ended March 31, 2025 primarily relates to sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests), offset in part by a $6 million loss on the sale of a non-core midstream facility to a third party. The net loss recognized in the three months ended March 31, 2024 primarily relates to a $26 million loss on the sale of a non-core pipeline to a third party offset, in part, by the sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests). (See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

Current wording

A net gain on asset sales and abandonments of $27 million was recognized in the six months ended June 30, 2025 compared to a net loss of $20 million in the six months ended June 30, 2024. The net gain recognized in the six months ended June 30, 2025 primarily relates to sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests), offset in part by a $6 million loss on the sale of a non-core midstream facility to a third party. The net loss recognized in the six months ended June 30, 2024 primarily relates to a $26 million loss on the sale of a non-core pipeline to a third party offset, in part, by the sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets). See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Previous wording

A loss on debt extinguishment of $7 million was recognized in the three months ended March 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 the principal amount. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such transactions occurred in the current period.

Current wording

A loss on debt extinguishment of $7 million was recognized in the six months ended June 30, 2024 in connection with CNX's repurchase of $350 million aggregate principal amount of 7.25% Senior Notes due March 2027 at an average price equal to 101.9% of the principal amount. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such transactions occurred in the current period.

Previous wording

•The Company’s cash on hand and access to additional liquidity. Cash, cash equivalents and restricted cash were $13 million as of March 31, 2025 and $55 million as of December 31, 2024.

Current wording

•The Company’s cash on hand and access to additional liquidity. Cash, cash equivalents and restricted cash were $16 million as of June 30, 2025 and $55 million as of December 31, 2024.

Previous wording

•Accounts and notes receivable - trade as of March 31, 2025 and December 31, 2024 were $247 million and $180 million, respectively. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.

Current wording

•Accounts and notes receivable - trade as of June 30, 2025 and December 31, 2024 were $180 million for each period, respectively. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.

Previous wording

•Capital expenditures are expected to range between $450 million to $500 million for the year ended December 31, 2025. For the three months ended March 31, 2025, CNX had capital expenditures of $131 million.

Current wording

•Capital expenditures are expected to range between $450 million to $500 million for the year ended December 31, 2025. For the six months ended June 30, 2025, CNX had capital expenditures of $245 million.

Previous wording

•Production volumes are expected to range between 605.0 Bcfe and 620.0 Bcfe for the year ended December 31, 2025. For the three months ended March 31, 2025, CNX had production volumes of 147.8 Bcfe.

Current wording

•Production volumes are expected to range between 615.0 Bcfe and 620.0 Bcfe for the year ended December 31, 2025. For the six months ended June 30, 2025, CNX had production volumes of 315.4 Bcfe.

Previous wording

•In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas and NGL swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was anet liability of $976 million at March 31, 2025 and a net liability of $536 million at December 31, 2024. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q for further discussion of our commodity risk management.

Current wording

•In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas and NGL swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of $471 million at June 30, 2025 and a net liability of $536 million at December 31, 2024. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q for further discussion of our commodity risk management.