CNX Resources Corp
For the period ended Mar 31, 2026. Filed Apr 30, 2026.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed Apr 30, 2026
CNX$34.92-1.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-10-30.
0001070412-25-000109
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-04-30.
0001070412-26-000047
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 249 previous paragraphs and 180 current paragraphs.
104 unchanged; 60 reworded; 14 added; 61 removed; 24 previous and 2 current paragraphs rearranged.
Tables are not compared: 33 previous and 18 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (14)
Current report
Net Income (Loss)
Current report
The 4.6 Bcfe increase in sales volumes was primarily due to new wells turned-in-line throughout 2025 and the first quarter of 2026, including wells related to 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 increase in sales volumes was offset, in part, by normal production declines.
Current report
•Production, ad valorem, and other fees increased on a per unit basis primarily due to the higher sales price in the period to period comparison.
Current report
•Transportation, gathering and compression expense increased on a per unit basis primarily due to higher repairs and maintenance expense and increased utilization of firm transportation capacity as volumes in our central Pennsylvania operating area have increased. The per unit increases were offset, in part, by the overall increase in total sales volumes.
Current report
The increase in total Shale sales volumes was primarily due to new wells turned-in-line throughout 2025 and the first quarter of 2026, including wells related to 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 increase in total Shale sales volumes was offset, in part, by normal production declines.
Current report
Total operating costs and expenses for the Shale segment were $221 million for the three months ended March 31, 2026 compared to $207 million for the three months ended March 31, 2025. The increase in total dollars and increase in unit costs for the Shale segment were due to the following items:
Current report
•Shale transportation, gathering and compression costs were $86 million for the three months ended March 31, 2026 compared to $78 million for the three months ended March 31, 2025. The increase in total dollars and unit costs was primarily due to higher repairs and maintenance expense and increased utilization of firm transportation capacity as volumes in our central Pennsylvania operating area have increased. The increase was offset, in part, on a per-unit basis by the overall increase in total Shale sales volumes.
Current report
The CBM segment had earnings before income tax of $7 million for the three months ended March 31, 2026 compared to a loss before income tax of $2 million for the three months ended March 31, 2025.
Current report
•CBM production, ad valorem and other fees were $3 million for the three months ended March 31, 2026 compared to $2 million for the three months ended March 31, 2025. The increase in total dollars and unit costs was primarily due to the increase in the average CBM gas sales price.
Current report
Other Operating (Income) Expense
Current report
Other Expense
Current report
•Right‑of‑way sales represent revenue generated from granting third‑party access across the Company’s surface acreage. The $3 million increase in the period-to-period comparison was due to higher right‑of‑way activity in the current period.
Current report
•CNX may from time to time seek to repurchase and retire outstanding debt, issue new debt, or repurchase a portion of its outstanding common stock through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The amounts involved in any such transactions may be material. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information for discussion related to CNX’s outstanding debt and Note 15 – Stock Repurchase in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information for discussion related to the repurchase of CNXs outstanding common stock.
Current report
•Net income increased $546 million in the period-to-period comparison.
Removed paragraphs (61)
Previous report
Other Updates
Previous report
During the nine months ended September 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 report
On September 30, 2025, CNX entered into an agreement to acquire Utica Shale oil and gas rights, across approximately 23,000 nearly contiguous acres, that sit beneath the Apex Energy footprint. The cost of the acquisition will be approximately $50 million to be paid equally over a three-year period starting in January 2026. This transaction provides the critical strategic benefits CNX envisioned when acquiring Apex due to our ability to leverage the Apex infrastructure already in place to efficiently develop that leasehold.
Previous report
On July 4, 2025, the United States enacted into law the One, Big, Beautiful Bill Act ("OBBBA"). The OBBBA, which, among other things, allows for 100% bonus depreciation on a permanent basis for property acquired and placed in service on or after January 19, 2025, permanently reinstates the EBITDA limitation for the calculation of the deduction for interest expense after December 31, 2024, and allows permanent expensing rather than a 5-year amortization period for domestic research and development amounts paid or incurred in tax years beginning after December 31, 2024. The OBBBA primarily impacts CNX's taxable temporary differences and certain deferred tax assets and liabilities with no material impact to the estimated annual effective tax rate.
Previous report
Net Income
Previous report
The 26.8 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Previous report
•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. The increases were offset, in part, by the overall increase in total sales volumes.
Previous report
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) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Previous report
The decrease in total average Shale sales price was primarily due to a $0.46 per Mcfe decrease in the average NGL sales price and a $0.64 per Mcf change in the gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 115.7 Bcf of the Company's produced Shale gas sales volumes for the three months ended September 30, 2025 at an average gain of $0.18 per Mcf hedged. For the three months ended September 30, 2024, these financial hedges represented approximately 96.0 Bcf at an average gain of $0.91 per Mcf hedged. These decreases were offset, in part, by a $0.67 per Mcf increase in average natural gas sales price.
Previous report
Total operating costs and expenses for the Shale segment were $235 million for the three months ended September 30, 2025 compared to $198 million for the three months ended September 30, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:
Previous report
•Shale lease operating expenses were $21 million for the three months ended September 30, 2025 compared to $12 million for the three months ended September 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. The increase in unit costs was offset, in part, by the overall increase in volumes.
Previous report
•Shale production, ad valorem and other fees were $6 million for the three months ended September 30, 2025 compared to $5 million for the three months ended September 30, 2024. The increase in total dollars was primarily due to increased realized prices on natural gas. Unit costs remained flat in the period-to-period comparison due to the overall increase in volumes.
Previous report
•Shale transportation, gathering and compression costs were $81 million for the three months ended September 30, 2025 compared to $80 million for the three months ended September 30, 2024. The increase in total dollars was primarily due to higher repairs and maintenance expense and electrical compression expense offset, in part, by lower processing costs due to production mix. The decrease in unit costs was primarily due to the overall increase in volumes.
Previous report
•Depreciation, depletion and amortization costs attributable to the Shale segment were $127 million for the three months ended September 30, 2025 compared to $101 million for the three months ended September 30, 2024. These amounts included depletion on a units of production basis of $0.74 per Mcfe and $0.70 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 report
The CBM segment had a loss before income tax of $5 million for the three months ended September 30, 2025 compared to a loss before income tax of $9 million for the three months ended September 30, 2024.
Previous report
The total average CBM sales price increased $0.63 per Mcf primarily due to a $1.20 per Mcf increase in average gas sales price offset, in part, by a $0.57 per Mcf change in the gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 7.4 Bcf of the Company's produced CBM sales volumes for the three months ended September 30, 2025 at an average gain of $0.18 per Mcf hedged. For the three months ended September 30, 2024, these financial hedges represented approximately 7.9 Bcf at an average gain of $0.90 per Mcf hedged.
Previous report
•CBM lease operating expenses were $6 million for the three months ended September 30, 2025 compared to $5 million for the three months ended September 30, 2024. The increase in total dollars and unit costs was primarily due to an increase in repairs and maintenance expense. The increase in per unit costs was also due to the decrease in total CBM volumes.
Previous report
•Water income represents revenue generated when CNX accepts deliveries of produced water from third parties for reuse in the Company’s hydraulic fracturing operations, as well as from sales of freshwater to third parties.
Previous report
Other Operating Expense
Previous report
•Other increased in the period-to-period comparison due to multiple one-time items, none of which were individually material.
Previous report
Other Expense (Income)
Previous report
•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.
Previous report
Results of Operations -Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Previous report
Net Income
Previous report
CNX reported net income of $437 million, or earnings per diluted share of $2.57, for the nine months ended September 30, 2025, compared to net income of $54 million, or earnings per diluted share of $0.32, for the nine months ended September 30, 2024.
Previous report
Non-GAAP Financial Measures
Previous report
Non-GAAP Financial Measures Reconciliation
Previous report
The 67.9 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Previous report
•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. The increases were offset, in part, by the overall increase in total sales volumes.
Previous report
•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.
Previous report
Average Realized Price Reconciliation
Previous report
SEGMENT ANALYSIS for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024:
Previous report
SHALE SEGMENT
Previous report
The Shale segment had earnings before income tax of $581 million for the nine months ended September 30, 2025 compared to earnings before income tax of $449 million for the nine months ended September 30, 2024.
Previous report
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) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Previous report
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,326 million for the nine months ended September 30, 2025 compared to $746 million for the nine months ended September 30, 2024. The $580 million increase was primarily due to a 62.4% increase in the average sales price for natural gas and an 18.1% increase in total Shale sales volumes. The increase was offset, in part, by the 140.0% change in the (loss) gain on commodity derivative instruments.
Previous report
Total operating costs and expenses for the Shale segment were $682 million for the nine months ended September 30, 2025 compared to $587 million for the nine months ended September 30, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:
Previous report
•Shale production, ad valorem and other fees were $20 million for the nine months ended September 30, 2025 compared to $17 million for the nine months ended September 30, 2024. The increase in total dollars was primarily due to increased realized prices on natural gas. Unit costs remained flat in the period-to-period comparison due to the overall increase in volumes.
Previous report
•Shale transportation, gathering and compression costs were $238 million for the nine months ended September 30, 2025 compared to $236 million for the nine months ended September 30, 2024. The increase in total dollars was primarily due to higher repairs and maintenance and electrical compression expense offset, in part, by lower processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes. The decrease in unit costs was due to the increase in total Shale sales volumes offset, in part, by the increases in total dollars.
Previous report
COALBED METHANE (CBM) SEGMENT
Showing the first 40 of 61 passages. Open the source sections for the rest.
Reworded paragraphs (60)
Previous wording
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this Form 10-Q. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward-looking statements that are based on the current views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see "Part I. Item 1A. Risk Factors" and the section entitled "Forward-Looking Statements" contained in our Annual Report on Form 10-K for the year ended December 31, 2024, which we filed with the SEC on February 11, 2025 (the “2024 Form 10-K”). CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Current wording
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this Form 10-Q. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward-looking statements that are based on the current views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see "Part I. Item 1A. Risk Factors" and the section entitled "Forward-Looking Statements" contained in the 2025 Form 10-K. CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
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, 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.
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 heightened geopolitical developments, including in the Middle East, uncertainties in global financial markets, and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, all of which have contributed to increased volatility in global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to differ materially from those of prior periods. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
Previous wording
Total hedged natural gas production for the fourth quarter of 2025 is 121.9 Bcf. CNX's annual gas hedge position is shown in the table below:
Current wording
Total hedged natural gas production for the second quarter of 2026 is 115.1 Bcf. CNX's annual gas hedge position is shown in the table below:
Previous wording
1 Includes actual settlements of 286.7 Bcf.
Current wording
1 Includes actual settlements of 117.2 Bcf.
Previous wording
CNX reported net income of $202 million, or earnings per diluted share of $1.21, for the three months ended September 30, 2025, compared to net income of $66 million, or earnings per diluted share of $0.37, for the three months ended September 30, 2024.
Current wording
CNX had net income of $348 million, or earnings per diluted share of $2.18, for the three months ended March 31, 2026, compared to a net loss of $198 million, or loss per diluted share of $1.34, for the three months ended March 31, 2025.
Previous wording
Included in earnings for the three months ended September 30, 2025 was an unrealized gain on commodity derivative instruments of $110 million and a net gain on asset sales and abandonments of $68 million. Included in the earnings for the three months ended September 30, 2024 was an unrealized loss on commodity derivative instruments of $6 million and a net gain on asset sales and abandonments of $11 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the gain on asset sales and abandonments.
Current wording
Included in the earnings for the three months ended March 31, 2026 was an unrealized gain on commodity derivative instruments of $226 million and a net gain on asset sales and abandonments of $6 million. 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. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the gain on asset sales and abandonments, net.
Previous 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 production mix. The per unit decrease was offset, in part, by higher repairs and maintenance expense.
Current wording
•Lease operating expense decreased on a per unit basis primarily due to a decrease in water disposal costs as more water was reused in well completions, a decrease in well tending expense and the overall increase in total sales volumes.
Previous wording
•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate. The increase was offset, in part, by the overall increase in total sales volumes.
Current wording
•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate offset, in part, by the overall increase in total sales volumes.
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 67.9 Bcfe increase in total sales volumes and the $1.11 per Mcf increase in natural gas sales price, when excluding the impact of hedging. These increases were offset, in part, by the impact of the change in the (loss) gain on commodity derivative instruments - cash settlement related to the Company's hedging program.
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 4.6 Bcfe increase in total sales volumes and the $1.08 per Mcf increase in natural gas sales price, when excluding the impact of hedging. These increases were offset, in part, by the impact of the change in the loss on commodity derivative instruments - cash settlement related to the Company's hedging program.
Previous wording
The Shale segment had earnings before income tax of $171 million for the three months ended September 30, 2025 compared to earnings before income tax of $145 million for the three months ended September 30, 2024.
Current wording
The Shale segment had earnings before income tax of $249 million for the three months ended March 31, 2026 compared to earnings before income tax of $215 million for the three months ended March 31, 2025.
Previous wording
The Shale segment had natural gas, NGLs and oil/condensate revenue of $367 million for the three months ended September 30, 2025 compared to $237 million for the three months ended September 30, 2024. The $130 million increase was primarily due to a 39.6% increase in the average sales price for natural gas and a 21.8% increase in total Shale sales volumes. The increase was offset, in part, by the 81.0% change in the gain on commodity derivative instruments and a 13.1% decrease in the average sales price of NGLs.
Current wording
The Shale segment had natural gas, NGLs and oil/condensate revenue of $663 million for the three months ended March 31, 2026 compared to $508 million for the three months ended March 31, 2025. The $155 million increase was primarily due to a 29.1% increase in the average sales price for natural gas and a 3.5% increase in total Shale sales volumes.
Previous wording
The increase in total average Shale sales price was primarily due to a $1.11 per Mcf increase in average gas sales price and a $0.12 per Mcfe increase in the average NGL sales price. These increases were offset, in part, by a $0.98 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 339.0 Bcf of the Company's produced Shale gas sales volumes for the nine months ended September 30, 2025 at an average loss of $0.34 per Mcf hedged. For the nine months ended September 30, 2024, these financial hedges represented approximately 285.6 Bcf at an average gain of $0.84 per Mcf hedged.
Current wording
The Shale segment had a loss on commodity derivative instruments - cash settlements of $209 million for the three months ended March 31, 2026 compared to a loss of $103 million for the three months ended March 31, 2025. The notional amounts associated with these financial hedges represented approximately 106.1 Bcf of the Company's produced Shale gas sales volumes for the three months ended March 31, 2026 at an average loss of $1.97 per Mcf hedged. For the three months ended March 31, 2025, these financial hedges represented approximately 109.7 Bcf at an average loss of $0.92 per Mcf hedged.
Previous wording
•Shale lease operating expenses were $59 million for the nine months ended September 30, 2025 compared to $36 million for the nine months ended September 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.
Current wording
•Shale lease operating expenses were $16 million for the three months ended March 31, 2026 compared to $17 million for the three months ended March 31, 2025. The decrease in total dollars and unit costs was primarily related to a decrease in water disposal costs as more water was reused in well completions.
Previous wording
•Depreciation, depletion and amortization costs attributable to the Shale segment were $365 million for the nine months ended September 30, 2025 compared to $298 million for the nine months ended September 30, 2024. These amounts included depletion on a unit of production basis of $0.71 per Mcfe and $0.67 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Current wording
•Depreciation, depletion and amortization costs attributable to the Shale segment were $113 million for the three months ended March 31, 2026 compared to $106 million for the three months ended March 31, 2025. These amounts included depletion on a unit of production basis of $0.68 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 $52 million for the nine months ended September 30, 2025 compared to $50 million for the nine months ended September 30, 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 $16 million for the three months ended March 31, 2026 compared to $17 million for the three months ended March 31, 2025. The decrease in the period-to-period comparison was primarily due to a decrease in third-party gathering volumes.
Previous wording
The CBM segment had natural gas revenue of $33 million for the three months ended September 30, 2025 compared to $22 million for the three months ended September 30, 2024. The $11 million increase was primarily due to a 54.8% increase in the average sales price for natural gas in the current period offset, in part, by a 3.0% decrease in CBM sales volumes due to normal production declines.
Current wording
The CBM segment had natural gas revenue of $59 million for the three months ended March 31, 2026 compared to $43 million for the three months ended March 31, 2025. The $16 million increase was due to a 39.5% increase in the average sales price for natural gas in the current period offset, in part, by a 2.2% decrease in CBM sales volumes due to normal production declines.
Previous wording
The total average CBM sales price increased $0.34 per Mcf due to a $1.27 per Mcf increase in average natural gas sales price offset, in part, by a $0.92 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 21.8 Bcf of the Company's produced CBM sales volumes for the nine months ended September 30, 2025 at an average loss of $0.36 per Mcf hedged. For the nine months ended September 30, 2024, these financial hedges represented approximately 22.6 Bcf at an average gain of $0.84 per Mcf hedged.
Current wording
The total average CBM sales price increased $1.12 per Mcf due to a $1.83 per Mcf increase in average natural gas sales price offset, in part, by a $0.71 per Mcf change in the loss on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 6.9 Bcf of the Company's produced CBM sales volumes for the three months ended March 31, 2026 at an average loss of $1.92 per Mcf hedged. For the three months ended March 31, 2025, these financial hedges represented approximately 7.6 Bcf at an average loss of $0.92 per Mcf hedged.
Previous wording
Total operating costs and expenses for the CBM segment were $39 million for the three months ended September 30, 2025 compared to $38 million for the three months ended September 30, 2024. The increases 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 March 31, 2026 compared to $38 million for the three months ended March 31, 2025. The increase in total dollars and 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 September 30, 2025 and 2024. The increase in unit costs was due to the decrease in total CBM volumes.
Current wording
•CBM lease operating expenses were $6 million for both the three months ended March 31, 2026 and 2025. The increase in per unit costs was due to the decrease in total CBM volumes.
Previous wording
•Depreciation, depletion and amortization costs attributable to the CBM segment were $15 million for both the three months ended September 30, 2025 and 2024. These amounts included depletion on a units 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 was $14 million for both the three months ended March 31, 2026 and 2025. These amounts included depletion on a unit of production basis of $0.80 per Mcfe and $0.87 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Previous wording
The Other Segment had earnings before income tax of $100 million for the three months ended September 30, 2025 compared to a loss before income tax of $53 million for the three months ended September 30, 2024. The increase in total dollars is discussed below.
Current wording
The Other Segment had earnings before income tax of $172 million for the three months ended March 31, 2026 compared to a loss before income tax of $486 million for the three months ended March 31, 2025. The increase in total dollars is discussed below.
Previous wording
For the three months ended September 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $110 million. For the three months ended September 30, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $6 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.
Current wording
For the three months ended March 31, 2026, the Other Segment recognized an unrealized gain on commodity derivative instruments of $226 million. For the three months ended March 31, 2025, the Other Segment recognized an unrealized loss on commodity derivative instruments of $418 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
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 $9 million for the three months ended September 30, 2025 compared to $27 million for the three months ended September 30, 2024. Purchased gas costs were $9 million for the three months ended September 30, 2025 compared to $27 million for the three months ended September 30, 2024. The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes offset, in part, by an increase in average sales price.
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 $13 million for the three months ended March 31, 2026 compared to $11 million for the three months ended March 31, 2025. Purchased gas costs were $12 million for the three months ended March 31, 2026 compared to $11 million for the three months ended March 31, 2025. The period-to-period increase in purchased gas revenue was primarily due to an increase in the average sales price offset, in part, by the decrease in purchased gas volumes.
Previous wording
•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in the amount of equity awards.
Current wording
•Long-term equity-based compensation (non-cash) decreased in the period-to-period comparison due to a decrease in the amount of equity awards.
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 in the earlier part of the year.
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, including net credits recognized related to capacity optimization driven by colder weather earlier in the year, which reduced the Company’s overall expenses.
Previous wording
A net gain on asset sales and abandonments of $68 million was recognized in the three months ended September 30, 2025 compared to a net gain of $11 million in the three months ended September 30, 2024. The net gain recognized during the three months ended September 30, 2025 primarily relates to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million. The remaining net gain during the three months ended September 30, 2025, as well as, the net gain during the three months ended September 30, 2024 related to the sale of various non-core assets (rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Current wording
A net gain on asset sales and abandonments of $6 million was recognized in the three months ended March 31, 2026 compared to a net gain of $10 million in the three months ended March 31, 2025. The net gain recognized in the three months ended March 31, 2026 primarily relates to sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material.
Previous wording
A net gain on asset sales and abandonments of $95 million was recognized in the nine months ended September 30, 2025 compared to a net loss of $9 million in the nine months ended September 30, 2024. The net gain recognized in the nine months ended September 30, 2025 primarily relates to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million. The remaining net gain during the period primarily relates to sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material. The net loss recognized in the nine months ended September 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 a net gain on the sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material.. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Current wording
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. 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 nine months ended September 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.
Current wording
A loss on debt extinguishment of $12 million was recognized in the three months ended March 31, 2026 in connection with CNX's repurchase of $500 million aggregate principal amount of 6.00% Senior Notes due January 2029 at an average price equal to 101.6% of the principal amount. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such transactions occurred in the current period.
Previous wording
The $5 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 2025 offset, in part, by lower borrowings on the CNXM Credit Facility. See Note 8 – Revolving Credit Facilities and Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Current wording
The $2 million decrease in total interest expense was primarily due to lower borrowings on the CNX Credit Facility and a reduction in the amount of Convertible Notes outstanding pursuant to the exchange agreement that was entered into in December 2025. See Note 8 – Revolving Credit Facilities and Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Previous wording
The effective income tax rates for the three months ended September 30, 2025 and 2024 were 23.9% and 20.6%, respectively. The effective rate for the three months ended September 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.
Current wording
The effective income tax rates for the three months ended March 31, 2026 and 2025 were 18.7% and 27.5%, respectively. The effective tax rate for the three months ended March 31, 2026 and 2025 differs from the U.S. federal statutory rate of 21% primarily due to the impact of equity compensation, federal tax credits, and state taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Previous wording
•The Company’s cash on hand and access to additional liquidity. Cash, cash equivalents and restricted cash were $17 million as of September 30, 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 $6 million as of March 31, 2026 and $13 million as of December 31, 2025.
Previous wording
•Accounts and notes receivable - trade were $141 million as of September 30, 2025 and $180 million as of December 31, 2024. 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 were $210 million as of March 31, 2026 and $265 million as of December 31, 2025. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.
Previous wording
•As of September 30, 2025, CNX had approximately $329 million classified as current portion of long-term debt, primarily related to the Convertible Notes due in May 2026. CNX actively manages its debt, including maturities and interest rates, in order to maintain financial flexibility and support long-term strategic objectives. Management may, from time to time, refinance existing indebtedness, adjust the mix of variable- and fixed-rate debt, or pursue alternative financing sources to meet the Company’s cash and operational needs. 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.
Current wording
•As of March 31, 2026, CNX had approximately $208 million classified as current portion of long-term debt, primarily related to the Convertible Notes due in May 2026. CNX actively manages its debt, including maturities and interest rates, in order to maintain financial flexibility and support long-term strategic objectives. Management may, from time to time, refinance existing indebtedness, adjust the mix of variable- and fixed-rate debt, or pursue alternative financing sources to meet the Company’s cash and operational needs. 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.
Previous wording
•Capital expenditures are expected to range between $475 million to $500 million for the year ended December 31, 2025. For the nine months ended September 30, 2025, CNX had capital expenditures of $321 million.
Current wording
•Capital expenditures are expected to range between $556 million to $586 million for the year ended December 31, 2026. For the three months ended March 31, 2026, CNX had capital expenditures of $170 million.
Previous wording
•Production volumes are expected to range between 620.0 Bcfe and 625.0 Bcfe for the year ended December 31, 2025. For the nine months ended September 30, 2025, CNX had production volumes of 476.7 Bcfe.
Current wording
•Production volumes are expected to range between 605.0 Bcfe and 620.0 Bcfe for the year ended December 31, 2026. For the three months ended March 31, 2026, CNX had production volumes of 152.4 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 a net liability of $349 million at September 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.
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 $3 million at March 31, 2026 and a net liability of $296 million at December 31, 2025. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q for further discussion of our commodity risk management.
Previous wording
•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $310 million net change in commodity derivative instruments, a $124 million net increase in deferred income taxes, a $104 million increase in (gain) loss on asset sales and abandonments, net and a $92 million net increase for various other changes in working capital.
Current wording
•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $732 million net change in commodity derivative instruments, a $170 million net increase in deferred income taxes, a $12 million increase in loss on debt extinguishment and a $66 million net increase for various other changes in working capital.
Previous wording
•Capital expenditures decreased $114 million primarily due to a decrease in drilling and completions activity.
Current wording
•Capital expenditures increased $38 million primarily due to an increase in drilling and completions activity.
Previous wording
•Proceeds from asset sales increased $81 million primarily due to the sale of Marcellus Shale rights, other non-core oil and gas rights and various non-operated producing oil and gas assets primarily located in the Appalachian Basin. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Current wording
•Proceeds from asset sales increased $16 million primarily due to the sale of non-core oil and gas rights and various non-operated producing oil and gas assets primarily located in the Appalachian Basin.
Previous wording
•During the nine months ended September 30, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $518 million, subject to certain post-closing adjustments. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Current wording
•During the three months ended March 31, 2026, the Company released approximately $10 million of restricted cash that the Company was contractually obligated to maintain in an escrow account in accordance with the terms of the purchase agreement to acquire the natural gas upstream and associated midstream business of Apex Energy II, LLC, subject to certain post-closing adjustments. During the three months ended March 31, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $518 million, subject to certain post-closing adjustments See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Showing the first 40 of 60 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
The increase in total average Shale sales price was primarily due to a $1.04 per Mcf increase in average gas sales price and a $0.17 per Mcfe increase in the average NGL sales price. These increases were offset, in part, by a $0.80 per Mcf change in the loss on commodity derivative instruments - cash settlements.
Current report — wording carried from elsewhere
•CBM transportation, gathering and compression costs were $16 million for both the three months ended March 31, 2026 and 2025. The decrease in per unit costs was due to a decrease in electrical compression rates in the current period.
Rearranged previous paragraphs (24)
Previous report — wording carried elsewhere
The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 26.8 Bcfe increase in total sales volumes and the $0.70 per Mcf increase in natural gas sales price, when excluding the impact of hedging. The increases were offset, in part, by the impact of the change in the gain on commodity derivative instruments - cash settlement related to the Company's hedging program and the $2.76 per Bbl decrease in NGL prices.
Previous report — wording carried elsewhere
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 $18 million for both the three months ended September 30, 2025 and 2024.
Previous report — wording carried elsewhere
•Sales of environmental attributes include items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The decrease in the period-to-period comparison was primarily due to a decrease in the price received for the environmental attributes sold.
Previous report — wording carried elsewhere
•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Revenue and Operating Income.
Previous report — wording carried elsewhere
•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.
Previous report — wording carried elsewhere
Included in the earnings for the nine months ended September 30, 2025 was an unrealized gain on commodity derivative instruments of $148 million and a net gain on asset sales and abandonments of $95 million. Included in the earnings for the nine months ended September 30, 2024 was an unrealized loss on commodity derivative instruments of $149 million and a net loss on asset sales and abandonments of $9 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 report — wording carried elsewhere
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, 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. These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Previous report — wording carried elsewhere
1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
Previous report — wording carried elsewhere
Selected Natural Gas, NGL and Oil Production Financial Data
Previous report — wording carried elsewhere
The following table presents a summary of our total sales volumes, sales of natural gas, NGL and oil including cash settlements, natural gas, NGL and oil production costs and natural gas, NGL and oil production margin related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation above for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP):
Previous report — wording carried elsewhere
*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.
Previous report — wording carried elsewhere
Changes in the average costs per Mcfe were primarily related to the following items:
Previous report — wording carried elsewhere
•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate.
Previous report — wording carried elsewhere
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:
Previous report — wording carried elsewhere
NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGL, condensate, and natural gas prices.
Previous report — wording carried elsewhere
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 report — wording carried elsewhere
Unrealized Gain (Loss) on Commodity Derivative Instruments
Previous report — wording carried elsewhere
For the nine months ended September 30, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $148 million. For the nine months ended September 30, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $149 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 report — wording carried elsewhere
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 $31 million for the nine months ended September 30, 2025 compared to $53 million for the nine months ended September 30, 2024. Purchased gas costs were $29 million for the nine months ended September 30, 2025 compared to $51 million for the nine months ended September 30, 2024. The period-to-period decrease in purchased gas revenue was primarily due to a decrease in purchased gas sales volumes.
Previous report — wording carried elsewhere
•Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in Total Other Operating Expense.
Previous report — wording carried elsewhere
Exploration and Production Related Other Costs
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
•Other decreased in the period-to-period comparison primarily due to lower professional services and various other one-time items, none of which were individually material.
Previous report — wording carried elsewhere
The effective income tax rates for the nine months ended September 30, 2025 and 2024 were 24.5% and 26.5%, respectively. The effective tax rate for the nine months ended September 30, 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.