ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
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-K. 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 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.” CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
General
CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations. Examples include global events such as 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-K are not necessarily indicative of future operating results.
Natural Gas, NGL, and Oil Pricing
Prices for natural gas, NGLs and oil that CNX produces significantly impact revenue and cash flows. In the current economic environment, CNX expects that commodity prices for some or all of the commodities we produce will remain volatile. In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length as well as financial hedges. However, this market volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Inflation
The inflationary environment over the last few years, primarily related to steel, diesel fuel and labor, continues to present risk for CNX and the broader natural gas industry. If inflation were to increase materially for any extended period of time, and CNX is unable to successfully mitigate the impact, our costs could increase further, thus having a greater impact on our financial position. CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset any additional potential cost increases from inflation.
2025 Highlights:
• Proved developed reserves of 7.0 Tcfe as of December 31, 2025
• Total sales volumes of 629.0 Bcfe
• Shale sales volumes of 590.8 Bcfe
• Repurchased 16.9 million shares of CNX common stock for $528 million on the open market at an average price of $31.00 (see Note 5 – Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
• On January 27, 2025, CNX completed the acquisition of Apex Energy II, LLC, (“the Apex Transaction”) for cash consideration of approximately $518 million (see Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
2026 Outlook:
• Our 2026 annual sales volumes are expected to be approximately 605 - 620 Bcfe.
• Our 2026 capital expenditures are expected to be approximately $556 - $586 million.
• CNX’s 2026 capital expenditures includes the first of three annual payments of $16 million associated with an agreement that grants CNX the right to acquire Utica Shale oil and gas rights that sit beneath the legacy Apex Energy footprint.
Results of Operations:
The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 2025 to the year ended December 31, 2024. A similar discussion and analysis that compares year ended December 31, 2024 to the fiscal year ended December 31, 2023 is omitted from this Annual Report on Form 10-K and may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Annual Report on Form 10-K for the year ended December 31, 2024, which is incorporated herein by reference.
Net Income (Loss)
CNX reported net income of $633 million, or earnings per diluted share of $3.98, for the year ended December 31, 2025, compared to a net loss of $90 million, or a loss per diluted share of $0.60, for the year ended December 31, 2024.
Included in earnings for the year ended December 31, 2025 was an unrealized gain on commodity derivative instruments of $278 million and a net gain on asset sales and abandonments of $97 million. Included in the net loss for the year ended December 31, 2024 was an unrealized loss on commodity derivative instruments of $453 million and a net gain on asset sales and abandonments of $25 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the gain on asset sales and abandonments.
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, 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.
Non-GAAP Financial Measures Reconciliation
For the Years Ended December 31,
(Dollars in millions)
Total Revenue and Other Operating Income
(Deduct) Add:
Purchased Gas Revenue
(Gain) Loss on Commodity Derivative Instruments - Unrealized
Other Revenue and Operating Income
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure
Total Operating Expense
Deduct:
Depreciation, Depletion and Amortization (DD&A) - Corporate
Exploration and Production Related Other Costs
Purchased Gas Costs
Selling, General and Administrative Costs
Other Operating Expense
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1
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.
Selected Natural Gas, NGL and Oil Production Financial Data
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):
For the Years Ended December 31,
Variance
in Millions
Per Mcfe
in Millions
Per Mcfe
in Millions
Per Mcfe
Total Sales Volumes (Bcfe)*
Natural Gas, NGL and Oil Revenue
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure
Lease Operating Expense
Production, Ad Valorem, and Other Fees
Transportation, Gathering and Compression
Depreciation, Depletion and Amortization (DD&A)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure
*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
The 78.2 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
Changes in the average costs per Mcfe were primarily related to the following items:
• Lease operating expense increased on a per unit basis primarily due to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense. The increases were offset, in part, by the overall increase in total sales volumes.
• Transportation, gathering and compression expense decreased on a per unit basis primarily due to the overall increase in total sales volumes, a decrease in processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes. The per unit decreases were offset, in part, by higher repairs and maintenance expense.
• Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate. The increases were offset, in part, by the overall increase in total sales volumes.
Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:
For the Years Ended December 31,
in thousands (unless noted)
Variance
Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross NGL Revenue
Oil/Condensate:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Oil/Condensate Revenue
NATURAL GAS
Sales Volume (MMcf)
Sales Price ($/Mcf)
Gross Gas Revenue
Hedging Impact ($/Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement
The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure, was primarily due to the 83.7 Bcf increase in natural gas sales volumes and the $1.01 per Mcf increase in natural gas sales price, when excluding the impact of hedging. These increases were offset, in-part, by the impact of the change in the (loss) gain on commodity derivative instruments - cash settlement related to the Company's hedging program, the 5.5 Bcfe decrease in NGL sales volumes and the $0.30 per barrel decrease in NGL prices.
SEGMENT ANALYSIS for the year ended December 31, 2025 compared to the year ended December 31, 2024:
For the Year Ended
Difference to Year Ended
December 31, 2025
December 31, 2024
(in millions)
Shale
CBM
Other
Total
Shale
CBM
Other
Total
Natural Gas, NGLs and Oil Revenue
(Loss) Gain on Commodity Derivative Instruments
Purchased Gas Revenue
Other Revenue and Operating Income
Total Revenue and Other Operating Income
Lease Operating Expense
Production, Ad Valorem, and Other Fees
Transportation, Gathering and Compression
Depreciation, Depletion and Amortization
Exploration and Production Related Other Costs
Purchased Gas Costs
Selling, General and Administrative Costs
Other Operating Expense
Total Operating Costs and Expenses
Other Expense
Gain on Asset Sales and Abandonments, net
Loss on Debt Extinguishment
Interest Expense
Total Other Expenses
Total Costs and Expenses
Earnings (Loss) Before Income Tax
SHALE SEGMENT
The Shale segment had earnings before income tax of $760 million for the year ended December 31, 2025 compared to earnings before income tax of $617 million for the year ended December 31, 2024.
For the Years Ended December 31,
Variance
Percent
Change
Shale Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Oil/Condensate Sales Volumes (Bcfe)*
Total Shale Sales Volumes (Bcfe)*
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf)
Average Sales Price - NGLs (per Mcfe)*
Average Sales Price - Oil/Condensate (per Mcfe)*
Total Average Shale Sales Price (per Mcfe)
Average Shale Lease Operating Expenses (per Mcfe)
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Shale Production Costs (per Mcfe)
Total Average Shale Production Margin (per Mcfe)
*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The increase in total Shale sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (see Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information) and the timing of when new wells were turned-in-line. The increase in volumes was offset, in part, by normal production declines.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,764 million for the year ended December 31, 2025 compared to $1,080 million for the year ended December 31, 2024. The $684 million increase was due primarily to a 52.6% increase in the average sales price for natural gas and an 18.6% increase in Shale gas sales volumes. These increases were offset, in part, by a 10.6% decrease in NGLs sales volumes and a 1.4% decrease in the average sales price for NGLs.
The increase in total average Shale sales price was primarily due to a $1.01 per Mcf increase in average gas sales price. These increases were offset, in part, by a $0.88 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements and a $0.05 per Mcfe decrease in the average NGL sales price. The notional amounts associated with these financial hedges represented approximately 452.6 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2025 at an average loss of $0.38 per Mcf hedged. For the year ended December 31, 2024, these financial hedges represented approximately 389.7 Bcf at an average gain of $0.67 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $903 million for the year ended December 31, 2025 compared to $791 million for the year ended December 31, 2024. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:
• Shale lease operating expenses were $73 million for the year ended December 31, 2025 compared to $48 million for the year ended December 31, 2024. The increase in total dollars and unit costs was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions, higher well tending expense and higher repairs and maintenance expense. The increase in unit costs was offset, in part, by the increase in total Shale sales volumes.
• Shale production, ad valorem and other fees were $25 million for the year ended December 31, 2025 compared to $22 million for the year ended December 31, 2024. The increase in total dollars was primarily due to increased realized prices on natural gas and a change in production mix by state. Unit costs remained flat in the period-to-period comparison due to the overall increase in volumes.
• Shale transportation, gathering and compression costs were $317 million for the year ended December 31, 2025 compared to $316 million for the year ended December 31, 2024. The increase in total dollars was primarily due to higher repairs and maintenance and electrical compression expense offset, in part, by lower processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes. The decrease in unit costs was due to the increase in total Shale sales volumes.
• Depreciation, depletion and amortization costs attributable to the Shale segment were $488 million for the year ended December 31, 2025 compared to $405 million for the year ended December 31, 2024. These amounts included depletion on a unit of production basis of $0.72 per Mcfe and $0.68 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering services provided to third parties. The Shale segment had other revenue and operating income of $69 million for the year ended December 31, 2025 compared to $68 million for the year ended December 31, 2024. The increase in the period-to-period comparison was primarily due to an increase in third-party gathering volumes.
COALBED METHANE (CBM) SEGMENT
The CBM segment had a loss before income tax of $17 million for the year ended December 31, 2025 compared to a loss before income tax of $26 million for the year ended December 31, 2024.
For the Years Ended December 31,
Variance
Percent
Change
CBM Gas Sales Volumes (Bcf)
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)
Total Average CBM Sales Price (per Mcf)
Average CBM Lease Operating Expenses (per Mcf)
Average CBM Production, Ad Valorem and Other Fees (per Mcf)
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
Total Average CBM Production Costs (per Mcf)
Total Average CBM Production Margin (per Mcf)
The CBM segment had natural gas revenue of $148 million for the year ended December 31, 2025 compared to $105 million for the year ended December 31, 2024. The $43 million increase was primarily due to a 45.4% increase in the average sales price for natural gas in the current period offset, in part, by a 3.3% decrease in CBM sales volumes due to normal production declines.
The total average CBM sales price increased $0.40 per Mcf due to a $1.22 per Mcf increase in average gas sales price, offset, in part, by a $0.83 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 29.5 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2025 at an average loss of $0.39 per Mcf hedged. For the year ended December 31, 2024, these financial hedges represented approximately 30.6 Bcf at an average gain of $0.67 per Mcf hedged.
Total operating costs and expenses for the CBM segment were $154 million for the year ended December 31, 2025 compared to $152 million for the year ended December 31, 2024. The increase in total dollars and unit costs for the CBM segment were due to the following items:
• CBM lease operating expense was $24 million for the year ended December 31, 2025 compared to $22 million for the year ended December 31, 2024. The increase in total dollars and unit costs was primarily due to an increase in repair and maintenance and well tending expense. The increase in per unit costs was also due to the decrease in total CBM volumes.
• CBM production, ad valorem and other fees were $6 million for both the years ended December 31, 2025 and 2024. The increase in unit costs was primarily due to the decrease in total CBM volumes.
• CBM transportation, gathering and compression costs were $64 million for both the years ended December 31, 2025 and 2024. The increase in per unit costs was also due to the decrease in CBM gas sales volumes.
• Depreciation, depletion and amortization costs attributable to the CBM segment were $60 million for both the years ended December 31, 2025 and 2024. These amounts also included depletion on a unit of production basis of $0.85 per Mcfe for both periods. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER SEGMENT
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, sales of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative expense (“SG&A”), interest expense and income taxes.
The Other Segment had earnings before income tax of $60 million for the year ended December 31, 2025 compared to a loss before income tax of $711 million for the year ended December 31, 2024. The increase in total dollars is discussed below.
For the Years Ended December 31,
Variance
Percent Change
Other Gas Sales Volumes (Bcf)
Oil/Condensate Sales Volumes (Bcfe)*
Total Other Sales Volumes (Bcfe)*
*Oil/Condensate is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.
Unrealized Gain (Loss) on Commodity Derivative Instruments
For the year ended December 31, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $278 million. For the year ended December 31, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $453 million. The unrealized gain (loss) on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Purchased Gas Revenue and Costs
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 $45 million for the year ended December 31, 2025 compared to $59 million for the year ended December 31, 2024. Purchased gas costs were $43 million for the year ended December 31, 2025 compared to $57 million for the year ended December 31, 2024. The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes.
For the Years Ended December 31,
Variance
Percent Change
Purchased Gas Sales Volumes (in Bcf)
Purchased Gas Average Sales Price (per Mcf)
Purchased Gas Average Cost (per Mcf)
Other Revenue and Operating Income
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Sales of Environmental Attributes
Excess Firm Transportation Income
Water Income
Equity Loss from Affiliates
Total Other Revenue and Operating Income
• Sales of environmental attributes include items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The decrease in the period-to-period comparison was due to a decrease in the amount of environmental attributes sold and a decrease in the price received.
• 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.
• Water income represents revenue generated when CNX accepts deliveries of produced water from third parties for reuse in the Company’s hydraulic fracturing operations, as well as from sales of freshwater to third parties. Water income increased in the period-to-period comparison primarily due to an increase in third-party sales in the current period.
Exploration and Production Related Other Costs
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Seismic Activity
Land Rentals
Lease Expiration Costs
Other Expense
Total Exploration and Production Related Other Costs
• Seismic activity expense in the current period primarily relates to the acquisition of three-dimensional seismic data.
SG&A includes costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Salaries, Wages and Employee Benefits
Short-Term Incentive Compensation
Contributions and Advertising
Long-Term Equity-Based Compensation (Non-Cash)
Other
Total SG&A
• Salaries, wages and employee benefits decreased in the period-to-period comparison due to a reduction in headcount that occurred at the end of the first quarter of 2025.
• Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in equity awards issued in the current year.
• Other decreased in the period-to-period comparison primarily due to lower professional services and various other one-time items, none of which were individually material.
Other Operating Expense
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Unutilized Firm Transportation and Processing Fees
Environmental Attribute Fees
Water Expense
Idle Equipment and Service Charges
Insurance Expense
Inventory Adjustments
Virginia Flood Expense
Other
Total Other Operating Expense
• 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.
• Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Revenue and Operating Income. The decrease in fees in the period-to-period comparison relates to the decrease in sales above.
Other Expense (Income)
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Other Income
Litigation Recoveries
Interest Income
Right-of-Way Sales
Other
Total Other Income
Other Expense
Other Land Rental Expense
Professional Services
Bank Fees
Other Corporate Expense
Total Other Expense
Total Other Expense (Income)
• 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.
• Other corporate expense primarily consists of severance expense related to the reduction in headcount that occurred at the end of the first quarter of 2025.
Gain on Asset Sales and Abandonments, net
A net gain on asset sales of $97 million was recognized in the year ended December 31, 2025, compared to a net gain of $25 million in the year ended December 31, 2024. The net gain recognized during the year ended December 31, 2025 primarily related to the sale of approximately 7,500 acres of Marcellus Shale rights primarily located in Monroe County, Ohio, for net proceeds of $57 million. The remaining net gain during the period primarily relates to sale of various other non-core assets (primarily rights-of-way, surface acreage and other non-operated oil and gas interests and assets) none of which were individually material.
The net gain during the year ended December 31, 2024 primarily relates to a $51 million gain on the sale of various non-core assets (primarily rights-of-way, surface acreage and the interest in various non-operated oil and gas assets), none of which were individually material. These gains were offset, in part, by a $26 million loss on the sale of a non-core pipeline to a third party.
See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Loss on Debt Extinguishment
A loss on debt extinguishment of $1 million was recognized in the year ended December 31, 2025, compared to $7 million in the year ended December 31, 2024. The loss recognized during the year ended December 31, 2025 was in connection with CNX’s issuance of common stock in exchange for $122 million aggregate principal amount of its 2.25% Convertible Notes due May 2026. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The loss recognized during the year ended December 31, 2024 was in connection with CNX’s repurchase of $350 million aggregate principal amount of its 7.25% Senior Notes due March 2027 at an average price equal to 101.9% of their principal amount. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Interest Expense
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Total Interest Expense
The $19 million increase in total interest expense was primarily due to higher borrowings on both the CNX and CNXM Credit Facilities and higher principal balances related to the long-term debt that was issued in 2025. The increase was offset, in part, by lower weighted average interest rates on both the CNX and CNXM Credit Facilities. See Note 10 – Revolving Credit Facilities and Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Income Taxes
For the Years Ended December 31,
(in millions)
Variance
Percent Change
Total Company Income (Loss) Before Income Tax
Income Tax Expense (Benefit)
Effective Income Tax Rate
The effective income tax rate was 21.1% for the year ended December 31, 2025 compared to 24.8% for the year ended December 31, 2024. The effective tax rates for the years ended December 31, 2025 and 2024 differ from the U.S. federal statutory rate of 21% primarily due to federal tax credits, state income taxes including tax rate changes, equity compensation, and the impact of changes in certain state deferred tax asset valuation allowances. See Note 6 – Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Liquidity and Capital Resources
Overview, Sources and Uses
CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CNX currently believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments, if any, and to provide required letters of credit for at least the next twelve months and the foreseeable future thereafter. Nevertheless, the ability of CNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, some of which are beyond CNX’s control.
From time to time, CNX is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.
CNX continuously reviews its liquidity and capital resources. If market conditions were to change, for instance due to a significant decline in commodity prices, and our revenue was reduced significantly or operating and capital costs were to increase significantly, our cash flows and liquidity could be reduced.
As of December 31, 2025, CNX was in compliance with all of its debt covenants. After considering the potential effect of a significant decline in commodity prices, CNX currently expects to remain in compliance with its debt covenants.
CNX frequently evaluates potential acquisitions. CNX has historically funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CNX on terms which CNX finds acceptable, or at all.
Factors that may Impact our Liquidity
• The Company’s cash on hand and access to additional liquidity. Cash, cash equivalents and restricted cash were $13 million as of December 31, 2025 and $55 million as of December 31, 2024.
• Accounts and notes receivable - trade as of December 31, 2025 and 2024 were $265 million and $180 million, respectively. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.
• Capital expenditures are expected to range between $556 million to $586 million for the year ended December 31, 2026. For the year ended December 31, 2025, CNX had capital expenditures of $495.0 million.
• Production volumes are expected to range between 605 Bcfe and 620 Bcfe for the year ended December 31, 2026. For the year ended December 31, 2025, CNX had production volumes of 629.0 Bcfe.
• Prices for natural gas and NGLs are volatile, and an extended decline in the prices we receive for our natural gas and NGLs will adversely affect our financial condition and cash flows.
• In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas and NGL swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of $296 million at December 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 7A., “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-K for further discussion of our commodity risk management.
• CNX may from time to time seek to repurchase and retire outstanding debt, issue new debt, or repurchase a portion of its outstanding common stock through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The amounts involved in any such transactions may be material. See Note 12: Long Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information for discussion related to CNX’s outstanding debt and Note 5 – Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information for discussion related to the repurchase of CNXs outstanding common stock.
Cash Flows (in millions)
For the Years Ended December 31,
Change
Cash Provided by Operating Activities
Cash Used in Investing Activities
Cash Used in Financing Activities
Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:
• Net income increased $724 million in the period-to-period comparison.
• Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $721 million net change in commodity derivative instruments, a $195 million net increase in deferred income taxes, a $72 million change in the gain on asset sales and abandonments, net, and an $87 million net increase from various other changes in working capital.
Cash used in investing activities changed in the period-to-period comparison primarily due to the following items:
• Capital expenditures decreased $45 million primarily due to a decrease in drilling and completions activity in Marcellus Shale.
• Proceeds from asset sales increased $47 million primarily due to the sale of Marcellus Shale rights primarily located in Monroe County, Ohio to a third party during the year ended December 31, 2025 for cash proceeds of $57 million. The remaining variance includes the sale of various non-core assets, rights-of-way, surface acreage and other oil and gas royalty interest in both periods. See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
• During the year ended December 31, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $518 million, subject to certain post-closing adjustments. See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Cash used in financing activities changed in the period-to-period comparison primarily due to the following items:
• Proceeds from borrowings under the CNXM Credit Facility increased $74 million and repayments under the CNXM Credit Facility decreased $32 million.
• Proceeds from borrowings under the CNX Credit Facility increased $793 million and repayments under the CNX Credit Facility increased $627 million.
• During the year ended December 31, 2025, CNX issued an additional $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of par. This issuance also included an underwriter discount and other issuance costs of $1.5 million, for net cash proceeds of $198.5 million. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
• During the year ended December 31, 2024, CNX paid $357 million to repurchase $350 million aggregate principal amount of CNX 7.25% Senior Notes due March 2027 at a price of 101.9% of their principal amount. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
• During the year ended December 31, 2024, CNX issued $400 million aggregate principal amount of CNX 7.25% Senior Notes due March 2032 at par. The issuance included an underwriter discount and other issuance costs of $5 million, for net cash proceeds of $395 million. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
• During the years ended December 31, 2025 and 2024, CNX repurchased $524 million and $184 million, respectively, of its common stock on the open market.
• During the year ended December 31, 2025, debt issuance and financing fees decreased $14 million primarily due to amending both the CNX and CNXM Credit Facilities in 2024. See Note 10 – Revolving Credit Facilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Commitments and Significant Contractual and Other Obligations
The following is a summary of the Company's significant contractual and other obligations at December 31, 2025 (in thousands):
Payments due by Year
Less Than
1 Year
1-3 Years
3-5 Years
More Than
5 Years
Total
Purchase Order Firm Commitments
Gas Firm Transportation and Processing
Long-Term Debt
Interest on Long-Term Debt
Finance Lease Obligations
Interest on Finance Lease Obligations
Operating Lease Obligations
Interest on Operating Lease Obligations
Long-Term Liabilities—Employee Related (a)
Other Long-Term Liabilities (b)
Total Contractual Obligations (c)
(a) Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.
(b) Other long-term liabilities include royalties and other long-term liability costs.
(c) The table above does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
Off-Balance Sheet Transactions
CNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Audited Consolidated Financial Statements. CNX uses a combination of surety bonds, corporate guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected in the Consolidated Balance Sheet at December 31, 2025. Management believes these items will expire without being funded. See Note 20 – Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CNX.
Debt
At December 31, 2025, CNX had total long-term debt of $2,429 million, including the current portion of long-term debt of $208 million and excluding unamortized debt issuance costs. This long-term debt consisted of:
• An aggregate principal amount of $600 million of 7.25% Senior Notes due March 2032 less $5 million of unamortized discount. Interest on the notes is payable March 1 and September 1 of each year. Payment on the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
• An aggregate principal amount of $500 million of 6.00% Senior Notes due January 2029. Interest on the notes is payable January 15 and July 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
• An aggregate principal amount of $500 million of 7.375% Senior Notes due January 2031, less $4 million of unamortized discount. Interest on the notes is payable January 15 and July 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX’s subsidiaries but does not include CNXM (or its subsidiaries or general partner).
• An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $3 million of unamortized discount. Interest on the notes is payable April 15 and October 15 of each year. Payment on the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of these notes.
• An aggregate principal amount of $209 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $1 million of unamortized discount and issuance costs. Interest on the notes is payable May 1 and November 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). The Convertible Notes are classified as short-term debt at December 31, 2025.
• An aggregate principal amount of $200 million in outstanding borrowings under the CNX Credit Facility. Payment of the principal and interest on the CNX Credit Facility is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
• An aggregate principal amount of $33 million in outstanding borrowings under the CNXM Credit Facility. Payment of the principal and interest on the CNXM Credit Facility is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of the CNXM Facility.
During the year ended December 31, 2025, CNX entered into a privately negotiated exchange agreement with a limited number of holders of its 2.25% Convertible Senior Notes due 2026 to exchange approximately $122 million aggregate principal amount of Notes for consideration consisting of an aggregate of approximately $1 million in cash (including accrued interest) and 9,509,188 shares of common stock. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
During the year ended December 31, 2025, CNX issued $200 million aggregate principal amount of additional 7.25% senior notes due 2032 (the "New Notes") at a price of 100.5% of par, plus accrued interest from September 1, 2024 to the date of closing less an underwriter discount and other issuance costs of $2 million. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Total Equity and Dividends
CNX had total equity of $4,337 million at December 31, 2025 compared to $4,098 million at December 31, 2024. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.
The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance can be given that CNX will pay dividends in the future. CNX has not paid dividends on its common stock since 2016. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX, and such other factors as CNX’s Board of Directors deems relevant. In addition, CNX’s ability to pay dividends is limited by the covenants governing the CNX Credit Facility and the indentures governing certain of CNX’s Senior Notes.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements. See Note 1 – Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates on an on-going basis. Actual results could differ from those estimates upon the subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting estimates are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Income Taxes
Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2025, prior to consideration of valuation allowances on deferred tax assets, CNX had deferred tax liabilities in excess of deferred tax assets of approximately $825 million. At December 31, 2025, CNX had a valuation allowance of $32 million on deferred tax assets.
CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation of the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, which are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon the subsequent resolution of identified matters. See Note 6 – Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company’s uncertain tax liabilities.
Natural Gas, NGL, Condensate and Oil Reserve (“Natural Gas Reserve”) Values
Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable natural gas reserves, including many factors beyond our control. As a result, estimates of economically recoverable natural gas reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Our natural gas reserves are reviewed by independent experts each year. Some of the factors and assumptions which impact economically recoverable reserve estimates include:
• geological conditions;
• historical production from the area compared with production from other producing areas;
• the assumed effects of regulations and taxes by governmental agencies;
• assumptions governing future prices; and
• future operating costs.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of gas attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. See “Risk Factors” in Item 1A of this Form 10-K for a discussion of the uncertainties in estimating our reserves.
The Company believes that the accounting estimate related to oil and gas reserves is a “critical accounting estimate” because the Company must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the estimated timing of development expenditures. Future results of operations and strength of the balance sheet for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. See “Impairment of Long-Lived Assets” below for additional information regarding the Company’s oil and gas reserves.
Impairment of Long-Lived Assets
The carrying values of the Company's proved oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Impairment tests require that the Company first compare future undiscounted cash flows by asset group to their respective carrying values. The Company groups its assets by geological and geographical characteristics. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital. There were no indicators of impairment related to the Company's proved oil and gas properties in the years ended December 31, 2025 or 2024.
CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators of potential impairment include, but are not limited to, changes brought about by economic factors, commodity price outlooks, our geologists’ evaluation of the property, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, potential shifts in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. There were no indicators of impairment related to the Company’s unproved properties in the years ended December 31, 2025 or 2024.
The Company believes that the accounting estimates related to the impairment of long-lived assets are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. In addition, when indicators are identified the Company must determine the estimated undiscounted future cash flows as well as the impact of commodity price outlooks. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates, such as different assumptions in projected revenues, future commodity prices or the weighted average costs of capital, could materially impact the calculated fair value and the resulting determinations about the impairment of long-lived assets which could materially impact the Company’s results of operations and financial position. Additionally, future estimates may differ materially from current estimates and assumptions.
Impairment of Goodwill
Goodwill is not amortized, but rather it is evaluated for impairment annually during the fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. We may assess goodwill for impairment by first performing a qualitative assessment, which considers specific factors, based on the weight of evidence, and the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount using the qualitative assessment, we perform a quantitative impairment test. From time to time, we may also bypass the qualitative assessment and proceed directly to the quantitative impairment test. Under the quantitative goodwill impairment test, the fair value of a reporting unit is compared to its carrying amount. If the quantitative goodwill impairment test indicates that the goodwill is impaired, an is recorded, which is the difference between carrying value of the reporting unit and its fair value, with the not to exceed the amount of goodwill recorded. The estimation of fair value of a reporting unit is determined using the income approach and/or the market approach as described below.
The income approach is a quantitative evaluation to determine the fair value of the reporting unit. Under the income approach we determine the fair value based on estimated future cash flows discounted by an estimated weighted-average cost of capital plus a forecast risk, which reflects the overall level of inherent risk of the reporting unit and the rate of return a market participant would expect to earn. The inputs used for the income approach were significant unobservable inputs, or Level 3 inputs, as described in the accounting fair value hierarchy. CNX determined the fair value based on estimated future cash flows and earnings before deducting net interest expense (interest expense less interest income) and income taxes (EBITDA - a non-GAAP financial measure) and also included estimates for capital expenditures, discounted to present value using a risk-adjusted rate, which management feels reflects the overall level of inherent risk of the reporting unit. Cash flow projections were derived from board approved budgeted amounts, a seven-year operating forecast and an estimate of future cash flows. Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur.
The market approach measures the fair value of a reporting unit through the analysis of recent transactions and/or financial multiples of comparable businesses. Consideration is given to the financial conditions and operating performance of the reporting unit being valued relative to those publicly-traded companies operating in the same or similar lines of business.
The determination of the fair value requires us to make significant estimates and assumptions. These estimates and assumptions primarily include but are not limited to: the selection of appropriate peer group companies; control premiums appropriate for acquisitions in the industries in which we compete; discount rates; terminal growth rates; and forecasts of revenue, operating income, depreciation, depletion, and amortization and capital expenditures. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from business risks as described in Part I. Item 1A. “Risk Factors” of this Form 10-K. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. Although we believe our estimates of fair value are reasonable, actual financial results could differ from those estimates due to the inherent uncertainty involved in making such estimates. Changes in assumptions concerning future financial results or other underlying assumptions could have a significant impact on either the fair value of the reporting unit, the amount of any goodwill impairment charge, or both.
For the Company’s annual impairment assessment during the fourth quarter of 2025, the Company elected to perform a qualitative impairment test on its goodwill and concluded that it is more likely than not that the fair value exceeded the carrying value and goodwill was not impaired.
The Company believes that the accounting estimates related to goodwill are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in the Company's stock price, weighted-average cost of capital, terminal growth rates, changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market capitalization and industry multiples. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about goodwill impairment which could materially impact the Company’s results of operations and financial position. Additionally, future estimates may differ materially from current estimates and assumptions.
Recent Accounting Pronouncements
See Note 1 – Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for a summary of recent accounting pronouncements.
