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Item 7. Management’s Discussion and Analysis

2024-02-08 compared with 2023-02-09 · 141 added, 135 removed, 450 unchanged (38% of the section changed)

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

Examples include the conflict between Russia and Ukraine that has had an impact on global commodity prices.

More information regarding these considerations is located in Item 1A Risk Factors.

Examples include global events such as the conflict between Russia and Ukraine and the announcement by the Organization of the Petroleum Exporting Countries (OPEC) to extend production cuts through the first quarter of 2024, both of which have had an impact on global commodity prices.

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

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Prices for natural gas, NGLs and oil that CNX produces significantly impact revenue and cash flows.

Natural gas, NGL and oil benchmark prices increased significantly during the year ended December 31, 2022 as compared to the year ended December 31, 2021.

As a result, CNX experienced a significant increase in revenue and cash flows during the year ended December 31, 2022.

In the current economic environment, CNX expects that commodity prices for some or all of the commodities we produce will remain volatile.

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

CNX experienced higher capital costs from inflation during the year ended December 31, 2022.

If inflation continues at its current levels or increases further for any extended period of time, and CNX is unable to successfully mitigate the impact, our costs could increase further, having a greater impact on our financial position.

Rising interest rates could also increase our borrowing costs on new debt and our current revolver and could affect the fair value of our investments.

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

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

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

New Technologies Update

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

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

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

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

carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances.

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

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

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

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

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

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

2023 Highlights:

• Proved developed reserves of 6.2 Tcfe, 5% higher than 2021.

• Total gas production of 580.2 Bcfe.

• Shale production of 536.1 Bcfe.

• Repurchased $568 million or 33.5 million shares of CNX common stock on the open market.

• Reduced long-term debt by $8 million.

• Proved developed reserves of 6.0 Tcfe.

• Total sales volumes of 560.4 Bcfe.

• Shale sales volumes of 519.5 Bcfe.

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

2024 Outlook:

• Our 2023 annual production is expected to be approximately 555-575 Bcfe.

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

See New Technologies section in “Item 1.

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

• Our 2024 capital expenditures are expected to be approximately $575-$625 million.

• Our 2024 sales of environmental attributes, net of corresponding fees, are expected to be approximately $75 million.

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

Risk Factors" of this Form 10-K.

Results of Operations:

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A similar discussion and analysis that compares year ended December 31, 2022 to the fiscal year ended December 31, 2021 is omitted from this Form 10-K and may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Form 10-K for the year ended December 31, 2022, which is incorporated herein by reference.

Net Loss Attributable to CNX Resources Shareholders

CNX reported a net loss attributable to CNX Resources shareholders of $142 million, or a loss per diluted share of $0.75, for the year ended December 31, 2022, compared to a net loss attributable to CNX Resources shareholders of $499 million, or a loss per diluted share of $2.31, for the year ended December 31, 2021.

Included in the loss for the year ended December 31, 2022 was an unrealized loss on commodity derivative instruments of $851 million.

Included in the loss for the year ended December 31, 2021 was an unrealized loss on commodity derivative instruments of $1,094 million.

Net Income (Loss)

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

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

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

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

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.

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

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.

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Total Revenue and Other Operating Income $ 3,435 $ 1,261

Add (Deduct):

(Deduct) Add:

Purchased Gas Revenue (75) (186)

Loss on Commodity Derivative Instruments 851 1,094

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

Other Revenue and Operating Income (130) (87)

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Total Operating Expense $ 1,192 $ 1,321

Add (Deduct):

Depreciation, Depletion and Amortization (DD&A) - Corporate (14) (13)

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Natural Gas, NGL and Oil Revenue $ 1,302 $ 2.29 $ 3,652 $ 6.52 $ (2,350) $ (4.23)

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (1,813) (3.35) (539) (0.98) (1,274) (2.37)

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

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

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

The 10.0 Bcfe decrease in volumes in the period-to period comparison was primarily due to various operational delays and challenges, including a loss related to the abandonment of a Shale wellbore (see Gain on Asset Sales and Abandonments, net for more information).

The decrease was also due to normal production declines, offset in part by the turn-in-line of new

wells throughout 2022.

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

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

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

• Lease operating expense increased on a per unit basis as a result of an increase in repairs and maintenance expense, including both routine and water storage system maintenance, and an increase in water disposal costs driven by more produced water being taken to disposal instead of being reused in well completions.

• Production, ad valorem and other fees increased on a per unit basis as a result of increased realized prices on natural gas and NGLs.

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

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

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

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

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Hedging Impact ($/Mcf) $ 0.32 $ (3.35) $ 3.67 109.6 %

Loss on Commodity Derivative Instruments - Cash Settlement $ (1,812,777) $ (539,016) $ (1,273,761) (236.3) %

The increase in gross revenue was primarily the result of the $2.72 per Mcf increase in natural gas prices, when excluding the impact of hedging, and the $4.26 per Bbl increase in NGL prices.

These increases were offset, in part, by the impact of the change in the realized loss on commodity derivative instruments related to the Company's hedging program and the 10.0 Bcfe decrease in sales volumes.

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

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

These decreases were offset, in-part, by the impact of the change in the gain (loss) on commodity derivative instruments - cash settlement related to the Company's hedging program.

SEGMENT ANALYSIS for the year ended December 31, 2023 compared to the year ended December 31, 2022:

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Natural Gas, NGLs and Oil Revenue $ 1,170 $ 131 $ 1 $ 1,302 $ (2,165) $ (184) $ (1) $ (2,350)

Loss on Commodity Derivative Instruments (1,673) (139) (852) (2,664) (1,181) (92) 242 (1,031)

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

Purchased Gas Revenue — — 75 75 — — (111) (111)

Other Revenue and Operating Income 67 — 63 130 (2) — 45 43

Total Revenue and Other Operating Income (Loss) 1,731 176 (646) 1,261 153 29 322 504

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

Lease Operating Expense 44 19 — 63 (6) 2 — (4)

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Total Costs and Expenses 746 142 324 1,212 (45) 10 (226) (261)

Earnings (Loss) Before Income Tax $ 940 $ 44 $ (1,196) $ (212) $ 166 $ 15 $ 244 $ 425

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

SHALE SEGMENT

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Average Sales Price - Gas (per Mcf) $ 2.11 $ 6.19 $ (4.08) (65.9) %

Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ (3.37) $ (0.98) $ (2.39) (243.9) %

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

Average Sales Price - NGLs (per Mcfe)* $ 3.54 $ 6.36 $ (2.82) (44.3) %

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The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,170 million for the year ended December 31, 2023 compared to $3,335 million for the year ended December 31, 2022.

The $1,346 million increase was due primarily to a 76.4% increase in the average sales price for natural gas and a 12.6% increase in the average sales price of NGLs, offset in part by a 0.8% decrease in total Shale gas sales volumes.

The decrease in total Shale gas sales volumes was primarily due to various operational delays and challenges including a loss related to the abandonment of a Shale wellbore (see Gain on Asset Sales and Abandonments, net for more information).

The decrease was also due to normal production declines, offset in part by the turn-in-line of new wells throughout 2022.

The increase in total average Shale sales price was primarily due to a $2.68 per Mcf increase in average gas sales price and a $0.71 per Mcfe increase in the average NGL sales price.

These increases were offset in part by a $2.39 per Mcf change in the realized loss on commodity derivative instruments.

The notional amounts associated with these financial hedges represented approximately 424.7 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2022 at an average loss of $3.94 per Mcf hedged.

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

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

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

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

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

The notional amounts associated with these financial hedges represented approximately 399.2 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2023 at an average gain of $0.37 per Mcf hedged.

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

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• Shale lease operating expenses were $44 million for the year ended December 31, 2023 compared to $50 million for the year ended December 31, 2022.

The increases in total dollars and unit costs were primarily related to an increase in repairs and maintenance expense, including both routine and water storage system maintenance, and an increase in water disposal costs as more water had to be taken to disposal instead of being reused in well completions.

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

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

The increases in total dollars and unit costs were primarily due to increased realized prices on natural gas and natural gas liquids.

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

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

The increases in total dollars and unit costs were primarily related to an increase in repairs and maintenance expense, an increase in processing costs due to a wetter production mix and increased electrical compression expense.

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

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

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

• Depreciation, depletion and amortization costs attributable to the Shale segment were $365 million for the year ended December 31, 2023 compared to $389 million for the year ended December 31, 2022.

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Average Sales Price - Gas (per Mcf) $ 3.22 $ 7.20 $ (3.98) (55.3) %

Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ (3.18) $ (0.93) $ (2.25) (241.9) %

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

Total Average CBM Sales Price (per Mcf) $ 3.51 $ 4.01 $ (0.50) (12.5) %

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The CBM segment had natural gas revenue of $131 million for the year ended December 31, 2023 compared to $315 million for the year ended December 31, 2022.

The $121 million increase was primarily due to an 84.1% increase in the average sales price for natural gas in the current period.

The natural gas price increases were partially offset by the 11.7% decrease in CBM gas sales volumes due to normal production declines.

The total average CBM sales price increased $1.04 per Mcf due to a $3.29 per Mcf increase in average gas sales price, offset in part by a $2.25 per Mcf change in the realized loss on commodity derivative instruments resulting from the Company's hedging program.

The notional amounts associated with these financial hedges represented approximately 35.5 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2022 at an average loss of $3.92 per Mcf hedged.

The $184 million decrease was primarily due to a 55.3% decrease in the average sales price for natural gas in the current period and a 7.1% decrease in CBM gas sales volumes due to normal production declines.

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

The notional amounts associated with these financial hedges represented approximately 31.9 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2023 at an average gain of $0.36 per Mcf hedged.

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

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• CBM lease operating expense was $19 million for the year ended December 31, 2023 compared to $17 million for the year ended December 31, 2022.

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

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

• CBM production, ad valorem and other fees were $7 million for the year ended December 31, 2023 compared to $12 million for the year ended December 31, 2022.

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

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

• CBM transportation, gathering and compression costs were $66 million for the year ended December 31, 2023 compared to $49 million for the year ended December 31, 2022.

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

• Depreciation, depletion and amortization costs attributable to the CBM segment were $54 million for the year ended December 31, 2022 compared to $58 million for the year ended December 31, 2021 due to lower volumes in the current period.

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

• Depreciation, depletion and amortization costs attributable to the CBM segment were $50 million for the year ended December 31, 2023 compared to $54 million for the year ended December 31, 2022.

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

These amounts included depletion on a unit of production basis of $0.64 per Mcfe and $0.65 per Mcfe, respectively.

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It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, New Technologies, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes.

The Other Segment had a loss before income tax of $1,196 million for the year ended December 31, 2022 compared to a loss before income tax of $1,440 million for the year ended December 31, 2021.

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

The increase in total dollars is discussed below.

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Other Gas Sales Volumes (Bcf) 0.3 0.4 (0.1) (25.0) %

Loss on Commodity Derivative Instruments

Unrealized Gain (Loss) on Commodity Derivative Instruments

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

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

For the year ended December 31, 2021, the Other Segment recognized an unrealized loss on commodity derivative instruments of $1,094 million.

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

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

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

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Purchased gas costs were $70 million for the year ended December 31, 2023 compared to $185 million for the year ended December 31, 2022.

The period-to-period increase in purchased gas revenue was due to an increase in average sales price and an increase in purchased gas sales volumes.

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

For the Years Ended December 31,

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(in millions) 2023 2022 Variance Percent Change

Sales of Environmental Attributes $ 41 $ — $ 41 100.0 %

Excess Firm Transportation Income 16 12 4 33.3 %

Equity Income from Affiliates 3 1 2 200.0 %

Water Income 3 5 (2) (40.0) %

Excess Firm Transportation Income 12 12 — — %

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

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

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

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

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

• Sales of environmental attributes includes 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.

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

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

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

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

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

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

Exploration and Production Related Other Costs

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(in millions) 2023 2022 Variance Percent Change

Exploratory Well Costs $ — $ 9 $ (9) (100.0) %

Lease Expiration Costs $ 6 $ 1 $ 5 500.0 %

Permitting Expense — 1 (1) (100.0) %

Land Rentals 4 4 — — %

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Total Exploration and Production Related Other Costs $ 10 $ 8 $ 2 25.0 %

• Exploratory well costs relate to the write-off of an exploratory well that was still being evaluated at the end of 2020.

During the year ended December 31, 2021, the Company determined it would be more economical to access the underlying reserves from a different location.

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

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

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

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

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

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(in millions) 2023 2022 Variance Percent Change

Long-Term Equity-Based Compensation (Non-Cash) $ 20 $ 16 $ 4 25.0 %

Salaries, Wages and Employee Benefits 31 31 — — %

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

Long-Term Equity-Based Compensation (Non-Cash) 16 17 (1) (5.9) %

Other 59 50 9 18.0 %

Total SG&A $ 125 $ 122 $ 3 2.5 %

• Salaries, wages and employee benefits increased in the period-to-period comparison primarily due to an increase in wages and employee benefit expense.

• Contributions and advertising increased in the period-to-period comparison primarily due to an increase in charitable contributions.

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

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

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

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(in millions) 2023 2022 Variance Percent Change

Litigation Settlements $ 3 $ 10 $ (7) (70.0) %

Water Expense 1 2 (1) (50.0) %

Environmental Attribute Fees $ 7 $ — $ 7 100.0 %

Inventory Adjustments 6 — 6 100.0 %

Idle Equipment and Service Charges 4 — 4 100.0 %

Unutilized Firm Transportation and Processing Fees 53 52 1 1.9 %

Insurance Expense 4 3 1 33.3 %

Water Expense 1 1 — — %

Virginia Flood Expense 2 3 (1) (33.3) %

Litigation Settlements — 3 (3) (100.0) %

Other 3 1 2 200.0 %

Total Other Operating Expense $ 80 $ 63 $ 17 27.0 %

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

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

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

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

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

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

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

• Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs.

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The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial.

The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Total Other Operating Income.

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

The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Inc ome.

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

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

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

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

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

Other Expense

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A net gain on asset sales of $132 million was recognized in the year ended December 31, 2023 compared to a gain of $9 million in the year ended December 31, 2022.

During the year ended December 31, 2022, the Company sold various non-core assets, primarily rights-of-way, surface acreage and other non-core oil and gas interests, the gains from which were partially offset by costs related to the plugging and abandonment of a Shale wellbore.

This well was originally part of the 2023 development plan, and in order to not delay other wells, CNX plugged the wellbore and plans on accessing the reserves at a future date.

During the year ended December 31, 2021, the Company sold various non-core assets, primarily rights-of-way, surface acreage and other non-core oil and gas interests.

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

During the year ended December 31, 2022, the Company chose to plug and abandon a Shale wellbore.

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

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

Loss on Debt Extinguishment

A loss on debt extinguishment of $23 million was recognized in the year ended December 31, 2022 compared to a loss on debt extinguishment of $34 million in the year ended December 31, 2021.

During the year ended December 31, 2022, CNX purchased a portion of the Convertible Notes due May 2026 and $350 million of the 7.25% Senior Notes due March 2027 at an average price equal to 102.5% of the principal amount.

During the year ended December 31, 2021, CNXM purchased all of the 6.50% Senior Notes due March 2026 and CNX repaid in full and terminated the Cardinal States Gathering Company LLC and CSG Holdings II LLC non-revolving credit facilities.

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

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

No such transactions occurred in the current period.

Interest Expense

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Total Interest Expense $ 143 $ 128 $ 15 11.7 %

The $23 million decrease in total interest expense was primarily due to the purchase of the $400 million 6.500% CNXM Senior Notes due March 2026 during the year ended December 31, 2021, the purchase of the $350 million 7.25% Senior Notes due March 2027 during the year ended December 31, 2022, and lower borrowings on the CNX Credit Facility, offset, in part, by the issuance of $400 million of 4.750% CNXM Senior Notes due April 2030 during the year ended December 31, 2021 and the issuance of $500 million 7.375% Senior Notes due January 2031 during the year ended December 31, 2022.

The decrease was also due to the Company adopting Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity on January 1, 2022.

As part of the adoption, total interest expense no longer includes a non-cash interest expense component related to the Convertible Notes due May 2026.

Total interest expense for the year ended December 31, 2021 also included $16 million that was amortized as additional non-cash interest expense related to the equity component of the Convertible Notes due May 2026.

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

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

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

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

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(in millions) 2023 2022 Variance Percent Change

Total Company Loss Before Income Tax $ (212) $ (637) $ 425 66.7 %

Income Tax Benefit $ (70) $ (138) $ 68 49.3 %

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

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

Effective Income Tax Rate 22.6 % 33.0 % (10.4) %

The effective income tax rate was 22.6% for the year ended December 31, 2023 compared to 33.0% for the year ended December 31, 2022.

The effective rates for each of the years ended December 31, 2022 and 2021 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 certain state deferred tax asset valuation allowances as a result of the higher unrealized loss on commodity derivative instruments during each of the periods presented.

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

The effective tax rates for the years ended December 31, 2023 and 2022 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.

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

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

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

Cash and cash equivalents as of December 31, 2022 and December 31, 2021 were $21.3 million and $3.6 million, respectively.

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

• Accounts and notes receivable - trade as of December 31, 2023 and 2022 were $116 million and $348 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 $575 million to $675 million for the year ended December 31, 2023, compared to capital expenditures of $565.8 million in fiscal year 2022.

• Capital expenditures are expected to range between $575 million to $625 million for the year ended December 31, 2024.

For the year ended December 31, 2023, CNX had capital expenditures of $679.4 million.

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

• Production volumes are expected to range between 555.0 Bcfe and 575.0 Bcfe for the year ended December 31, 2023, compared to production volumes of 580.2 Bcfe in fiscal year 2022.

• Production volumes are expected to range between 570.0 Bcfe and 590.0 Bcfe for the year ended December 31, 2024.

For the year ended December 31, 2023, CNX had production volumes of 560.4 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 swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing.

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 $56 million at December 31, 2023 and a net liability of $1,905 million at December 31, 2022.

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

• Net loss decreased $357 million in the period-to-period comparison.

• Adjustments to reconcile net loss to cash provided by operating activities primarily consisted of an $165 million net change in commodity derivative instruments, a $62 million change in deferred income taxes, a $54 million change in depreciation, depletion and amortization, a $33 million change in gain on asset sales and abandonments, net, and various other changes in working capital.

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

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

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

• Capital expenditures increased $100 million primarily due to an increase in drilling and completions activity, midstream activity and an overall increase in costs related to inflation.

• Proceeds from asset sales decreased $8 million mainly due to decreased sales of non-core surface and oil and gas interests in the year ended December 31, 2022.

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

• Proceeds from asset sales increased $133 million primarily due to the sale of various non-operated oil and gas assets (See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

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

• Proceeds from borrowings under the CNXM Credit Facility decreased $10 million and repayments under the CNXM Credit Facility increased $7 million.

• Proceeds from borrowings under the CNX Credit Facility decreased $1,745 million and repayments under the CNX Credit Facility decreased $1,989 million.

• During the year ended December 31, 2022, CNX closed on $500 million aggregate principal amount of CNX 7.375% Senior Notes due January 2031 at a price of 98.8% for cash proceeds of $494 million.

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

• During the year ended December 31, 2022, there were $31 million of net payments on the CNXM Credit Facility compared to $106 million of net payments during the year ended December 31, 2021.

• During the year ended December 31, 2022, there were $192 million of net payments on the CNX Credit Facility compared to $31 million of net proceeds during the year ended December 31, 2021.

• During the year ended December 31, 2021, CNXM paid $421 million to purchase $400 million of CNXM 6.50% Senior Notes due in March 2026 at 105.3% of the principal amount.

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

• During the year ended December 31, 2021, CNXM completed a private offering of $400 million aggregate principal amount of CNXM 4.75% Senior Notes due April 2030 at a price of 98.8% for 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 year ended December 31, 2021, there were $161 million of net payments on the Cardinal States Facility and CSG Holdings Facility compared to $159 million of net proceeds in the year ended December 31, 2020.

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, 2023 and 2022, CNX repurchased $320 million and $565 million, respectively, of its common stock on the open market.

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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.

At December 31, 2022, CNX had total long-term debt of $2,220 million, excluding unamortized debt issuance costs.

At December 31, 2023, CNX had total long-term debt of $2,226 million, including the current portion of long-term debt of $326 million and excluding unamortized debt issuance costs.

This long-term debt consisted of:

• An aggregate principal amount of $500 million of 7.375% Senior Notes due January 2031, less $6 million of unamortized bond discount.

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

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

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

• An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $4 million of unamortized bond discount.

• An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $4 million of unamortized discount.

Interest on the notes is payable April 15 and October 15 of each year.

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CNX is not a guarantor of these notes.

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

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

Interest on the notes is payable March 14 and September 14 of each year.

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

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

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

• An aggregate principal amount of $105 million in outstanding borrowings under the CNXM Credit Facility.

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CNX is not a guarantor of the CNXM Facility.

• An aggregate principal amount of $52 million in outstanding borrowings under the CNX Credit Facility.

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

Total Equity and Dividends

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See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.

On September 28, 2020, the Merger of CNXM was completed (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).

CNX accounted for the change in our ownership interest in CNXM as an equity transaction which was reflected as a reduction of noncontrolling interest with corresponding increases to common stock and capital in excess of par value.

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.

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

Asset Retirement Obligations

Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.

The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset.

Asset retirement obligations primarily relate to the closure of gas wells and the reclamation of land upon exhaustion of gas reserves.

Changes in the variables used to calculate the liabilities can have a significant effect on the gas well closing liability.

The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.

The Company believes that the accounting estimates related to asset retirement obligations are “critical accounting estimates” because the Company must assess the expected amount and timing of asset retirement obligations.

In addition, the Company must determine the estimated present value of future liabilities.

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

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

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

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

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

assumptions that we believe are reasonable under the circumstances.

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

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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.

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.

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The Company groups its assets by geological and geographical characteristics.

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

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

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

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

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Impairment of Goodwill

In connection with the Midstream Acquisition that closed on January 3, 2018, CNX recorded $796 million of goodwill.

See Note 9 – Goodwill and Other Intangible Assets in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

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.

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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.

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.

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

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

Changes in assumptions concerning future financial results or other underlying assumptions

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

For the Company’s annual impairment assessment during the fourth quarter of 2023, the Company elected to perform a qualitative impairment test on its goodwill and concluded that it is more likely than not that the fair value exceeded the carrying value and goodwill was not impaired.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis