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Item 7. Management’s Discussion and Analysis

2022-02-10 compared with 2021-02-09 · 297 added, 643 removed, 332 unchanged (74% of the section changed)

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CNX continues to monitor the current and potential impacts of the coronavirus COVID-19 (“COVID-19”) pandemic on all aspects of our business and geographies, including how it has impacted, and may in the future impact, our operations, financial results, liquidity, contractors, customers, employees and vendors.

The Company also continues to monitor a number of factors that may cause actual results of operations to differ from our historical results or current expectations.

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

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.

While CNX did not incur significant disruptions to operations during the year ended December 31, 2020 as a direct result of the COVID-19 pandemic, CNX is unable to predict the impact that the COVID-19 pandemic will have on us, including our financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous uncertainties.

The full extent of the future impact of the COVID-19 pandemic on the Company’s operational and financial performance is currently uncertain and will depend on many factors outside the Company’s control, including, without limitation, the timing, extent, trajectory and duration of the pandemic, the development and availability of effective treatments and vaccines, the imposition of protective public safety measures, and the impact of the pandemic on the global economy and demand for consumer products.

Refer to Part I, Item 1A of this Form 10-K under the heading “Risk Factors,” for more information.

While CNX did not incur significant disruptions to operations during the years ended December 31, 2021 or 2020 as a direct result of the COVID-19 pandemic, CNX is unable to predict the full extent of the future impact that the COVID-19 pandemic could have on the Company, including our financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous uncertainties outside the Company’s control.

2021 Highlights:

• Increased proved reserves to 9.5 Tcfe, 13.3% higher than 2019.

• Increased proved developed reserves to 5.9 Tcfe, 13.5% higher than 2020.

• Total gas production of 590.2 Bcfe.

• Shale production of 540.4 Bcfe.

• Repurchased $43 million of CNX common stock on the open market.

• On September 28, 2020, CNX completed the acquisition of all of the outstanding common units of CNX Midstream Partners LP ("CNXM") and CNXM became an indirect wholly-owned subsidiary (the “Merger”) (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K).

• Repurchased $241 million or 18.3 million shares of CNX common stock on the open market.

• Reduced Long-Term Debt by $187 million.

2022 Outlook:

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Results of Operations:

Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019

The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 2021 to the year ended December 31, 2020.

A similar discussion and analysis that compares year ended December 31, 2020 to the fiscal year ended December 31, 2019 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, 2020, which is incorporated herein by reference.

Net Loss Attributable to CNX Resources Shareholders

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(Dollars in thousands) 2021 2020 Variance

Net (Loss) Income $ (428,744) $ 31,948 $ (460,692)

Net Loss $ (498,643) $ (428,744) $ (69,899)

Net Income Attributable to Noncontrolling Interests — 55,031 (55,031)

Net Loss Attributable to CNX Resources Shareholders $ (498,643) $ (483,775) $ (14,868)

Included in the loss for the year ended December 31, 2020 was a $62 million non-cash impairment charge related to exploration and production properties specific to our Southwestern Pennsylvania (SWPA) CBM asset group, a $473 million non-cash impairment charge related to goodwill and an unrealized loss on commodity derivatives of $288 million.

Included in the loss for the year ended December 31, 2019 was a $327 million non-cash impairment charge related to exploration and production properties and a $119 million non-cash impairment charge related to unproved properties and expirations, both were associated with the Company's Central Pennsylvania (CPA) acreage, offset, in part, by an unrealized gain on commodity derivative instruments of $306 million.

Prior to the effective time of the Merger on September 28, 2020 (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K), public unitholders held a 46.9% equity interest in CNXM and CNX owned the remaining 53.1% equity interest.

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

Included in the loss for the year ended December 31, 2020 was an unrealized loss on commodity derivative instruments of $288 million, a $62 million non-cash impairment charge related to exploration and production properties specific to our Southwestern Pennsylvania (SWPA) CBM asset group (See Note 8 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K), and a $473 million non-cash impairment charge related to 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).

The earnings of CNXM that were attributed to its common units held by the public prior to the Merger are reflected in Net Income Attributable to Noncontrolling Interest in the Consolidated Statements of Income.

There were no changes in our ownership interest in CNXM during the year ended December 31, 2021.

Selected Operating Revenue and Other Cost Data

The following table presents sales volumes, revenue, costs, average sales prices (including the effects of settled derivatives and excluding hedge monetizations) and average unit costs for production operations on a total Company basis:

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 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 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 excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 21 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

These expenses include, but are not limited to, interest expense, impairment of exploration and production properties, impairment of goodwill, 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) 2021 2020

Total Revenue and Other Operating Income $ 757 $ 1,258

Add (Deduct):

Purchased Gas Revenue (100) (106)

Loss on Commodity Derivative Instruments and Monetization 1,094 204

Other Revenue and Operating Income (106) (82)

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

$ 1,645 $ 1,274

Total Operating Expense $ 1,235 $ 1,697

Add (Deduct):

Depreciation, Depletion and Amortization (DD&A) - Corporate (11) (10)

Exploration and Production Related Other Costs (21) (15)

Purchased Gas Costs (94) (101)

Impairment of Exploration and Production Properties — (62)

Impairment of Goodwill — (473)

Selling, General and Administrative Costs (113) (109)

Other Operating Expense (68) (85)

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,

2021 2020 Variance

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Natural Gas, NGL and Oil Revenue $ 2,184 $ 3.77 $ 897 $ 1.71 $ 1,287 $ 2.06

Gain on Commodity Derivative Instruments - Cash Settlement - Gas** 377 0.78 70 0.14 307 0.64

Total Revenue 1,274 2.49 1,434 2.66 (160) (0.17)

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas** (539) (0.98) 377 0.78 (916) (1.76)

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

1,645 2.79 1,274 2.49 371 0.30

Lease Operating Expense 46 0.08 40 0.08 6 —

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Depreciation, Depletion and Amortization (DD&A) 504 0.85 492 0.96 12 (0.11)

Average Costs 842 1.64 929 1.72 (87) (0.08)

Average Margin $ 432 $ 0.85 $ 505 $ 0.94 $ (73) $ (0.09)

Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure

928 1.57 842 1.64 86 (0.07)

Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure

$ 717 $ 1.22 $ 432 $ 0.85 $ 285 $ 0.37

*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.

**Excluding hedge monetizations.

The decrease in volumes in the period-to-period comparison was primarily due to the strategic temporary shut-in of certain wells to take advantage of higher prices later in the year and thereby optimize the overall value of the assets.

Twenty-two dry gas turn-in-lines from April and May were temporarily shut-in through September and a portion of CNX's liquids-rich Shirley-Pennsboro production was shut-in during May and June of 2020.

Normal production declines also contributed to the decrease in total volumes.

The 79.1 Bcfe increase in volumes in the period-to period comparison was primarily due to the turn-in-line of new wells throughout 2020 and 2021.

Additionally, in 2020 the Company temporarily shut-in new turn-in-line wells as a result of low natural gas and NGL pricing.

The increases were offset in part by normal production declines.

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

• Lease operating expense decreased on a per unit basis primarily due to a decrease in water disposal costs in the period-to-period comparison as a result of increased reuse of produced water in well completions in the current period.

• Transportation, gathering and compression expense decreased on a per unit basis primarily due to lower processing costs due to a drier production mix and a decrease in firm transportation costs due to lower gas sales volumes.

• Depreciation, depletion and amortization expense increased on a per unit basis as a result of fixed depreciation costs related to CNX's gathering infrastructure being spread over fewer production volumes in 2020.

The lower production volumes were the result of the strategic temporary shut-in of certain wells as previously discussed.

The following table is a summary of total other revenue and operating income and selected other expense line items that are included in the total loss before income tax on a total company Mcfe equivalent and excluded from the previous table.

For the Years Ended December 31,

2020 2019 Variance

in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe

Total Company Sales Volumes (Bcfe)* 511.1 539.1 (28.0)

Total Other Revenue and Operating Income $ 82 $ 0.16 $ 88 $ 0.16 $ (6) $ 0.00

Depreciation, Depletion and Amortization $ 10 $ 0.02 $ 2 $ 0.00 $ 8 $ 0.02

Exploration and Production Related Other Costs 15 0.03 44 0.08 (29) (0.05)

Selling, General and Administrative Costs 109 0.21 144 0.27 (35) (0.06)

Other Operating Expense 85 0.17 80 0.15 5 0.02

Total Selected Operating Costs and Expenses 219 0.43 270 0.50 (51) (0.07)

Other Expense 24 0.05 3 0.01 21 0.04

Interest Expense 171 0.33 151 0.28 20 0.05

Total Selected Other Expense 195 0.38 154 0.29 41 0.09

Total Selected Costs and Expenses $ 414 $ 0.81 $ 424 $ 0.79 $ (10) $ 0.02

* 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.

• Production, ad valorem and other fees increased on a per unit basis as a result of increased realized prices on natural gas and natural gas liquids as well as the change in production mix by state as new wells were turned-in-line.

• Transportation, gathering and compression expense increased on a per unit basis primarily due to increased processing costs due to a wetter production mix, and increased firm transportation costs.

• Depreciation, depletion and amortization expense decreased on a per unit basis as a result of low cost reserve additions from development during the 2020 period in SWPA, the addition of proved undeveloped Shale wells in the Central Pennsylvania (CPA), and an impairment recognized in CBM in the 2020 period.

Average Realized Price Reconciliation

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Hedging Impact ($/Mcf) $ (0.98) $ 0.78 $ (1.76) (225.6) %

Gain on Commodity Derivative Instruments - Cash Settlement* $ 377,219 $ 69,780 $ 307,439 440.6 %

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement* $ (539,016) $ 377,219 $ (916,235) (242.9) %

*Excluding gains from hedge monetizations

The decrease in gross revenue was primarily the result of the $0.77 per Mcf decrease in general natural gas prices, when excluding the impact of hedging, in the markets in which CNX sells its natural gas and the 28.0 Bcfe decrease in sales volumes.

The decrease in gross revenue was offset, in part, by the increase in the realized gain on commodity derivative instruments related to the Company's hedging program.

The increase in gross revenue was primarily the result of the $1.84 per Mcf increase in natural gas prices, when excluding the impact of hedging, the 79.1 Bcfe increase in sales volumes and the $20.16 per Bbl increase in NGL prices.

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

SEGMENT ANALYSIS for the year ended December 31, 2021 compared to the year ended December 31, 2020:

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Natural Gas, NGLs and Oil Revenue $ 1,989 $ 194 $ 1 $ 2,184 $ 1,208 $ 80 $ (1) $ 1,287

Gain (Loss) on Commodity Derivative Instruments 337 40 (204) 173 275 33 (511) (203)

Loss on Commodity Derivative Instruments (492) (47) (1,094) (1,633) (829) (87) (890) (1,806)

Purchased Gas Revenue — — 100 100 — — (6) (6)

Other Revenue and Operating Income 81 — 25 106 16 — 8 24

Total Revenue and Other Operating Income 1,183 154 (79) 1,258 (152) (17) (495) (664)

Total Revenue and Other Operating Income (Loss) 1,578 147 (968) 757 395 (7) (889) (501)

Lease Operating Expense 34 13 (1) 46 8 (1) (1) 6

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Impairment of Exploration and Production Properties — — — — — — (62) (62)

Impairment of Unproved Properties and Expirations — — — — — — (119) (119)

Impairment of Goodwill — — — — — — (473) (473)

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Purchased Gas Costs — — 94 94 — — (7) (7)

Other Operating Expense — — 85 85 — — 5 5

Selling, General and Administrative Costs — — 113 113 — — 4 4

Other Operating Expense — — 68 68 — — (17) (17)

Total Operating Costs and Expenses 804 118 313 1,235 95 (10) (547) (462)

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Gain on Asset Sales and Abandonments, net — — (42) (42) — — (21) (21)

Gain on Debt Extinguishment — — (10) (10) — — (18) (18)

Loss on Debt Extinguishment — — 34 34 — — 44 44

Interest Expense — — 151 151 — — (20) (20)

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Average Sales Price - Gas (per Mcf) $ 3.51 $ 1.65 $ 1.86 112.7 %

Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.79 $ 0.14 $ 0.65 464.3 %

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ (0.98) $ 0.79 $ (1.77) (224.1) %

Average Sales Price - NGLs (per Mcfe)* $ 5.65 $ 2.29 $ 3.36 146.7 %

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Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) 0.82 0.91 (0.09) (9.9) %

Total Average Shale Costs (per Mcfe) $ 1.55 $ 1.63 $ (0.08) (4.9) %

Average Margin for Shale (per Mcfe) $ 0.89 $ 0.98 $ (0.09) (9.2) %

Total Average Shale Production Costs (per Mcfe) $ 1.49 $ 1.55 $ (0.06) (3.9) %

Total Average Shale Production Margin (per Mcfe) $ 1.28 $ 0.89 $ 0.39 43.8 %

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,989 million for the year ended December 31, 2021 compared to $781 million for the year ended December 31, 2020.

The $418 million decrease was due primary to a 31.8% decrease in the average sales price for natural gas, a 5.2% decrease in total Shale sales volumes, and a 28.4% decrease in the average sales price of NGLs.

Normal production declines also contributed to the decrease in total volumes.

The decrease in total average Shale sales price was primarily due to a $0.77 per Mcf decrease in average gas sales price and a $0.91 per Mcfe decrease in the average NGL sales price.

These decreases were offset in part by a $0.65 per Mcf increase in the realized gain on commodity derivative instruments.

The notional amounts associated with these financial hedges represented approximately 412.1 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2020 at an average realized gain of $0.82 per Mcf hedged.

For the year ended December 31, 2019, these financial hedges represented approximately 348.1 Bcf at an average realized gain of $0.18 per Mcf hedged.

The $1,208 million increase was due primarily to a 17.9% increase in total Shale gas sales volumes, and a 13.5% increase in the total average Shale sales price.

The increase in total Shale gas sales volumes was primarily due to the turn-in-line of new wells throughout 2020 and 2021.

The increase was also due to the temporary shut-in of new turn-in-line wells in 2020 due to low natural gas prices, offset in part by normal production declines.

The increase in total average Shale sales price was primarily due to a $1.86 per Mcf increase in average gas sales price and a $3.36 per Mcfe increase in the average NGL sales price.

These increases were offset in part by a $1.77 per Mcf change in the realized (loss) gain on commodity derivative instruments.

The notional amounts associated with these financial hedges represented approximately 429.4 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2021 at an average loss of $1.15 per Mcf hedged.

For the year ended December 31, 2020, these financial hedges represented approximately 412.1 Bcf at an average gain of $0.82 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $804 million for the year ended December 31, 2021 compared to $709 million for the year ended December 31, 2020.

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

• Shale lease operating expense was $26 million for the year ended December 31, 2020, compared to $49 million for the year ended December 31, 2019.

The decrease in total dollars was primarily due to a decrease in water disposal costs in the current period resulting from an increase in the reuse of produced water in well completions activity.

The decrease in unit costs was driven by the decrease in total dollars.

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 $34 million for the year ended December 31, 2021 compared to $26 million for the year ended December 31, 2020.

The increase in total dollars was primarily related to an increase in production volumes.

• Shale production, ad valorem and other fees were $27 million for the year ended December 31, 2021 compared to $19 million for the year ended December 31, 2020.

The increases in total dollars and unit costs were primarily due to increased realized prices on natural gas and natural gas liquids as well as the change in production mix by state as new wells were turned-in-line.

• Shale transportation, gathering and compression costs were $303 million for the year ended December 31, 2021 compared to $248 million for the year ended December 31, 2020.

The decreases in total dollars and unit costs were primarily related to lower processing costs due to a drier production mix.

Lower firm transportation costs from lower gas sales volumes also contributed to the decrease in total dollars.

The increase in total dollars was primarily related to the increase in total production volumes and increased processing costs due to a wetter production mix.

The increase in unit costs was primarily due to increased processing costs due to a wetter production mix and an increase in firm transportation costs.

• Depreciation, depletion and amortization costs attributable to the Shale segment were $440 million for the year ended December 31, 2021 compared to $416 million for the year ended December 31, 2020.

The decrease is due to lower production volumes.

These amounts each included depletion on a unit of production basis of $0.81 per Mcfe.

The increase in total dollars was due to the increase in production volumes.

These amounts included depletion on a unit of production basis of $0.71 per Mcfe and $0.81 per Mcfe, respectively.

The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of low-cost reserve additions from development in 2020 in SWPA as well as the addition of proved undeveloped Shale reserves in CPA.

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

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The Shale segment had other revenue and operating income of $81 million for the year ended December 31, 2021 compared to $65 million for the year ended December 31, 2020.

The decrease in the period-to-period comparison was primarily due to a reduction in volumes transported due to temporary production curtailments by third-party producers that occurred early in the 2020 period.

The increase in the period-to-period comparison was primarily due to temporary production curtailments by third party customers that occurred in early 2020 due to low prices.

Those curtailments were restored to full production in the latter half of 2020.

COALBED METHANE (CBM) SEGMENT

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Average Sales Price - Gas (per Mcf) $ 3.91 $ 2.17 $ 1.74 80.2 %

Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.76 $ 0.13 $ 0.63 484.6 %

(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ (0.93) $ 0.76 $ (1.69) (222.4) %

Total Average CBM Sales Price (per Mcf) $ 2.97 $ 2.93 $ 0.04 1.4 %

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Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.18 1.33 (0.15) (11.3) %

Total Average CBM Costs (per Mcf) $ 2.43 $ 2.45 $ (0.02) (0.8) %

Average Margin for CBM (per Mcf) $ 0.50 $ 0.64 $ (0.14) (21.9) %

Total Average CBM Production Costs (per Mcf) $ 2.38 $ 2.43 $ (0.05) (2.1) %

Total Average CBM Production Margin (per Mcf) $ 0.59 $ 0.50 $ 0.09 18.0 %

The CBM segment had natural gas revenue of $194 million for the year ended December 31, 2021 compared to $114 million for the year ended December 31, 2020.

The $50 million decrease was due to a 5.1% decrease in total CBM sales volumes and a 26.7% decrease in the average sales price for natural gas in the current period.

The decrease in CBM sales volumes was primarily due to normal production declines.

The total average CBM sales price decreased $0.16 per Mcf due to a $0.79 per Mcf decrease in average sales price for natural gas, offset in part by a $0.63 per Mcf increase in the gain on commodity derivative instruments resulting from the Company's hedging program.

The notional amounts associated with these financial hedges represented approximately 48.7 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2020 at an average gain of $0.82 per Mcf hedged.

The $80 million increase was primarily due to an 80.2% increase in the average sales price for natural gas in the current period.

The natural gas price increases were partially offset by the 5.9% decrease in CBM gas sales volumes due to normal production declines.

The total average CBM sales price increased $0.04 per Mcf due to a $1.74 per Mcf increase in average gas sales price, offset in part by a $1.69 per Mcf change in the realized (loss) gain on commodity derivative instruments resulting from the Company's hedging program.

The notional amounts associated with these financial hedges represented approximately 40.4 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2021 at an average loss of $1.15 per Mcf hedged.

For the year ended December 31, 2020, these financial hedges represented approximately 48.7 Bcf at an average gain of $0.82 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $118 million for the year ended December 31, 2021 compared to $128 million for the year ended December 31, 2020.

The decrease in total dollars was primarily due to decreases in employee costs, electrical power expense and repairs and maintenance.

The decrease in unit costs was driven by the decrease in total dollars.

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

• CBM lease operating expense was $13 million for the year ended December 31, 2021 compared to $14 million for the year ended December 31, 2020.

The decreases in total dollars was primarily due to a decrease in water disposal costs.

• CBM transportation, gathering and compression costs were $40 million for the year ended December 31, 2021 compared to $39 million for the year ended December 31, 2020.

The increases in total dollars and unit costs were primarily due to an increase in firm transportation expense.

• Depreciation, depletion and amortization costs attributable to the CBM segment were $58 million for the year ended December 31, 2021 compared to $70 million for the year ended December 31, 2020.

These amounts included depletion on a

unit of production basis of $0.68 per Mcfe and $0.70 per Mcfe, respectively.

The decrease in the units of production depreciation, depletion and amortization rate was due, in part, to an impairment in the first quarter of 2020 related to the Southwest Pennsylvania (SWPA) CBM asset group.

These amounts included depletion on a unit of production basis of $0.66 per Mcfe and $0.68 per Mcfe, respectively.

The decrease in the units of production depreciation, depletion and amortization rate was primarily due to an impairment in the 2020 period that reduced the carrying value of the underlying SWPA CBM asset group (See Note 8 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

No such impairment occurred in the current period).

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

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Total Other Sales Volumes (Bcfe)* 0.3 0.2 0.1 50.0 %

*Oil 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.

Gain or Loss on Commodity Derivative Instruments and Monetization

For the year ended December 31, 2020, the Other segment recognized an unrealized loss on commodity derivative instruments of $288 million as well as cash settlements received of $84 million related to natural gas hedges and financial basis hedges that were partially monetized or terminated prior to their settlement date.

For the year ended December 31, 2019, the Other segment recognized an unrealized gain on commodity derivative instruments of $306 million as well as cash settlements received of $1 million.

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

*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.

Loss on Commodity Derivative Instruments and Monetization

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

For the year ended December 31, 2020, the Other Segment recognized an unrealized loss on commodity derivative instruments of $288 million as well as cash settlements received of $84 million related to natural gas hedges that were partially monetized prior to their settlement dates.

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.

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 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 revenues were $106 million for the year ended December 31, 2020 compared to $94 million for the year ended December 31, 2019.

Purchased gas revenue was $100 million for the year ended December 31, 2021 compared to $106 million for the year ended December 31, 2020.

Purchased gas costs were $94 million for the year ended December 31, 2021 compared to $101 million for the year ended December 31, 2020.

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

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

For the Years Ended December 31,

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Purchased Gas Sales Volumes (in Bcf) 26.6 66.6 (40.0) (60.1) %

Average Sales Price (per Mcf) $ 1.59 $ 2.32 $ (0.73) (31.5) %

Average Cost (per Mcf) $ 1.52 $ 2.23 $ (0.71) (31.8) %

Purchased Gas Average Sales Price (per Mcf) $ 3.75 $ 1.59 $ 2.16 135.8 %

Purchased Gas Average Cost (per Mcf) $ 3.53 $ 1.52 $ 2.01 132.2 %

Other Operating Income

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(in millions) 2021 2020 Variance Percent Change

Equity Income (Loss) from Affiliates $ 6 $ (1) $ 7 700.0 %

Water Income 7 6 1 16.7 %

Excess Firm Transportation Income 12 12 — — %

Equity in (Loss) Earnings of Affiliates (1) 2 (3) (150.0) %

Total Other Operating Income $ 25 $ 17 $ 8 47.1 %

• Water income increased $4 million in the 2020 period due to increased revenue for accepting deliveries of produced water from third-parties for reuse in the Company's hydraulic fracturing.

• Equity income (loss) 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.

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

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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 (gathering income) from released capacity helps offset the unutilized firm transportation and processing fees in total other operating expense.

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

Impairment of Exploration and Production Properties

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The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value.

As a result, an impairment of $62 million was recognized and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income.

As a result, an impairment of $62 million was recognized and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income for the year ended December 31, 2020.

The impairment was related to an economic decision to temporarily idle certain wells and the related processing facility during the first quarter.

During the year ended December 31, 2019, CNX identified certain indicators of impairment specific to our CPA Marcellus asset group and determined that carrying value of that asset group was not recoverable.

As a result, an impairment of $327 million was recognized within the CPA Marcellus proved properties and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income.

This impairment was related to 56 operated wells and approximately 51,000 acres within our CPA Marcellus proved properties in Armstrong, Indiana, Jefferson and Westmoreland counties.

The majority of these properties were developed prior to 2013 and the last of these properties were developed in 2015.

Impairment of Unproved Properties and Expirations

Capitalized costs of unproved oil and gas properties are evaluated periodically for indicators of potential impairment.

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.

The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced.

If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment is recorded.

Expense for lease expirations that were not previously impaired are recorded as the leases expire.

No impairments related to unproved properties were recorded for the year-ended December 31, 2020.

For the year ended December 31, 2019, CNX recorded an impairment related to unproved properties of $119 million that was included in Impairment of Unproved Properties and Expirations in the Consolidated Statements of Income.

These unproved properties are within CNX's CPA operating region and east of the acreage associated with the proved property impairment described above.

See Note 8 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

No such impairment occurred in the current period.

Impairment of Goodwill

In connection with the Midstream Acquisition that occurred in January 2018, CNX recorded $796 million of goodwill.

(See Note 4 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

Goodwill is tested 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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In connection with CNX's assessment of goodwill in the first quarter of 2020 in relation to the deteriorating macroeconomic conditions, and the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches to estimate the fair value of the Midstream reporting unit.

As a result of this assessment, CNX concluded that the carrying value exceed its estimated fair value, and as a result, an impairment of $473 million was included in Impairment of Goodwill in the Consolidated Statements of Income.

No such impairment occurred in the prior period.

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

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 additional information.

No such impairment occurred in the current period.

Exploration and Production Related Other Costs

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(in millions) 2021 2020 Variance Percent Change

Lease Expiration Costs $ 10 $ 31 $ (21) (67.7) %

Seismic Activity 1 8 (7) (87.5) %

Exploratory Well Costs $ 9 $ — $ 9 100.0 %

Land Rentals 3 3 — — %

Other 1 2 (1) (50.0) %

Permitting Expense 1 2 (1) (50.0) %

Lease Expiration Costs 8 10 (2) (20.0) %

Total Exploration and Production Related Other Costs $ 21 $ 15 $ 6 40.0 %

• 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.

The $21 million decrease in the period-to-period comparison is due to a decrease in the number of leases that were allowed to expire in the year ended December 31, 2020, or will expire within the next 12 months, because they were no longer in the Company's future drilling plan.

Additionally, approximately $15 million of the $21 million decrease is associated with leases which expired

• Seismic activity decreased in the period-to-period comparison due to additional geophysical research in the prior period.

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

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Long-Term Equity-Based Compensation (Non-Cash) $ 17 $ 14 $ 3 21.4 %

Salaries, Wages and Employee Benefits 31 40 (9) (22.5) %

Short-Term Incentive Compensation 20 20 — — %

Salaries, Wages and Employee Benefits 27 31 (4) (12.9) %

Other 49 44 5 11.4 %

Total SG&A $ 113 $ 109 $ 4 3.7 %

• Long-term equity-based compensation decreased $24 million in the period-to-period comparison due to a change in control event that occurred in the second quarter of 2019 and resulted in the acceleration of vesting of certain restricted stock units and performance share units held by certain employees.

See Note 15 - Stock-Based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

• Salaries, wages and employee benefits decreased $9 million due to an overall reduction in employees and employee-related costs resulting from a reduction in staff.

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

• Salaries, wages and employee benefits decreased in the period-to-period comparison primarily due to a decrease in employees.

• Other increased in the period-to-period comparison primarily due to an increase in legal and consulting professional services.

Other Operating Expense

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Unutilized Firm Transportation and Processing Fees $ 53 $ 70 $ (17) (24.3) %

Insurance Expense 3 4 (1) (25.0) %

Severance Expense — 1 (1) (100.0) %

Idle Equipment and Service Charges — 10 (10) (100.0) %

Insurance Expense 2 3 (1) (33.3) %

Water Expense 2 1 1 100.0 %

Litigation Settlements 10 — 10 100.0 %

Other 1 1 — — %

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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 Gathering Income in Total Revenue and Other Operating Income above.

The increase in the period-to-period comparison was primarily due to an increase in previously acquired capacity that was not able to be utilized during the current period to transport the Company's flowing production or to process the Company’s wet natural gas production.

One contributing factor was the strategic temporary shut-in of certain wells to take advantage of higher prices later in the year and thereby optimize the overall value of the assets.

Normal production declines also contributed to the decrease in total volumes.

• Other decreased $6 million in the period-to-period comparison primarily due to a tax refund that was received in the 2020 period.

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.

The decrease in unutilized firm transportation and processing fees in the period-to-period comparison was primarily due to an increase in utilization of firm transportation capacity in the current year due to production increases in 2021 compared to 2020.

• Idle equipment and service charges relate to temporary idling of certain of the Company’s natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process.

The decrease in the period-to-period comparison was the result of two of CNX’s drilling rigs being idled in the prior period.

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

Other Expense

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(in millions) 2021 2020 Variance Percent Change

Right-of-Way Sales $ 3 $ 9 $ (6) (66.7) %

Royalty Income — 4 (4) (100.0) %

Interest Income $ — $ 2 $ (2) (100.0) %

Right-of-Way Sales 2 3 (1) (33.3) %

Other 7 8 (1) (12.5) %

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Total Other Expense $ 16 $ 24 $ (8) (33.3) %

• Right-of-way sales relate to revenue generated from the sale of the Company's unutilized surface rights.

The decrease of $6 million in the period-to-period comparison was due to a decrease in sales.

• Royalty income is comprised of royalties CNX received on non-operated properties unrelated to natural gas.

The decrease of $4 million in the period-to-period comparison was due to a reduction in third-party prices.

• Other income increased $4 million in the period-to-period comparison primarily due to various items that occurred throughout both periods, none of which were individually material.

• Merger-related costs consist of transaction costs directly attributable to the CNXM Merger (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), including financial advisory, legal service and other professional fees, which were recorded to Other Expense in the Consolidated Statements of Income.

• Professional services increased $5 million in the period-to-period comparison primarily due to fees related to an agreement to eliminate CNXM's incentive distribution rights, or IDRs, in January of 2020, prior to the Merger.

• Interest income decreased in the period-to-period comparison primarily due to the receipt of interest in the prior year in connection with a severance tax refund related to a prior period and additional interest income related to the alternative minimum tax credit refund CNX received in the prior year.

• Professional services decreased in the period-to-period comparison primarily due to the prior year containing fees related to the elimination of CNXM's incentive distribution rights (“IDRs”) prior to the CNXM Merger discussed below.

• Merger-related costs in the prior period consisted of transaction costs, including financial advisory, legal service and other professional fees directly attributable to the CNXM Merger (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), which were recorded to Other Expense in the Consolidated Statements of Income.

Gain on Asset Sales and Abandonments, net

A gain on asset sales of $21 million related to the sale of various non-core assets, primarily surface properties, was recognized in the year ended December 31, 2020 compared to a gain of $36 million in the year ended December 31, 2019.

Loss on Debt Extinguishment

A gain on debt extinguishment of $10 million was recognized in the year ended December 31, 2020 compared to a loss on debt extinguishment of $8 million in the year ended December 31, 2019.

A gain on asset sales of $42 million related to the sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests) was recognized in the year ended December 31, 2021 compared to a gain of $21 million in the year ended December 31, 2020.

Loss (Gain) on Debt Extinguishment

A loss on debt extinguishment of $34 million was recognized in the year ended December 31, 2021 compared to a gain on debt extinguishment of $10 million in the year ended December 31, 2020.

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.

During the year ended December 31, 2020, CNX purchased the remaining $894 million of its 5.875% Senior Notes due April 2022 at an average price equal to 98.6% of the principal amount.

During the year ended December 31, 2019 CNX purchased $400 million of its 5.875% Senior Notes due April 2022 at an average price equal to 101.5% 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.

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Total Interest Expense $ 151 $ 171 $ (20) (11.7) %

• The $20 million increase was primarily due to interest related to the addition, in the current period, of $345 million of Convertible Senior Notes due 2026, the $125 million Cardinal States Facility, the $50 million CSG Holdings Facility, $500 million of senior notes due 2029, and $200 million of senior notes due 2027.

The amortization of debt discount in connection with the Convertible Senior Notes and realized and unrealized losses on interest rate swap agreements during the year ended December 31, 2020 also contributed to the increase.

These increases were offset in part by the purchase of the remaining $894 million of the 5.875% senior notes due in April 2022 during the year ended December 31, 2020, as well as lower borrowings on the CNX credit facility.

• The $20 million decrease was primarily due to the purchase of the remaining $894 million of the 5.875% Senior Notes due April 2022 during the year ended December 31, 2020 and the purchase of the $400 million 6.500% CNXM Senior Notes due March 2026 during the year ended December 31, 2021.

Lower borrowings on the CNX Credit Facility and higher unrealized gains on interest rate swap agreements also contributed to the decrease.

These decreases were offset in part by $400 million of 4.750% CNXM Senior Notes due 2030 issued in 2021, interest related to the addition in 2020 of $345 million of Convertible Notes due 2026, $500 million of 6.00% Senior Notes due 2029 issued in 2020, and an additional $200 million of 7.25% Senior Notes due 2027 issued in 2020.

The amortization of debt discount in connection with the Convertible Notes also contributed to the offsetting increase.

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) 2021 2020 Variance Percent Change

Total Company (Loss) Earnings Before Income Tax $ (603) $ 60 $ (663) (1,105.0) %

Income Tax (Benefit) Expense $ (174) $ 28 $ (202) (721.4) %

Total Company Loss Before Income Tax $ (637) $ (603) $ (34) (5.6) %

Income Tax Benefit $ (138) $ (174) $ 36 20.7 %

Effective Income Tax Rate 21.7 % 28.9 % (7.2) %

The effective income tax rate was 21.7% for the year ended December 31, 2021 compared to 28.9% for the year ended December 31, 2020.

The effective rates for the years ended December 31, 2020 and 2019 differs from the U.S.

federal statutory rate of 21% primarily due to the impact of state income taxes, equity compensation and state valuation allowances, partially offset by the benefit from non-controlling interest.

The effective rate for the year ended December 31, 2021 differs from the U.S.

federal statutory rate of 21% primarily due to federal tax credits, state income taxes, equity compensation and the increase in certain state valuation allowances as a result of higher-than-expected unrealized losses on commodity derivative instruments during the current period.

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

The effective rate for the year ended December 31, 2020 differs from the U.S.

federal statutory rate of 21% primarily due to state income taxes, equity compensation and state valuation allowances, partially offset by the benefit from non-controlling interest.

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.

Results of Operations:

Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018

Net (Loss) Income Attributable to CNX Resources Shareholders

CNX reported a net loss attributable to CNX Resources shareholders of $81 million, or a loss per diluted share of $0.42, for the year ended December 31, 2019, compared to net income attributable to CNX Resources shareholders of $797 million, or earnings per diluted share of $3.71, for the year ended December 31, 2018.

For the Years Ended December 31,

(Dollars in thousands) 2019 2018 Variance

Net Income $ 31,948 $ 883,111 $ (851,163)

Net Income Attributable to Noncontrolling Interest 112,678 86,578 26,100

Net (Loss) Income Attributable to CNX Resources Shareholders $ (80,730) $ 796,533 $ (877,263)

Included in the loss for the year ended December 31, 2019 was a $327 million non-cash impairment charge related to exploration and production properties and a $119 million non-cash impairment charge related to unproved properties and expirations, both of which were associated with the Company's Central Pennsylvania (CPA) acreage, offset, in part, by an unrealized gain on commodity derivative instruments of $306 million.

Included in the earnings for the year ended December 31, 2018 was a $19 million non-cash impairment charge related to the other intangible asset - customer relationship in connection with the AEA with HG Energy and an unrealized gain on commodity derivative instruments of $40 million.

(See Note 4 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

As a result of the Midstream Acquisition (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 owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus the Company began consolidating CNXM on January 3, 2018.

The resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $624 million was included in the Gain on Previously Held Equity Interest line of the Consolidated Statements of Income in the 2018 period and was part of CNX's unallocated expenses.

No such transactions occurred during the year ended December 31, 2019.

Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment.

Selected Operating Revenue and Other Cost Data

The following table presents sales volumes, revenue, costs, average sales prices (including the effects of settled derivatives) and average unit costs for production operations on a total Company basis:

For the Years Ended December 31,

2019 2018 Variance

in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe

Total Sales Volumes (Bcfe)* 539.1 507.1 32.0

Natural Gas, NGL and Oil Revenue $ 1,364 $ 2.52 $ 1,578 $ 3.12 $ (214) $ (0.60)

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement - Gas 70 0.14 (70) (0.15) 140 0.29

Total Revenue 1,434 2.66 1,508 2.97 (74) (0.31)

Lease Operating Expense 65 0.12 95 0.19 (30) (0.07)

Production, Ad Valorem and Other Fees 27 0.05 33 0.06 (6) (0.01)

Transportation, Gathering and Compression 331 0.61 303 0.60 28 0.01

Depreciation, Depletion and Amortization (DD&A) 506 0.94 493 0.97 13 (0.03)

Average Costs 929 1.72 924 1.82 5 (0.10)

Average Margin $ 505 $ 0.94 $ 584 $ 1.15 $ (79) $ (0.21)

The 32.0 Bcfe increase in total sales volumes was primarily due to additional natural gas wells that were turned-in-line in the latter half of the 2018 period as well as throughout the 2019 period.

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

• Lease operating expense decreased on a per unit basis primarily due to a decrease in water disposal costs in the period-to-period comparison due to an increase in the reuse of produced water in well completions in the 2019 period, and also due to the sale of the majority of CNX's shallow oil and gas assets and the sale of substantially all of CNX's Ohio Utica JV assets in 2018.

• Depreciation, Depletion and Amortization decreased on a per unit basis due to positive reserve revisions within the core SWPA Shale development area, partially offset by negative reserve revisions within CNX's Ohio Shale operations, as well as an increase in capital expenditures.

• Transportation, gathering and compression expense increased on a per unit basis primarily due to new firm transportation contracts which began in the fourth quarter of 2018 and the first quarter of 2019.

The following table is a summary of total other revenue and operating income and selected other expense line items that are included in the total (loss) earnings before income tax on a total company Mcfe equivalent and excluded from the previous table.

For the Years Ended December 31,

2019 2018 Variance

in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe

Total Company Sales Volumes (Bcfe)* 539.1 507.1 32.0

Total Other Revenue and Operating Income $ 88 $ 0.16 $ 116 $ 0.23 $ (28) $ (0.07)

Depreciation, Depletion and Amortization $ 2 $ 0.00 $ — $ 0.00 $ 2 $ 0.00

Exploration and Production Related Other Costs 44 0.08 12 0.02 32 0.06

Selling, General and Administrative Costs 144 0.27 135 0.27 9 0.00

Other Operating Expense 80 0.15 72 0.14 8 0.01

Total Selected Operating Costs and Expenses 270 0.50 219 0.43 51 0.07

Other Expense (Income) 3 0.01 (15) (0.03) 18 0.04

Interest Expense 151 0.28 146 0.29 5 (0.01)

Total Selected Other Expense 154 0.29 131 0.26 23 0.03

Total Selected Costs and Expenses $ 424 $ 0.79 $ 350 $ 0.69 $ 74 $ 0.10

* 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.

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) 2019 2018 Variance Percent Change

Sales Volume (MMcfe) 32,571 36,489 (3,918) (10.7) %

Sales Volume (Mbbls) 5,428 6,081 (653) (10.7) %

Gross Price ($/Bbl) $ 19.20 $ 27.30 $ (8.10) (29.7) %

Gross Revenue $ 104,139 $ 165,883 $ (61,744) (37.2) %

Oil/Condensate:

Sales Volume (MMcfe) 1,223 2,389 (1,166) (48.8) %

Sales Volume (Mbbls) 204 398 (194) (48.7) %

Gross Price ($/Bbl) $ 45.00 $ 51.72 $ (6.72) (13.0) %

Gross Revenue $ 9,173 $ 20,595 $ (11,422) (55.5) %

Sales Volume (MMcf) 505,355 468,226 37,129 7.9 %

Sales Price ($/Mcf) $ 2.48 $ 2.97 $ (0.49) (16.5) %

Gross Revenue $ 1,251,013 $ 1,391,459 $ (140,446) (10.1) %

Hedging Impact ($/Mcf) $ 0.14 $ (0.15) $ 0.29 193.3 %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement $ 69,780 $ (69,720) $ 139,500 200.1 %

The decrease in gross revenue was primarily the result of the $0.49 per Mcf decrease in general natural gas prices, when excluding the impact of hedging, in the markets in which CNX sells its natural gas and the $8.10 per Bbl decrease in NGL prices.

These decreases were offset, in-part, by the 32.0 Bcfe increase in sales volumes and the increase in the realized gain on commodity derivative instruments related to the Company's hedging program.

SEGMENT ANALYSIS for the year ended December 31, 2019 compared to the year ended December 31, 2018:

For the Year Ended Difference to Year Ended

December 31, 2019 December 31, 2018

(in millions) Shale CBM Other Total Shale CBM Other Total

Natural Gas, NGLs and Oil Revenue $ 1,199 $ 164 $ 1 $ 1,364 $ (150) $ (49) $ (15) $ (214)

Gain on Commodity Derivative Instruments 62 7 307 376 122 16 268 406

Purchased Gas Revenue — — 94 94 — — 28 28

Other Revenue and Operating Income 74 — 14 88 (16) — (12) (28)

Total Revenue and Other Operating Income 1,335 171 416 1,922 (44) (33) 269 192

Lease Operating Expense 49 16 — 65 (22) (6) (2) (30)

Production, Ad Valorem and Other Fees 21 7 (1) 27 (4) — (2) (6)

Transportation, Gathering and Compression 290 40 1 331 39 (8) (3) 28

Depreciation, Depletion and Amortization 426 73 9 508 21 (4) (2) 15

Impairment of Exploration and Production Properties — — 327 327 — — 327 327

Impairment of Unproved Properties and Expirations — — 119 119 — — 119 119

Impairment of Other Intangible Assets — — — — — — (19) (19)

Exploration and Production Related Other Costs — — 44 44 — — 32 32

Purchased Gas Costs — — 91 91 — — 26 26

Other Operating Expense — — 80 80 — — 8 8

Selling, General and Administrative Costs — — 144 144 — — 9 9

Total Operating Costs and Expenses 786 136 814 1,736 34 (18) 493 509

Other Expense — — 3 3 — — 18 18

Gain on Asset Sales and Abandonments, net — — (36) (36) — — 121 121

Gain on Previously Held Equity Interest — — — — — — 624 624

Loss on Debt Extinguishment — — 8 8 — — (46) (46)

Interest Expense — — 151 151 — — 5 5

Total Other Expenses — — 126 126 — — 722 722

Total Costs and Expenses 786 136 940 1,862 34 (18) 1,215 1,231

Earnings (Loss) Before Income Tax $ 549 $ 35 $ (524) $ 60 $ (78) $ (15) $ (946) $ (1,039)

SHALE SEGMENT

The Shale segment had earnings before income tax of $549 million for the year ended December 31, 2019 compared to earnings before income tax of $627 million for the year ended December 31, 2018.

For the Years Ended December 31,

2019 2018 Variance Percent

Shale Gas Sales Volumes (Bcf) 449.6 403.2 46.4 11.5 %

NGLs Sales Volumes (Bcfe)* 32.6 36.5 (3.9) (10.7) %

Oil/Condensate Sales Volumes (Bcfe)* 1.2 2.2 (1.0) (45.5) %

Total Shale Sales Volumes (Bcfe)* 483.4 441.9 41.5 9.4 %

Average Sales Price - Gas (per Mcf) $ 2.42 $ 2.89 $ (0.47) (16.3) %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.14 $ (0.15) $ 0.29 193.3 %

Average Sales Price - NGLs (per Mcfe)* $ 3.20 $ 4.55 $ (1.35) (29.7) %

Average Sales Price - Oil/Condensate (per Mcfe)* $ 7.47 $ 8.48 $ (1.01) (11.9) %

Total Average Shale Sales Price (per Mcfe) $ 2.61 $ 2.92 $ (0.31) (10.6) %

Average Shale Lease Operating Expenses (per Mcfe) 0.10 0.16 (0.06) (37.5) %

Average Shale Production, Ad Valorem and Other Fees (per Mcfe) 0.05 0.06 (0.01) (16.7) %

Average Shale Transportation, Gathering and Compression Costs (per Mcfe) 0.60 0.57 0.03 5.3 %

Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) 0.88 0.91 (0.03) (3.3) %

Total Average Shale Costs (per Mcfe) $ 1.63 $ 1.70 $ (0.07) (4.1) %

Average Margin for Shale (per Mcfe) $ 0.98 $ 1.22 $ (0.24) (19.7) %

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,199 million for the year ended December 31, 2019 compared to $1,349 million for the year ended December 31, 2018.

The $150 million decrease was due primarily to a 16.3% decrease in the average sales price for natural gas.

This decrease was offset in part by a 9.4% increase in total Shale sales volumes.

The increase in total Shale sales volumes was primarily due to additional wells being turned-in-line throughout 2018 and 2019, partially offset by the sale of substantially all of CNX's Ohio JV assets in the third quarter of 2018 (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) as well as normal production declines in the remaining dry Shale wells.

The decrease in total average Shale sales price was primarily due to a $0.47 per Mcf decrease in average gas sales price.

Additionally, there was a $0.10 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging due to the sale of the previously mentioned Ohio JV assets in the third quarter of 2018, which consisted primarily of wet Shale production.

The decreases were partially offset by a $0.29 per Mcf increase in the realized gain (loss) on commodity derivative instruments.

The notional amounts associated with these financial hedges represented approximately 348.1 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2019 at an average gain of $0.18 per Mcf hedged.

For the year ended December 31, 2018, these financial hedges represented approximately 308.3 Bcf at an average loss of $0.20 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $786 million for the year ended December 31, 2019 compared to $752 million for the year ended December 31, 2018.

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 $49 million for the year ended December 31, 2019 compared to $71 million for the year ended December 31, 2018.

The decrease in total dollars was primarily due to a decrease in water disposal costs due to an increase in reuse of produced water in well completions and a reduction in employee costs.

The decrease in unit costs was driven by the decrease in total dollars.

• Shale transportation, gathering and compression costs were $290 million for the year ended December 31, 2019 compared to $251 million for the year ended December 31, 2018.

The $39 million increase in total dollars and $0.03 per Mcfe increase in unit costs were both due to the overall increase in Shale volumes and the new firm transportation contracts which began in the fourth quarter of 2018 and first quarter of 2019.

• Depreciation, depletion and amortization costs attributable to the Shale segment were $426 million for the year ended December 31, 2019 compared to $405 million for the year ended December 31, 2018.

These amounts included depletion on a unit of production basis of $0.81 per Mcfe and $0.83 per Mcfe, respectively.

The decrease in the units of production depreciation, depletion and amortization rate was due to positive reserve revisions within the core SWPA development area, partially offset by an increase in the units of production depreciation, depletion and amortization rate due to negative reserve revisions within the Ohio operations, an increase in capital expenditures and a higher depreciation, depletion and amortization rate on deep dry Shale wells compared to the lower capital cost wells which were part of the Ohio JV asset sale in 2018.

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 $74 million for the year ended December 31, 2019 compared to $90 million for the year ended December 31, 2018.

The decrease in the period-to-period comparison was primarily due to a reduction in third-party volumes transported due to normal production declines.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $35 million for the year ended December 31, 2019 compared to earnings before income tax of $50 million for the year ended December 31, 2018.

For the Years Ended December 31,

2019 2018 Variance Percent

CBM Gas Sales Volumes (Bcf) 55.4 60.3 (4.9) (8.1) %

Average Sales Price - Gas (per Mcf) $ 2.96 $ 3.53 $ (0.57) (16.1) %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.13 $ (0.14) $ 0.27 192.9 %

Total Average CBM Sales Price (per Mcf) $ 3.09 $ 3.39 $ (0.30) (8.8) %

Average CBM Lease Operating Expenses (per Mcf) 0.29 0.37 (0.08) (21.6) %

Average CBM Production, Ad Valorem and Other Fees (per Mcf) 0.12 0.12 — — %

Average CBM Transportation, Gathering and Compression Costs (per Mcf) 0.72 0.79 (0.07) (8.9) %

Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.32 1.28 0.04 3.1 %

Total Average CBM Costs (per Mcf) $ 2.45 $ 2.56 $ (0.11) (4.3) %

Average Margin for CBM (per Mcf) $ 0.64 $ 0.83 $ (0.19) (22.9) %

The CBM segment had natural gas revenue of $164 million for the year ended December 31, 2019 compared to $213 million for the year ended December 31, 2018.

The $49 million decrease was due to an 8.1% decrease in total CBM sales volumes and the 16.1% decrease in the average gas sales price.

The decrease in CBM sales volumes was primarily due to normal well declines, as well as the sale of certain CBM assets that were sold along with the majority of CNX's shallow oil and gas assets in 2018 (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The total average CBM sales price decreased $0.30 per Mcf due to a $0.57 per Mcf decrease in average gas sales price, offset in part by a $0.27 per Mcf increase in the gain (loss) on commodity derivative instruments resulting from the Company's hedging program.

The notional amounts associated with these financial hedges represented approximately 40.9 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2019 at an average gain of $0.18 per Mcf hedged.

For the year ended December 31, 2018, these financial hedges represented approximately 44.8 Bcf at an average loss of $0.20 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $136 million for the year ended December 31, 2019 compared to $154 million for the year ended December 31, 2018.

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

• CBM lease operating expense was $16 million for the year ended December 31, 2019 compared to $22 million for the year ended December 31, 2018.

The $6 million decrease was primarily due to reductions in contract services, a decrease in repairs and maintenance costs, and a reduction in employee costs.

The decrease in unit costs was also due to the decrease in total dollars.

• CBM transportation, gathering and compression costs were $40 million for the year ended December 31, 2019 compared to $48 million for the year ended December 31, 2018.

The $8 million decrease in total dollars as well as the $0.07 per Mcf decrease in unit costs were primarily related to a decrease in electrical power expense as well as a decrease in contractor services.

• Depreciation, depletion and amortization costs attributable to the CBM segment were $73 million for the year ended December 31, 2019 compared to $77 million for the year ended December 31, 2018.

These amounts each included depletion on a unit of production basis of $0.70 per Mcfe.

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, exploration and production related other costs, impairments, 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 $524 million for the year ended December 31, 2019 compared to earnings before income tax of $422 million for the year ended December 31, 2018.

For the Years Ended December 31,

2019 2018 Variance Percent

Other Gas Sales Volumes (Bcf) 0.3 4.7 (4.4) (93.6) %

Oil/Condensate Sales Volumes (Bcfe)* — 0.2 (0.2) (100.0) %

Total Other Sales Volumes (Bcfe)* 0.3 4.9 (4.6) (93.9) %

Other Gas sales volumes were primarily related to shallow oil and gas production.

CNX sold substantially all of these assets on March 30, 2018 (See Note 4 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

There was $1 million of natural gas and oil revenue related to the Other Gas segment for the year ended December 31, 2019 compared to $16 million for the year ended December 31, 2018.

Total operating costs and expenses related to these other gas sales volumes were $6 million for the year ended December 31, 2019 compared to $18 million for the year ended December 31, 2018.

The decrease in natural gas and oil revenue was due to the asset sale.

Gain or Loss on Commodity Derivative Instruments

The Other Segment recognized an unrealized gain on commodity derivative instruments of $306 million and cash settlements received of $1 million for the year ended December 31, 2019.

For the year ended December 31, 2018, the Other Segment recognized an unrealized gain on commodity derivative instruments of $40 million and cash settlements paid of $1 million.

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

Purchased Gas

Purchased gas volumes represent volumes of 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 revenues were $94 million for the year ended December 31, 2019 compared to $66 million for the year ended December 31, 2018.

Purchased gas costs were $91 million for

the year ended December 31, 2019 compared to $65 for the year ended December 31, 2018.

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

For the Years Ended December 31,

2019 2018 Variance Percent Change

Purchased Gas Sales Volumes (in Bcf) 40.6 20.5 20.1 98.0 %

Average Sales Price (per Mcf) $ 2.32 $ 3.23 $ (0.91) (28.2) %

Average Cost (per Mcf) $ 2.23 $ 3.17 $ (0.94) (29.7) %

Other Operating Income

For the Years Ended December 31,

(in millions) 2019 2018 Variance Percent Change

Water Income $ 2 $ 11 $ (9) (81.8) %

Equity in Earnings of Affiliates 2 5 (3) (60.0) %

Excess Firm Transportation Income

Total Other Operating Income $ 14 $ 26 $ (12) (46.2) %

• Water income decreased $9 million due to nominal sales of freshwater to third parties for hydraulic fracturing in 2019 compared to 2018.

Impairment of Exploration and Production Properties

During the fourth quarter of 2019, CNX identified certain indicators of impairment specific to our CPA Marcellus asset group and determined that carrying value of that asset group was not recoverable.

This impairment was related to 56 operated wells and approximately 51,000 acres within our CPA Marcellus proved properties in Armstrong, Indiana, Jefferson and Westmoreland counties.

The majority of these properties were developed prior to 2013 and the last of these properties were developed in 2015.

Impairment of Unproved Properties and Expirations

Capitalized costs of unproved oil and gas properties are evaluated periodically for indicators of potential impairment.

The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced.

Expense for lease expirations that were not previously impaired are recorded as the leases expire.

These unproved properties are within CNX's CPA operating region and east of the acreage associated with the proved property impairment described above.

Impairment of Other Intangible Assets

Intangible assets are tested for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable.

An impairment loss would be recognized when the carrying amount of the asset exceeds the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition.

The impairment loss to be recorded would be the excess of the asset's carrying value over its fair value.

In connection with the AEA with HG Energy (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) that occurred during the year ended December 31, 2018, CNX determined that the carrying value of the other intangible asset - customer relationship exceeded its fair value, and an impairment of $19 million was included in Impairment of Other Intangible Assets in the Consolidated Statement of Income.

No such transactions occurred in the 2019 period.

Exploration and Production Related Other Costs

For the Years Ended December 31,

(in millions) 2019 2018 Variance Percent Change

Lease Expiration Costs $ 31 $ 5 $ 26 520.0 %

Seismic Activity 8 — 8 100.0 %

Land Rentals 3 4 (1) (25.0) %

Other 2 3 (1) (33.3) %

Total Exploration and Production Related Other Costs $ 44 $ 12 $ 32 266.7 %

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

The $26 million increase in the period-to-period comparison is due to an increase in the number of leases that were allowed to expire in the year ended December 31, 2019, or will expire within the next 12 months, because they were no longer in the Company's future drilling plan.

Additionally, approximately $15 million of the $26 million increase is associated with leases which have ceased production.

• Seismic activity increased in the period-to-period comparison due to additional geophysical research in the 2019 period.

SG&A costs include costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees 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) 2019 2018 Variance Percent Change

Long-Term Equity-Based Compensation (Non-Cash) $ 38 $ 21 $ 17 81.0 %

Salaries, Wages and Employee Benefits 40 40 — — %

Short-Term Incentive Compensation 21 24 (3) (12.5) %

Other 45 50 (5) (10.0) %

Total SG&A $ 144 $ 135 $ 9 6.7 %

• Long-term equity-based compensation increased $17 million in the period-to-period comparison due to the Company incurring an additional $20 million of long-term equity-based compensation (non-cash) expense during the year ended December 31, 2019.

The additional expense was a result of the acceleration of vesting of certain pre-2019 restricted stock units and performance share units held by certain employees related to the trigger of a contractual change in control event.

See Note 15 - Stock-Based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

The remaining variance was due to various items that occurred throughout both periods, none of which were individually material.

• Short-term incentive compensation decreased $3 million due to a reduction in the number of employees and lower projected payouts in the 2019 period.

Other Operating Expense

For the Years Ended December 31,

(in millions) 2019 2018 Variance Percent Change

Unutilized Firm Transportation and Processing Fees $ 55 $ 42 $ 13 31.0 %

Idle Equipment and Service Charges 12 5 7 140.0 %

Insurance Expense 4 3 1 33.3 %

Severance Expense 1 1 — — %

Litigation Expense — 4 (4) (100.0) %

Water Expense — 6 (6) (100.0) %

Other 8 11 (3) (27.3) %

Total Other Operating Expense $ 80 $ 72 $ 8 11.1 %

• 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.

The increase in the period-to-period comparison was primarily due to previously-acquired capacity which was not utilized during the 2019 period to transport the Company's flowing production.

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 increase 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 Gathering Income in Total Other Operating Income above.

• Idle Equipment and Service Charges primarily relate to the temporary idling of some of the Company's natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process.

The increase of $7 million in the period-to-period comparison was primarily the result CNX terminating one of its drilling rig contracts early, as well as additional idle service expense related to the Shaw 1G Utica Shale well that occurred in the first quarter of 2019.

• Water Expense decreased $6 million due to the associated costs related to the sales of freshwater to third-parties for hydraulic fracturing during 2018 in Total Other Operating Income above.

There were nominal sales during 2019.

Other Expense (Income)

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 the current fiscal year.

Nevertheless, the ability of CNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, including the current COVID-19 pandemic, 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 costs were to increase significantly, our cash flows and liquidity could be reduced.

As of December 31, 2021, 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.

As of December 31, 2021, cash and cash equivalents totaled $3.6 million.

• Accounts and notes receivable - trade as of December 31, 2021 and 2020 was $330.1 million and $145.9 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 $470 million to $500 million for the year ended December 31, 2022, compared to capital expenditures of $465.9 million in fiscal year 2021.

In addition, 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 575.0 Bcfe and 605.0 Bcfe for the year ended December 31, 2022, compared to production volumes of 590.2 Bcfe in fiscal year 2021.

• 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.

The fair value of these contracts was a net liability of $976 million at December 31, 2021 and a net asset of $118 million at December 31, 2020.

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

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

Cash Flows (in millions)

For the Years Ended December 31,

(in millions) 2019 2018 Variance Percent Change

Royalty Income $ 4 $ 15 $ (11) (73.3) %

Right of Way Sales 9 14 (5) (35.7) %

Interest Income 2 — 2 100.0 %

Other 4 8 (4) (50.0) %

Total Other Income $ 19 $ 37 $ (18) (48.6) %

Other Expense

Bank Fees $ 11 $ 11 $ — — %

Professional Services 4 7 (3) (42.9) %

Other Land Rental Expense 4 4 — — %

Other Corporate Expense 3 — 3 100.0 %

Total Other Expense $ 22 $ 22 $ — — %

Total Other Expense (Income) $ 3 $ (15) $ 18 120.0 %

Gain on Asset Sales and Abandonments, net

A gain on asset sales of $36 million related to non-core assets was recognized in the year ended December 31, 2019 compared to a gain of $157 million in the year ended December 31, 2018, primarily due to the $131 million gain that was recognized related to the sale of substantially all of CNX's Ohio Utica JV assets as well as the sale of various other non-core assets in the 2018 period.

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.

Gain on Previously Held Equity Interest

CNX recognized a gain on previously held equity interest of $624 million in the year ended December 31, 2018 due to the Midstream Acquisition that occurred in January 2018.

No such transactions occurred in the 2019 period.

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 $8 million was recognized in the year ended December 31, 2019 compared to a loss on debt extinguishment of $54 million in the year ended December 31, 2018.

During the year ended December 31, 2019, CNX purchased $400 million of its 5.875% senior notes due in April 2022 at an average price equal to 101.5% of the principal amount.

During the year ended December 31, 2018, CNX purchased $411 million of its 5.875% senior notes due in April 2022 at an average price equal to 103.5% of the principal amount and redeemed the $500 million 8.00% senior notes due in April 2023 at a call price equal to 106.0% of the principal amount.

2021 2020 Change

Cash Provided by Operating Activities $ 926 $ 795 $ 131

Cash Used in Investing Activities $ (421) $ (439) $ 18

Cash Used in Financing Activities $ (524) $ (351) $ (173)

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

• Net loss increased $70 million in the period-to-period comparison.

• Adjustments to reconcile net loss to cash provided by operating activities primarily consisted of a $473 million impairment of goodwill and a $62 million impairment of exploration and production properties in the prior year, an $805 million net change in commodity derivative instruments, a $20 million change in deferred income taxes, a $44 million change in gain/loss on debt extinguishment, as well as 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 $21 million in the period-to-period comparison primarily due to decreased expenditures in the Shale segment resulting from decreased drilling and completions activity as well as decreased midstream activity.

• Proceeds from asset sales decreased $3 million mainly due to decreased sales of rights-of-way, surface acreage and other non-core oil and gas interests in the year ended December 31, 2021.

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

• 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.

Interest Expense

For the Years Ended December 31,

(in millions) 2019 2018 Variance Percent Change

Total Interest Expense $ 151 $ 146 $ 5 3.4 %

• The $5 million increase was primarily due to additional borrowings on the CNX and CNXM credit facilities as well as a completed private offering of $500 million of 7.25% senior notes due March 2027 during the year ended December 31, 2019.

These increases were partially offset by the reduction in higher cost long-term debt, resulting from the $500 million purchase of the outstanding 8.00% senior notes due in April 2023 and the $411 million purchase of the outstanding 5.875% senior notes due in April 2022 during the year ended December 31, 2018.

Additionally, the Company purchased $400 million of its outstanding 5.875% senior notes due in April 2022 during the year ended December 31, 2019.

• 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.

For the Years Ended December 31,

(in millions) 2019 2018 Variance Percent Change

Total Company Earnings Before Income Tax $ 60 $ 1,099 $ (1,039) (94.5) %

Income Tax Expense $ 28 $ 216 $ (188) (87.0) %

Effective Income Tax Rate 46.5 % 19.6 % 26.9 %

The effective income tax rate was 46.5% for the year ended December 31, 2019, compared to 19.6% for the year ended December 31, 2018.

The effective rate for the year ended December 31, 2019 differs from the U.S.

federal statutory rate of 21% primarily due to state income taxes, equity compensation and state valuation allowances partially offset by the benefit from non-controlling interest.

During the year ended December 31, 2018, CNX obtained a controlling interest in CNX Gathering LLC and, through CNX Gathering's ownership of the general partner, control over CNXM.

All of CNXM’s income is included in the Company's pre-tax income.

However, the Company is not required to record income tax expense with respect to the portions of CNXM’s income allocated to the noncontrolling public limited partners of CNXM, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the Company's effective tax rate in periods when the Company has consolidated pre-tax loss.

The effective rate for the year ended December 31, 2018 differs from the U.S.

federal statutory 21% primarily due to a benefit from the filing of a Federal 10-year net operating loss (“NOL”)

carryback which resulted in the Company being able to utilize previously valued tax attributes at a tax rate differential of 14%, noncontrolling interest, the reversal of the alternative minimum tax ("AMT") credit sequestration valuation allowance, and the release of certain state valuation allowances as a result of a corporate reorganization during the year.

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.

• In the year ended December 31, 2021, there were $106 million of net payments on the CNXM Credit Facility compared to $21 million of net payments during the year ended December 31, 2020.

• In the year ended December 31, 2021, there were $31 million of net proceeds on the CNX Credit Facility compared to $500 million of net payments during the year ended December 31, 2020.

• 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, 2021 and 2020, CNX repurchased $245 million and $37 million, respectively, of its common stock on the open market.

• During the year ended December 30, 2020, CNX paid $882 million to purchase $894 million of Senior Notes due in 2022 at 98.6% 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, 2020, CNX received proceeds of $500 million from the issuance of its 6.00% Senior Notes due January 2029.

• During the year ended December 31, 2020, CNX completed a private offering of $200 million aggregate principal amount of its 7.25% Senior Notes due March 2027 at a price of 103.5% for cash proceeds of $207 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, 2020, CNX received proceeds of $335 million from the issuance of Convertible Notes due 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.

• During the year ended December 31, 2020, CNX paid $36 million for capped call transactions related to the issuance of the Convertible Notes as mentioned above.

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, 2020 there were $42 million of payments to CNXM noncontrolling interest holders compared to no payments during the year ended December 31, 2021 due to the Merger with CNXM.

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.

Commitments and Significant Contractual Obligations

The following is a summary of the Company's significant contractual obligations at December 31, 2021 (in thousands):

Payments due by Year

1 Year 1-3 Years 3-5 Years More Than

5 Years Total

Purchase Order Firm Commitments $ 777 $ 642 $ — $ — $ 1,419

Gas Firm Transportation and Processing 257,796 437,921 387,027 896,943 1,979,687

Long-Term Debt — — 630,716 1,600,801 2,231,517

Interest on Long-Term Debt 116,792 231,156 225,258 167,720 740,926

Finance Lease Obligations 555 883 333 2 1,773

Interest on Finance Lease Obligations 30 51 25 — 106

Operating Lease Obligations 23,460 9,395 9,116 24,591 66,562

Interest on Operating Lease Obligations 2,366 4,015 3,056 2,988 12,425

Long-Term Liabilities—Employee Related (a) 2,039 4,296 4,580 33,504 44,419

Other Long-Term Liabilities (b) 230,804 10,000 10,000 68,859 319,663

Total Contractual Obligations (c) $ 634,619 $ 698,359 $ 1,270,111 $ 2,795,408 $ 5,398,497

_________________________

(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, 2021.

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.

At December 31, 2021, CNX had total long-term debt of $2,232 million, excluding unamortized debt issuance costs.

This long-term debt consisted of:

• An aggregate principal amount of $700 million of 7.25% Senior Notes due March 2027 plus $6 million of unamortized bond premium.

Interest on the notes is payable March 14 and September 14 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 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 $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $5 million of unamortized bond 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 $345 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $91 million of unamortized bond 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).

• An aggregate principal amount of $192 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 $185 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.

Total Equity and Dividends

CNX had total equity of $3,700 million at December 31, 2021 compared to $4,422 million at December 31, 2020.

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.

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

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

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

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

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

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

There were no defaults in the year ended December 31, 2021.

Critical Accounting Policies

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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.

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, 2020, CNX had deferred tax liabilities in excess of deferred tax assets of approximately $343 million.

At December 31, 2021, prior to consideration of valuation allowances on deferred tax assets, CNX had deferred tax liabilities in excess of deferred tax assets of approximately $177 million.

At December 31, 2021, CNX had a valuation allowance of $152 million on deferred tax assets.

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

The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise

judgment regarding the amount of financial statement benefit to record for uncertain tax positions.

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

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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.

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.

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This impairment was related to our Southwest Pennsylvania (SWPA) coalbed methane (CBM) asset group.

For the year ended December 31, 2019, an impairment of $327 million was included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income.

This impairment was related to 56 operated wells and approximately 51,000 acres within our CPA Marcellus proved properties in Armstrong, Indiana, Jefferson and Westmoreland counties.

See Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

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

For the year ended December 31, 2019, an impairment of $119 million was included in Impairment of Unproved Properties and Expirations in the Consolidated Statements of Income.

There were no other impairments related to unproved properties in the years ended December 31, 2020, 2019 or 2018.

There were no impairments related to unproved properties in the years ended December 31, 2021 or 2020.

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.

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

See Note 4 - Acquisitions and Dispositions for more information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

See Note 9 - Goodwill and Other Intangible Assets for more information 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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and forecasts of revenue, operating income, depreciation 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.

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.

“Risk Factors” of this Form 10-K.

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

In May 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were acquired in connection with the Midstream acquisition exceeded their fair value in conjunction with the AEA with HG Energy (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).

As a result, CNX recognized an impairment on this intangible asset of $19 million, which is included in Impairment of Other Intangible Assets in the Consolidated Statements of Income for the year ended December 31, 2018.

There were no other impairments related to definite-lived intangible assets in the years ended December 31, 2020, 2019 or 2018.

There were no impairments related to definite-lived intangible assets in the years ended December 31, 2021 or 2020.

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

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

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

however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about the

impairment of definite-lived intangible assets which could materially impact the Company’s results of operations and financial position.

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

Business Combinations

Accounting for the acquisition of a business requires the identifiable assets and liabilities acquired to be recorded at fair value.

The most significant assumptions in a business combination include those used to estimate the fair value of the oil and natural gas properties acquired.

The fair value of proved natural gas properties is determined using a risk-adjusted after-tax

discounted cash flow analysis based upon significant assumptions including commodity prices;

projections of estimated quantities of reserves;

projections of future rates of production;

timing and amount of future development and operating costs;

projected reserve recovery factors;

and a weighted average cost of capital.

The Company utilizes the guideline transaction method to estimate the fair value of unproved properties acquired in a business combination which requires the Company to use judgment in considering the value per undeveloped acre in recent comparable transactions to estimate the value of unproved properties.

The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach, which incorporates assumptions about the replacement costs for similar assets, the relative age of assets and any potential economic or functional obsolescence.

The fair values of the intangible assets are estimated using the multi-period excess earnings model which estimates revenues and cash flows derived from the intangible asset and then deducts portions of the cash flow that can be attributed to supporting assets otherwise recognized.

The Company’s intangible assets are comprised of customer relationships.

The Company believes that the accounting estimates related to business combinations are “critical accounting estimates” because the Company must, in determining the fair value of assets acquired, make assumptions about future commodity prices;

projections of estimated quantities of reserves;

projections of future rates of production;

projections regarding the timing and amount of future development and operating costs;

and projections of reserve recovery factors, per acre values of undeveloped property, replacement cost of and future cash flows from midstream assets, cash flow from customer relationships and non-compete agreements and the pre and post modification value of stock based awards.

Different assumptions may result in materially different values for these assets which would impact the Company’s financial position and future results of operations.

Convertible Senior Notes

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however, different assumptions and estimates could materially impact the calculated fair value and the resulting balance sheet classification.

Liquidity and Capital Resources

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.

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, including the current COVID 19 pandemic, 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 or due to the uncertainty created by the COVID-19 pandemic, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be reduced.

As of December 31, 2020, CNX was in compliance with all of its debt covenants.

After considering the potential effect of a significant decline in commodity prices as well as the uncertainty created by the COVID-19 pandemic on its operations, CNX currently expects to remain in compliance with its debt covenants.

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.

The fair value of these contracts was a net asset of $118 million at December 31, 2020 and a net asset of $406 million at December 31, 2019.

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

CNX frequently evaluates potential acquisitions.

CNX has 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.

Cash Flows (in millions)

For the Years Ended December 31,

2020 2019 Change

Cash Provided by Operating Activities $ 795 $ 981 $ (186)

Cash Used in Investing Activities $ (439) $ (1,147) $ 708

Cash (Used in) Provided by Financing Activities $ (351) $ 166 $ (517)

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

• Net income decreased $461 million in the period-to-period comparison.

• Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $473 million impairment of goodwill, a $266 million decrease in impairment of exploration and production properties, a $119 million decrease in impairment of unproved properties and expirations, a $595 million net change in commodity derivative instruments, an $18 million increase in the gain on debt extinguishment, a $24 million decrease in stock based compensation, $197 million change in deferred income taxes, and 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 $705 million in the period-to-period comparison primarily due to decreased expenditures in the Shale segment resulting from decreased drilling and completions activity.

Gathering capital expenditures decreased due primarily to the substantial build out that was completed during 2019.

• Proceeds from asset sales increased $3 million mainly due to increased surface sales and oil and natural gas assignment sales in the year ended December 31, 2020.

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

• In the year ended December 31, 2020, CNX paid $882 million to purchase $894 million of Senior Notes due in 2022 at 98.6% of the principal amount.

In the year ended December 31, 2019, CNX paid $406 million to purchase $400 million of the Senior Notes due in 2022 at 101.5% 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.

• In the year ended December 31, 2020, there were $21 million of net payments on the CNXM Credit Facility compared to $228 million of net proceeds in the year ended December 31, 2019.

• In the year ended December 31, 2020, there were $500 million of net payments on the CNX Credit Facility compared to $49 million of net proceeds in the year ended December 31, 2019.

• In the year ended December 31, 2020, CNX received proceeds of $500 million from the issuance of Senior Notes due in 2029.

• In the year ended December 31, 2020, CNX received proceeds of $207 million from the issuance of Senior Notes due in 2027 at 103.5% of the principal amount.

The new Senior Notes due in 2027 were offered as additional notes under an indenture pursuant to the $500 million Senior Notes due in 2027 that were issued in the year ended December 31, 2019.

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.

• In the year ended December 31, 2020, there were $159 million of net proceeds from the Cardinal States Facility and CSG Holdings 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.

• In the year ended December 31, 2020 , CNX received proceeds of $335 million from the issuance of the Convertible Notes.

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.

• In the year ended December 31, 2020 , CNX paid $36 million for capped call transactions related to the issuance of the Convertible Notes.

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.

• In the year ended December 31, 2020, there were $42 million in distributions to CNXM noncontrolling interest holders compared to distributions of $64 million in the year ended December 31, 2019.

• In the years ended December 31, 2020 and 2019, CNX repurchased $37 million and $117 million, respectively, of its common stock on the open market.

• Debt issuance and financing fees increased $15 million primarily due to the fees associated with the borrowings on the Cardinal States Facility and CSG Holdings Facility and the issuance of the Convertible Notes.

The following is a summary of the Company's significant contractual obligations at December 31, 2020 (in thousands):

Payments due by Year

1 Year 1-3 Years 3-5 Years More Than

5 Years Total

Purchase Order Firm Commitments $ 806 $ 970 $ — $ — $ 1,776

Gas Firm Transportation and Processing 252,886 430,312 390,693 985,201 2,059,092

Long-Term Debt 22,574 48,181 497,423 1,882,675 2,450,853

Interest on Long-Term Debt 122,251 262,415 240,083 202,118 826,867

Finance Lease Obligations 6,876 837 182 38 7,933

Interest on Finance Lease Obligations 262 52 11 1 326

Operating Lease Obligations 52,575 23,301 7,434 22,500 105,810

Interest on Operating Lease Obligations 3,615 3,744 2,823 3,496 13,678

Long-Term Liabilities—Employee Related (a) 1,992 4,169 4,436 35,129 45,726

Other Long-Term Liabilities (b) 201,684 10,000 10,000 64,713 286,397

Total Contractual Obligations (c) $ 665,521 $ 783,981 $ 1,153,085 $ 3,195,871 $ 5,798,458

_________________________

(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.

At December 31, 2020, CNX had total long-term debt of $2,451 million, including the current portion of long-term debt of $23 million and excluding unamortized debt issuance costs.

This long-term debt consisted of:

• An aggregate principal amount of $700 million of 7.25% Senior Notes due March 2027 plus $7 million of unamortized bond premium.

Interest on the notes is payable March 14 and September 14 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) or CSG Holdings III LLC.

• 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) or CSG Holdings III LLC.

• An aggregate principal amount of $400 million of 6.50% Senior Notes due March 2026 issued by CNXM, less $4 million of unamortized bond discount.

Interest on the notes is payable March 15 and September 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 $345 million of 2.25% Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $108 million of unamortized bond 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) or CSG Holdings III LLC.

• An aggregate principal amount of $291 million in outstanding borrowings under the CNXM Credit Facility.

CNX is not a guarantor of CNXM's Credit Facility.

• An aggregate principal amount of $161 million in outstanding borrowings under the CNX Credit Facility.

CNXM (or its subsidiaries or general partner) is not a guarantor of CNX's Credit Facility.

• An aggregate principal amount of $115 million in outstanding borrowings under the Cardinal States Facility, less $1 million of unamortized discount.

Interest and a portion of the obligation are paid quarterly.

• An aggregate principal amount of $45 million in outstanding borrowings under the CSG Holdings Facility, less a nominal unamortized discount.

Interest and a portion of the obligation are paid quarterly.

Total Equity and Dividends

CNX had total equity of $4,422 million at December 31, 2020 compared to $4,962 million at December 31, 2019.

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 suspended its quarterly dividend in March 2016 to further reflect the Company's increased emphasis on growth at that time.

The net leverage ratio was 2.45 to 1.00 at December 31, 2020.

The Credit Facility does not permit dividend payments in the event of default.

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

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

There were no defaults under the year ended December 31, 2020.

Off-Balance Sheet Transactions

Management believes these items will expire without being funded.

Recent Accounting Pronouncements

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity.

This ASU simplifies an entity's accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, simplifies the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification, requires entities to use the if-converted method for all convertible instruments in the diluted EPS calculation and include the effect of potential share settlement (if the effect is more dilutive) for instruments that may be settled in cash or shares, except for certain liability-classified share-based payment awards, requires new disclosures about events that occur during the reporting period and cause conversion contingencies to be met and about the fair value of an entity's convertible debt at the instrument level, among other things.

The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years, and can be adopted through either a modified retrospective method of transition or a fully retrospective method of transition.

Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020, including interim periods within those fiscal years.

The Company is still evaluating the effect of adopting this guidance.

In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (Topic 848).

This ASU provides optional expedient and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met.

In response to the concerns about structural risks of interbank offered rates (IBORs) and, particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR), regulators in several jurisdictions around the world have undertaken reference rate reform initiatives to identify alternative reference rates that are more observable or transaction based and less susceptible to manipulation.

The ASU provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates that are expected to be discontinued.

In January 2021, the FASB issued ASU 2021-01, which clarifies that certain provisions in Topic 848, if elected by an entity, apply to derivative instruments that use an interest rate for margining, discounting, or contract price alignment that is modified as a result of reference rate reform.

The amendments in these ASUs are effective for all entities as of March 12, 2020 through December 31, 2022.

The Company is still evaluating the effect of adopting this guidance.

In March 2020, the FASB issued ASU 2020-03 - Codification Improvements to Financial Instruments.

This ASU improves and clarifies various financial instruments topics, including the CECL standard (see Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K for more information).

The ASU includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications.

The amendments in this ASU have different effective dates.

The adoption of this guidance is not expected to have a material impact on the Company's 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 a summary of recent accounting pronouncements.

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