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Item 7. Management’s Discussion and Analysis

2021-02-09 compared with 2020-02-10 · 630 added, 376 removed, 345 unchanged (74% of the section changed)

6 unchanged sentences

Risk Factors” and the section entitled “Forward‑Looking Statements.” CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

The Company has applied the Fast Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent fiscal years.

This section of this Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018.

Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II.

Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

COVID-19 Update:

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.

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.

2020 Highlights:

Record total gas production of 539.1 Bcfe in 2019, 6.3% higher than 2018.

Record Marcellus Shale production of 369.7 Bcfe in 2019, 28.3% higher than 2018.

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

• Total gas production of 511.1 Bcfe.

• Shale production of 458.3 Bcfe.

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

Repurchased $400 million of 5.875% notes due in 2022.

• 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).

2021 Outlook:

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

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 .

Net Loss Attributable to CNX Resources Shareholders

CNX reported a net loss attributable to CNX Resources shareholders of $484 million, or a loss per diluted share of $2.43, for the year ended December 31, 2020, compared to 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.

For the Years Ended December 31,

(Dollars in thousands)

(Dollars in thousands) 2020 2019 Variance

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

Net Income Attributable to Noncontrolling Interests 55,031 112,678 (57,647)

Net (Loss) Income Attributable to CNX Resources Shareholders

CNX consists of two principal business divisions:

Exploration and Production (E&P) and Midstream.

The principal activity of the E&P Division is to produce pipeline quality natural gas for sale primarily to gas wholesalers.

The E&P division's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane and Other Gas.

CNX's E&P Division had a loss before income tax of $ 140 million for the year ended December 31, 2019 , compared to earnings before income tax of $ 245 million for the year ended December 31, 2018 .

Included in the 2019 loss 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 (See the Other Gas Segment for more information).

There were no such transactions in the 2018 period.

Offsetting the loss for the 2019 period was an unrealized gain on commodity derivative instruments of $ 306 million compared to an unrealized gain of $ 40 million for the year ended December 31, 2018 .

CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets, through CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia.

Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM.

As a result of the Midstream Acquisition (See Note 6 - 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 in the current period.

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

CNX's Midstream Division had earnings before income tax of $ 167 million for the year ended December 31, 2019 , compared to earnings before income tax of $ 134 million for the period from January 3, 2018 through December 31, 2018 .

E&P Division Summary

Sales volumes, average sales prices (including the effects of settled derivatives instruments), and average costs for the E&P Division were as follows:

Net Loss Attributable to CNX Resources Shareholders $ (483,775) $ (80,730) $ (403,045)

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.

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, 2019.

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:

For the Years Ended December 31,

Sales Volume (Bcfe)

Average Sales Price - Gas (per Mcf)

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)

Average Sales Price - NGLs (per Mcfe)*

Average Sales Price - Oil (per Mcfe)*

Average Sales Price - Condensate (per Mcfe)*

Average Sales Price (per Mcfe)

Lease Operating Expense (per Mcfe)

Production, Ad Valorem, and Other Fees (per Mcfe)

Transportation, Gathering and Compression (per Mcfe)

Depreciation, Depletion and Amortization (DD&A) (per Mcfe)

Average Costs (per Mcfe)

Average Margin (per Mcfe)

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

Excluding the effects of settled derivative instruments, natural gas, NGLs, and oil revenue was $ 1,364 million for the year ended December 31, 2019 , compared to $ 1,578 million for the year ended December 31, 2018 .

The decrease was primarily due to the 10.4% decrease in the average sales price driven by lower natural gas and NGL prices offset in-part by the 6.3% increase in total sales volumes.

The 6.3% 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.

The decrease in average sales price was primarily the result of a $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.

There was also a $0.09 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging.

Both decreases were offset, in part,

by a $0.29 per Mcf increase in the realized gain (loss) on commodity derivative instruments related to the Company's hedging program.

2020 2019 Variance

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

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

Natural Gas, NGL and Oil Revenue $ 897 $ 1.71 $ 1,364 $ 2.52 $ (467) $ (0.81)

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)

Lease Operating Expense 40 0.08 65 0.12 (25) (0.04)

Production, Ad Valorem, and Other Fees 24 0.04 27 0.05 (3) (0.01)

Transportation, Gathering and Compression 286 0.56 331 0.61 (45) (0.05)

Depreciation, Depletion and Amortization (DD&A) 492 0.96 506 0.94 (14) 0.02

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

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

*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.

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

Transportation, gathering and compression expense increased on a per unit basis primarily due to an increase in CNXM gathering fees related to an increase in our Marcellus production and an increase in firm transportation expense, primarily as a result of new contracts that give CNX the ability to move and sell gas outside of the Appalachian basin.

The decrease in production from CNX's lower cost dry Utica volumes as well as the third quarter 2018 sale of CNX's Ohio JV assets also contributed to the increase on a per unit basis.

See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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 current 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.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s natural gas production and sales portfolio.

• 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,

in thousands (unless noted)

Sales Volume (MMcfe)

Sales Volume (Mbbls)

Gross Price ($/Bbl)

Gross Revenue

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.

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) 2020 2019 Variance Percent Change

Sales Volume (MMcfe) 28,062 32,571 (4,509) (13.8) %

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Gross Price ($/Bbl) $ 13.74 $ 19.20 $ (5.46) (28.4) %

Gross Revenue

Gross NGL Revenue $ 64,138 $ 104,139 $ (40,001) (38.4) %

Oil/Condensate:

Sales Volume (MMcfe) 1,584 1,223 361 29.5 %

1 unchanged sentence

Gross Price ($/Bbl) $ 35.91 $ 45.00 $ (9.09) (20.2) %

Gross Revenue

Gross Oil/Condensate Revenue $ 9,475 $ 9,173 $ 302 3.3 %

Sales Volume (MMcf) 481,426 505,355 (23,929) (4.7) %

Sales Price ($/Mcf) $ 1.71 $ 2.48 $ (0.77) (31.0) %

Gross Revenue

Gross Gas Revenue $ 823,132 $ 1,251,013 $ (427,881) (34.2) %

Hedging Impact ($/Mcf) $ 0.78 $ 0.14 $ 0.64 457.1 %

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement

Selling, General and Administrative ("SG&A") - Total Company

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

*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.

SEGMENT ANALYSIS for the year ended December 31, 2020 compared to the year ended December 31, 2019:

For the Year Ended Difference to Year Ended

December 31, 2020 December 31, 2019

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

Natural Gas, NGLs and Oil Revenue $ 781 $ 114 $ 2 $ 897 $ (418) $ (50) $ 1 $ (467)

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

Purchased Gas Revenue — — 106 106 — — 12 12

Other Revenue and Operating Income 65 — 17 82 (9) — 3 (6)

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

Lease Operating Expense 26 14 — 40 (23) (2) — (25)

Production, Ad Valorem, and Other Fees 19 5 — 24 (2) (2) 1 (3)

Transportation, Gathering and Compression 248 39 (1) 286 (42) (1) (2) (45)

Depreciation, Depletion and Amortization 416 70 16 502 (10) (3) 7 (6)

Impairment of Exploration and Production Properties — — 62 62 — — (265) (265)

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

Impairment of Goodwill — — 473 473 — — 473 473

Exploration and Production Related Other Costs — — 15 15 — — (29) (29)

Purchased Gas Costs — — 101 101 — — 10 10

Other Operating Expense — — 85 85 — — 5 5

Selling, General and Administrative Costs — — 109 109 — — (35) (35)

Total Operating Costs and Expenses 709 128 860 1,697 (77) (8) 46 (39)

Other Expense — — 24 24 — — 21 21

Gain on Asset Sales and Abandonments, net — — (21) (21) — — 15 15

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

Interest Expense — — 171 171 — — 20 20

Total Other Expenses — — 164 164 — — 38 38

Total Costs and Expenses 709 128 1,024 1,861 (77) (8) 84 (1)

Earnings (Loss) Before Income Tax $ 474 $ 26 $ (1,103) $ (603) $ (75) $ (9) $ (579) $ (663)

SHALE SEGMENT

The Shale segment had earnings before income tax of $474 million for the year ended December 31, 2020 compared to earnings before income tax of $549 million for the year ended December 31, 2019.

For the Years Ended December 31,

2020 2019 Variance Percent

Shale Gas Sales Volumes (Bcf) 428.7 449.6 (20.9) (4.6) %

NGLs Sales Volumes (Bcfe)* 28.1 32.6 (4.5) (13.8) %

Oil/Condensate Sales Volumes (Bcfe)* 1.5 1.2 0.3 25.0 %

Total Shale Sales Volumes (Bcfe)* 458.3 483.4 (25.1) (5.2) %

Average Sales Price - Gas (per Mcf) $ 1.65 $ 2.42 $ (0.77) (31.8) %

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

Average Sales Price - NGLs (per Mcfe)* $ 2.29 $ 3.20 $ (0.91) (28.4) %

Average Sales Price - Oil/Condensate (per Mcfe)* $ 5.83 $ 7.47 $ (1.64) (22.0) %

Total Average Shale Sales Price (per Mcfe) $ 2.44 $ 2.61 $ (0.17) (6.5) %

Average Shale Lease Operating Expenses (per Mcfe) 0.06 0.10 (0.04) (40.0) %

Average Shale Production, Ad Valorem, and Other Fees (per Mcfe) 0.04 0.05 (0.01) (20.0) %

Average Shale Transportation, Gathering and Compression Costs (per Mcfe) 0.54 0.60 (0.06) (10.0) %

Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) 0.91 0.88 0.03 3.4 %

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) %

The Shale segment had natural gas, NGLs and oil/condensate revenue of $781 million for the year ended December 31, 2020 compared to $1,199 million for the year ended December 31, 2019.

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.

Total operating costs and expenses for the Shale segment were $709 million for the year ended December 31, 2020 compared to $786 million for the year ended December 31, 2019.

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.

• Shale transportation, gathering and compression costs were $248 million for the year ended December 31, 2020 compared to $290 million for the year ended December 31, 2019.

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.

• Depreciation, depletion and amortization costs attributable to the Shale segment were $416 million for the year ended December 31, 2020 compared to $426 million for the year ended December 31, 2019.

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 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 $65 million for the year ended December 31, 2020 compared to $74 million for the year ended December 31, 2019.

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.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $26 million for the year ended December 31, 2020 compared to earnings before income tax of $35 million for the year ended December 31, 2019.

For the Years Ended December 31,

2020 2019 Variance Percent

CBM Gas Sales Volumes (Bcf) 52.6 55.4 (2.8) (5.1) %

Average Sales Price - Gas (per Mcf) $ 2.17 $ 2.96 $ (0.79) (26.7) %

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

Total Average CBM Sales Price (per Mcf) $ 2.93 $ 3.09 $ (0.16) (5.2) %

Average CBM Lease Operating Expenses (per Mcf) 0.27 0.29 (0.02) (6.9) %

Average CBM Production, Ad Valorem and Other Fees (per Mcf) 0.10 0.12 (0.02) (16.7) %

Average CBM Transportation, Gathering and Compression Costs (per Mcf) 0.73 0.72 0.01 1.4 %

Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.33 1.32 0.01 0.8 %

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) %

The CBM segment had natural gas revenue of $114 million for the year ended December 31, 2020 compared to $164 million for the year ended December 31, 2019.

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.

For the year ended December 31, 2019, these financial hedges represented approximately 40.9 Bcf at an average gain of $0.18 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $128 million for the year ended December 31, 2020 compared to $136 million for the year ended December 31, 2019.

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.

• Depreciation, depletion and amortization costs attributable to the CBM segment were $70 million for the year ended December 31, 2020 compared to $73 million for the year ended December 31, 2019.

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.

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, realized gain on commodity derivative instruments that were monetized prior to their contractual settlement dates, 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 $1,103 million for the year ended December 31, 2020 compared to a loss before income tax of $524 million for the year ended December 31, 2019.

The decrease in total dollars is discussed below.

For the Years Ended December 31,

2020 2019 Variance Percent Change

Other Gas Sales Volumes (Bcf) 0.1 0.3 (0.2) (66.7) %

Oil/Condensate Sales Volumes (Bcfe)* 0.1 — 0.1 100.0 %

Total Other Sales Volumes (Bcfe)* 0.2 0.3 (0.1) (33.3) %

*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.

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.

Purchased Gas

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 costs were $101 million for the year ended December 31, 2020 compared to $91 million for the year ended December 31, 2019.

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,

2020 2019 Variance Percent Change

Purchased Gas Sales Volumes (in Bcf) 66.6 40.6 26.0 64.0 %

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) %

Other Operating Income

For the Years Ended December 31,

(in millions) 2020 2019 Variance Percent Change

Water Income $ 6 $ 2 $ 4 200.0 %

Excess Firm Transportation Income 12 10 2 20.0 %

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

Total Other Operating Income $ 17 $ 14 $ 3 21.4 %

• 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.

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

The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase.

In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial.

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

Impairment of Exploration and Production Properties

During the year ended December 31, 2020, CNX recognized certain indicators of impairments specific to our SWPA CBM asset group and determined that the carrying value of that asset group was not recoverable.

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.

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.

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.

If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount using the qualitative assessment, a quantitative impairment test is performed.

From time to time, CNX may also bypass the qualitative assessment and proceed directly to the quantitative impairment test.

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.

Exploration and Production Related Other Costs

For the Years Ended December 31,

(in millions) 2020 2019 Variance Percent Change

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

Seismic Activity 1 8 (7) (87.5) %

Land Rentals 3 3 — — %

Other 1 2 (1) (50.0) %

Total Exploration and Production Related Other Costs $ 15 $ 44 $ (29) (65.9) %

• 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")

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.

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For the Years Ended December 31,

(in millions)

(in millions) 2020 2019 Variance Percent Change

Long-Term Equity-Based Compensation (Non-Cash) $ 14 $ 38 $ (24) (63.2) %

Salaries and Wages

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

Short-Term Incentive Compensation 20 21 (1) (4.8) %

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.

Other 44 45 (1) (2.2) %

Total SG&A $ 109 $ 144 $ (35) (24.3) %

• 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.

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 current period.

Unallocated Expense

Certain costs and expenses, such as other expense (income), gain on asset sales related to non-core assets, gain on previously held equity interest, loss on debt extinguishment, impairment of other intangible assets and income taxes are unallocated expenses and therefore are excluded from the per unit costs above as well as segment reporting.

Below is a summary of these costs and expenses:

Other Expense (Income)

• 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.

Other Operating Expense

For the Years Ended December 31,

(in millions)

Royalty Income

(in millions) 2020 2019 Variance Percent Change

Unutilized Firm Transportation and Processing Fees $ 70 $ 55 $ 15 27.3 %

Insurance Expense 3 4 (1) (25.0) %

Severance Expense — 1 (1) (100.0) %

Idle Equipment and Service Charges 10 12 (2) (16.7) %

Other 2 8 (6) (75.0) %

Total Other Operating Expense $ 85 $ 80 $ 5 6.3 %

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

In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity.

Such sales would result in an increase in unutilized firm transportation expense.

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

The revenue received when this capacity is released (sold) is included in 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.

Other Expense

For the Years Ended December 31,

(in millions) 2020 2019 Variance Percent Change

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

Royalty Income — 4 (4) (100.0) %

Interest Income 2 2 — — %

Other 8 4 4 100.0 %

Total Other Income $ 13 $ 19 $ (6) (31.6) %

Other Expense

Merger Related Costs $ 11 $ — $ 11 100.0 %

Professional Services 9 4 5 125.0 %

Bank Fees 12 11 1 9.1 %

Other Land Rental Expense 4 4 — — %

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Total Other Expense $ 37 $ 22 $ 15 68.2 %

Total Other Expense (Income)

Also refer to Other Expense contained in the section "Total Midstream Division Analysis" of this item of this Form 10-K for additional items that are not part of Unallocated Expense.

Total Other Expense $ 24 $ 3 $ 21 700.0 %

• 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.

Gain on Asset Sales and Abandonments, net

A gain on asset sales of $ 42 million related to non-core assets was recognized in the year ended December 31, 2019 compared to a gain of $ 155 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 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Also refer to the discussion of Loss (Gain) on Asset Sales and Abandonments, net contained in the section "Total Midstream Division Analysis" below for additional items that are not part of Unallocated Expense.

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 current period.

See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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 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.

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.

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.

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 6 - 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 current period.

Interest Expense

For the Years Ended December 31,

(in millions) 2020 2019 Variance Percent Change

Total Interest Expense $ 171 $ 151 $ 20 13.2 %

• 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.

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) 2020 2019 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) %

Effective Income Tax Rate 28.9 % 46.5 % (17.6) %

The effective income tax rate was 28.9% for the year ended December 31, 2020, compared to 46.5% for the year ended December 31, 2019.

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.

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.

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,

(in millions)

Total Company Earnings Before Income Tax

Income Tax Expense

Effective Income Tax Rate

TOTAL E&P DIVISION ANALYSIS for the year ended December 31, 2019 compared to the year ended December 31, 2018 :

The E&P division had a loss before income tax of $140 million for the year ended December 31, 2019 compared to earnings before income tax of $245 million for the year ended December 31, 2018 .

Variances by individual operating segment are discussed below.

For the Year Ended

Difference to Year Ended

December 31, 2019

December 31, 2018

(in millions)

(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

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)

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Purchased Gas Revenue — — 94 94 — — 28 28

Other Operating Income

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

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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

3 unchanged sentences

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 E&P Division Costs

Earnings (Loss) from Continuing Operations Before Income Tax

Included in the table above is a related party transportation, gathering and compression charge of $233 million that is offset in the Midstream Division in Midstream Revenue - Related Party.

Of this charge, $227 million related to Marcellus and $6 million related to Utica.

See Note 24 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

MARCELLUS SEGMENT

The Marcellus segment had earnings before income tax of $ 234 million for the year ended December 31, 2019 compared to earnings before income tax of $254 million for the year ended December 31, 2018 .

For the Years Ended December 31,

Marcellus Gas Sales Volumes (Bcf)

NGLs Sales Volumes (Bcfe)*

Condensate Sales Volumes (Bcfe)*

Total Marcellus Sales Volumes (Bcfe)*

Average Sales Price - Gas (per Mcf)

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)

Average Sales Price - NGLs (per Mcfe)*

Average Sales Price - Condensate (per Mcfe)*

Total Average Marcellus Sales Price (per Mcfe)

Average Marcellus Lease Operating Expenses (per Mcfe)

Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)

Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)

Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)

Total Average Marcellus Costs (per Mcfe)

Average Margin for Marcellus (per Mcfe)

The Marcellus segment had natural gas, NGLs and oil revenue of $ 935 million for the year ended December 31, 2019 compared to $ 903 million for the year ended December 31, 2018 .

The $ 32 million increase was due to a 28.3% increase in total Marcellus sales volumes.

The increase in sales volumes was primarily due to additional wells being turned in-line throughout 2018 and 2019 as part of the Company's ongoing drilling and completions program.

The decrease in the total average Marcellus sales price was primarily due to a $0.48 per Mcf decrease in average sales price for natural gas and a $1.35 per Mcfe decrease in the average NGL sales price, offset in part by a $0.30 per Mcf increase in the realized gain (loss) on commodity derivative instruments resulting from the Company's hedging program.

The notional amounts associated with these financial hedges represented approximately 264.8 Bcf of the Company's produced Marcellus gas sales volumes for the year ended December 31, 2019 at an average gain of $0.18 per Mcf.

For the year ended December 31, 2018 , these financial hedges represented approximately 206.7 Bcf at an average loss of $0.20 per Mcf.

Total operating costs and expenses for the Marcellus segment were $748 million for the year ended December 31, 2019 compared to $609 million for the year ended December 31, 2018 .

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

• Marcellus lease operating expenses were $ 33 million for the year ended December 31, 2019 compared to $41 million for the year ended December 31, 2018 .

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

The decrease in unit costs was driven by the decrease in total dollars, along with the 28.3% increase in total Marcellus sales volumes.

• Marcellus production, ad valorem, and other fees were $ 15 million for the year ended December 31, 2019 compared to $18 million for the year ended December 31, 2018 .

The decrease in total dollars was primarily related to a decrease in CNX's severance tax liability due to the production mix by state and lower natural gas prices.

The decrease in unit costs was driven by the decrease d total dollars, along with the 28.3% increase in total Marcellus sales volumes.

• Marcellus transportation, gathering and compression costs were $ 444 million for the year ended December 31, 2019 compared to $320 million for the year ended December 31, 2018 .

The $124 million increase in total dollars was primarily related to an increase in both CNX Midstream fees as well as an increase in utilized firm transportation expense.

The increase in firm transportation total dollars was related to new contracts undertaken in 2019 that give CNX the ability to move and sell natural gas outside of the Appalachian basin.

The increase in CNXM fees was due to annual rate escalation as well as additional compression.

These increases were offset by lower processing costs due to a drier production mix.

The increase in unit costs was driven by the increase d total dollars described above.

• Depreciation, depletion and amortization costs attributable to the Marcellus segment were $ 256 million for the year ended December 31, 2019 compared to $230 million for the year ended December 31, 2018 .

These amounts included depletion on a unit of production basis of $0.68 per Mcfe and $0.79 per Mcfe, respectively.

The decrease in units of production depreciation, depletion and amortization rate is the result of positive reserve revisions within the Company's core development area in the current year.

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

UTICA SEGMENT

The Utica segment had earnings before income tax of $88 million for the year ended December 31, 2019 compared to earnings before income tax of $194 million for the year ended December 31, 2018 .

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,

Utica Gas Sales Volumes (Bcf)

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 Sales Volumes (Bcfe)*

Condensate Sales Volumes (Bcfe)*

Total Utica Sales Volumes (Bcfe)*

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) %

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

Average Sales Price - Oil (per Mcfe)*

Average Sales Price - Condensate (per Mcfe)*

Total Average Utica Sales Price (per Mcfe)

Average Utica Lease Operating Expenses (per Mcfe)

Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)

Average Utica Transportation, Gathering and Compression Costs (per Mcfe)

Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)

Total Average Utica Costs (per Mcfe)

Average Margin for Utica (per Mcfe)

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

The Utica segment had natural gas, NGLs and oil revenue of $264 million for the year ended December 31, 2019 compared to $446 million for the year ended December 31, 2018 .

The $182 million decrease was due to the 26.0% decrease in total Utica sales volumes and a 17.7% decrease in the average sales price for natural gas.

The decrease in total Utica sales volumes was primarily due to the sale of substantially all of CNX's Ohio Utica JV assets in the third quarter of 2018 (See Note 6 - 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 Utica wells.

The decrease in total average Utica sales price was primarily due to a $0.50 per Mcf decrease in average gas sales price.

Additionally, there was a $0.07 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 Utica production.

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 83.3 Bcf of the Company's produced Utica gas sales volumes for the year ended December 31, 2019 at an average gain of $0.18 per Mcf.

For the year ended December 31, 2018 , these financial hedges represented approximately 101.6 Bcf at an average loss of $0.20 per Mcf.

Total operating costs and expenses for the Utica segment were $191 million for the year ended December 31, 2019 compared to $232 million for the year ended December 31, 2018 .

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

• Utica lease operating expenses were $16 million for the year ended December 31, 2019 , compared to $30 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 lower production volumes, an increase in reuse of produced water in well completions and a reduction in well operating costs due to the overall decrease in Utica volumes described above.

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.

• Utica transportation, gathering and compression costs were $33 million for the year ended December 31, 2019 compared to $52 million for the year ended December 31, 2018 .

The $19 million decrease in total dollars and $0.05 per Mcfe decrease in unit costs were both due to the overall decrease in Utica volumes as well as the shift to lower cost dry Utica production.

• Depreciation, depletion and amortization costs attributable to the Utica segment were $136 million for the year ended December 31, 2019 compared to $143 million for the year ended December 31, 2018 .

• 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 increase in the units of production depreciation, depletion and amortization rate was due to negative reserve revisions, an increase in capital expenditures and a higher depreciation, depletion and amortization rate on deep dry Utica wells compared to the lower capital cost Utica wells which were part of the Ohio JV asset sale in 2018.

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

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For the Years Ended December 31,

2019 2018 Variance Percent

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

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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 decrease d $0.30 per Mcf due to a $0.57 per Mcf decrease in average gas sales price, offset in part by a $0.28 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.

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

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.

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.

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

OTHER GAS SEGMENT

The Other Gas segment had a loss before income tax of $497 million for the year ended December 31, 2019 compared to a loss before income tax of $253 million for the year ended December 31, 2018 .

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 Sales Volumes (Bcfe)*

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

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

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments.

This segment also includes unrealized gain or loss on commodity derivative instruments, purchased gas activity, exploration and production related other costs, impairment of exploration and production properties, impairment of unproved properties and expirations, and other operational activity not assigned to a specific segment.

*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, condensate and natural gas prices.

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

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

Unrealized Gain or Loss on Commodity Derivative Instruments

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

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

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.

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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 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 %

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Other Operating Income

Other operating income was $14 million for the year ended December 31, 2019 compared to $27 million for the year ended December 31, 2018 .

The $13 million decrease was due to the following items:

For the Years Ended December 31,

(in millions)

(in millions) 2019 2018 Variance Percent Change

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

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

Gathering Income

Excess Firm Transportation Income

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

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

• 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

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These unproved

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

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.

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

Exploration and production related other costs were $44 million for the year ended December 31, 2019 compared to $12 million for the year ended December 31, 2018 .

The $32 million increase was due to the following items:

For the Years Ended December 31,

(in millions)

(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 %

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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 current period related to the Utica segment.

Other Operating Expenses

Other operating expense was $ 79 million for the year ended December 31, 2019 compared to $72 million for the year ended December 31, 2018 .

The $7 million increase was due to the following items:

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

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.

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 %

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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 current period to transport the Company's flowing production.

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.

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The revenue received when this capacity is released (sold) is included in Gathering Income in Total Other Operating Income above.

There were no unutilized fees related to the Midstream Division for 2018 or 2019.

• 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 decrease d $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.

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.

Selling, General and Administrative

SG&A costs represent direct charges for the management and operation of CNX's E&P division.

SG&A costs were $ 124 million for the year ended December 31, 2019 compared to $112 million for the year ended December 31, 2018 .

Refer to the discussion of total Company SG&A costs contained in the section "Net (Loss) Income Attributable to CNX Resources Shareholders" within this Item 7 of this Form 10-K for a detailed cost explanation.

Other Expense (Income)

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.

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

Interest expense of $ 121 million was recognized in the year ended December 31, 2019 compared to $122 million in the year ended December 31, 2018 .

The $ 1 million decrease was primarily due to 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 .

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.

These decreases were partially offset by a completed private offering of $500 million of 7.25% senior notes due March 2027 during the year ended December 31, 2019 , as well as additional borrowings on the CNX credit facility.

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

TOTAL MIDSTREAM DIVISION ANALYSIS for the year ended December 31, 2019 compared to the period January 3, 2018 through December 31, 2018:

CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets of CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third-parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia.

Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM.

On January 3, 2018, CNX completed the Midstream Acquisition (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

CNX Gathering holds all of the interests in CNX Midstream GP LLC, which holds both the general partner and limited partner interests in CNXM.

As a result of this transaction, 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.

(in millions)

For the Year Ended December 31, 2019

For the period January 3, 2018 through December 31, 2018

Midstream Revenue - Related Party

Midstream Revenue - Third Party

Total Revenue

Transportation, Gathering and Compression

Depreciation, Depletion and Amortization

Selling, General and Administrative Costs

Total Operating Costs and Expenses

Other Expense

Loss (Gain) on Asset Sales and Abandonments, net

Interest Expense

Total Midstream Division Costs

Earnings from Continuing Operations Before Income Tax

Midstream Revenue

Midstream revenue consists of revenue related to volumes gathered on behalf of CNX and other third-party natural gas producers.

CNXM charges a higher fee for natural gas that is shipped on its wet system compared to gas shipped through its dry system.

CNXM revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon delivery point and may change dynamically depending on commodity prices at time of shipment.

Total midstream revenue increased $49 million primarily due to a 21.3% increase in the average rate for related party volumes as well as a14.2% increase in gathered volumes of both dry and wet gas in the period-to-period comparison.

The table below summarizes volumes gathered by gas type:

For the Year Ended December 31, 2019

For the period January 3, 2018 through December 31, 2018

Dry Gas (BBtu/d) (*)

Wet Gas (BBtu/d) (*)

Other (BBtu/d) (*)(**)

Total Gathered Volumes

(*) Classification as dry or wet is based upon the shipping destination of the related volumes.

Because CNXM's customers have the option to ship a portion of their natural gas to destinations associated with either our wet system or our dry system, due to any number of factors, volumes may be classified as “wet” in one period and as “dry” in the comparative period.

(**) Includes condensate handling and third-party volumes under high-pressure short-haul agreements.

Transportation, Gathering and Compression

Transportation, Gathering and Compression costs were $ 47 million for both the year ended December 31, 2019 and the period January 3, 2018 through December 31, 2018 and are comprised of items directly related to the cost of gathering natural gas at the wellhead and transporting it to interstate pipelines or other local sales points.

These costs include items such as electrically-powered compression, compressor rental, repairs and maintenance, supplies, treating and contract services.

Selling, General and Administrative Expense

SG&A expense is comprised of direct charges for the management and operation of CNXM assets.

SG&A costs were $ 20 million for the year ended December 31, 2019 compared to $ 23 million for the period January 3, 2018 through December 31, 2018 .

Refer to the discussion of total Company SG&A costs contained in the section "Net (Loss) Income Attributable to CNX Resources Shareholders" above for a detailed cost explanation.

Depreciation, Depletion and Amortization Expense

Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25 years to 40 years.

Loss (Gain) on Asset Sales and Abandonments, net

During the year ended December 31, 2019 , CNXM abandoned the construction of a compressor station that was designed to support additional production within certain areas of what is referred to as their "Anchor Systems," incurring a loss of $ 7 million that is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.

CNXM continues to evaluate projects as CNX's and third-party customer development plans change in order to optimize system design and to actively manage capital investments.

During the period January 3, 2018 through December 31, 2018 , CNXM sold property and equipment to an unrelated third-party for $ 6 million in cash proceeds, resulting in a gain of $ 2 million .

Interest Expense

Interest expense is comprised of interest on the outstanding balance under CNXM's senior notes due 2026 and its revolving credit facility.

Interest expense was $ 30 million for the year ended December 31, 2019 compared to $ 24 million for the period January 3, 2018 through December 31, 2018 .

The increase in the period-to-period comparison was due to additional borrowings on the revolving credit facility.

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.

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.

Critical Accounting Policies

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Actual results could differ from those estimates upon subsequent resolution of identified matters.

CNX has no uncertain tax liabilities at December 31, 2019 .

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.

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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In making the determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit.

To the extent that an uncertain tax position or

valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.

To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.

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

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For the year ended December 31, 2020, an impairment of $62 million was included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income.

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.

In February 2017, the Company approved a plan to sell subsidiaries Knox Energy LLC and Coalfield Pipeline Company (collectively, Knox).

As part of the required evaluation under the held for sale guidance, Knox's book value was evaluated, and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold.

The resulting impairment of $138 million was included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income.

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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CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis.

Indicators of potential impairment include, but are not limited to, changes brought about by economic factors, commodity price outlooks, our geologists’

evaluation of the property, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, potential shifts in business strategy employed by management and historical experience.

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

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CNX determined the fair value based on estimated future cash flows and earnings before deducting net interest expense (interest expense less interest income) and income taxes (EBITDA - a non-GAAP financial measure) and also included estimates for capital expenditures, discounted to present value using a risk-adjusted rate, which management feels reflects the overall level of inherent risk of the reporting unit.

Cash flow projections were derived from board approved budgeted amounts, a five-year operating forecast and an estimate of future cash flows.

Cash flow projections were derived from board approved budgeted amounts, a seven-year operating forecast and an estimate of future cash flows.

Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur.

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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.

The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results.

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

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

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

In connection with our annual assessment of goodwill in the fourth quarter of 2019, we 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, we concluded that the estimated fair value exceeded carrying value, and accordingly no adjustment to goodwill was necessary.

However, the margin by which the fair value of the Midstream reporting unit exceeded its carrying value was less than 10%.

The fair value was estimated using an equal weighting of the income approach and guideline public company market approach.

In our income approach analyses, CNX used a production forecast that included, amount other things, estimates of gathered volumes based upon CNX's proved developed and proved undeveloped reserves, as defined by the SEC, as well as forecasted production declines for third-party customers.

Revenue contraction was applied to the terminal period.

Had CNX used a discount rate that was 160 basis points higher or a terminal growth rate that was 520 basis points lower than those assumed under the income approach, the fair value of this reporting unit would have continued to exceed its carrying amount.

Had we more heavily weighed the market approach in estimating the fair value of this reporting unit, the excess fair value over the carrying amount would have increased.

As a result of the small margin by which the Midstream reporting unit’s fair value exceeded its carrying value, the reporting unit is susceptible to impairment risk from further adverse macroeconomic conditions or other adverse factors such as future gathering volumes being less than those currently estimated.

Any such adverse changes in the future could reduce the underlying cash flows used to estimate fair values and could result in a decline in fair value that could trigger future impairment charges relating to the Midstream reporting unit.

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

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

Any additional adverse changes in the future could reduce the underlying cash flows used to estimate fair values and could result in a decline in fair value that could trigger future impairment charges.

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

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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).

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.

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.

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.

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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 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;

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;

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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

CNX accounted for its Convertible Senior Notes due May 2026 as separate liability and equity components.

The carrying amount of the liability component of the instrument was computed by estimating the fair value of a similar liability without the conversion option.

The amount of the equity component was then calculated by deducting the fair value of the liability component from the principal amount of the instrument.

The difference between the principal amount and the liability component represents a debt discount that is amortized to interest expense over the respective term of the Convertible Notes using the effective interest rate method.

The equity component is not remeasured as long as it continues to meet the conditions for equity classification.

Additionally, a detailed analysis of the terms of the convertible senior notes transactions was required to determine existence of any derivatives that may require separate mark-to-market accounting under applicable accounting guidance.

The Company believes that the accounting estimates related to the Convertible Notes are “critical accounting estimates” because of the judgment required when determining the balance sheet classification of the elements of the Convertible Notes as well as the existence of any derivatives that may require separate presentation under the applicable accounting guidance.

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 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.

CNX 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 and to provide required letters of credit for the next 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, some of which are beyond CNX’s control.

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 next fiscal year.

From time to time, CNX is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business.

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CNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

Uncertainty in the financial markets brings additional potential risks to CNX.

These risks include declines in the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures.

Financial market disruptions may impact the Company's collection of trade receivables.

As a result, CNX regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments and security.

CNX believes that its current group of customers is financially sound and represents no abnormal business risk.

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 has also entered into various natural gas swap and option transactions, which exist parallel to the underlying physical transactions.

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.

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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 Provided by (Used in) Financing Activities

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 $327 million increase in impairment of exploration and production properties, a $119 million increase in impairment of unproved properties and expirations, a $19 million decrease in impairment of other intangible assets, a $267 million net change in commodity derivative instruments, a $46 million decrease in the loss on debt extinguishment, $624 million decrease in gain on previously held equity interest, and a $266 million change in deferred income taxes.

• 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 increased $76 million in the period-to-period comparison primarily due to increased expenditures in midstream and water operations to support development within Southwest Pennsylvania.

In January 2018, CNX acquired Noble Energy's interest in CNX Gathering for a net payment of $299 million.

See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Proceeds from the sale of assets decreased $467 million primarily due to the 2018 sale of substantially all of the Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble counties along with the 2018 sale of substantially all of CNX's shallow oil and gas assets and certain CBM assets in Pennsylvania and West Virginia.

This was partially offset by various 2019 sales of surface land and oil and gas rights.

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

In the year ended December 31, 2019, there were net proceeds of $49 million of borrowings on the CNX credit facility compared to net proceeds of $612 million in the year ended December 31, 2018.

In the year ended December 31, 2019, CNX paid $406 million to repurchase $400 million of the 5.875% senior notes due in April 2022.

In the year ended December 31, 2018, CNX paid $955 million to repurchase all of the remaining 8.00% senior notes due April 2023 and $411 million of the 5.875% senior notes due in April 2022.

• 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.

During the year ended December 31, 2019, CNX received proceeds of $500 million from the issuance of senior notes due in 2027.

During the year ended December 31, 2018, CNX received proceeds of $394 million from the issuance of CNXM's senior notes due in 2026.

• 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 years ended December 31, 2019 and 2018, CNX repurchased $117 million and $382 million, respectively, of its common stock on the open market.

In the year ended December 31, 2019, there were net proceeds of $228 million of borrowings on the CNXM credit facility compared to net payments of $66 million in the year ended December 31, 2018.

• 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 year ended December 31, 2019, there were $11 million in debt issuance and financing fees compared to $21 million in the year ended December 31, 2018.

• 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

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_________________________

Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.

Other long-term liabilities include royalties and other long-term liability costs.

The significant obligation table 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, 2019 , CNX had total long-term debt of $2,763 million , excluding unamortized debt issuance costs.

(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 $894 million of 5.875% Senior Notes due in April 2022 plus $1 million of unamortized bond premium.

Interest on the notes is payable April 15 and October 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.

An aggregate principal amount of $661 million in outstanding borrowings under the CNX credit facility.

An aggregate principal amount of $500 million of 7.25% Senior Notes due in March 2027.

• 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.

An aggregate principal amount of $400 million of 6.50% Senior Notes due in March 2026 issued by CNXM, less $5 million of unamortized bond discount.

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.

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CNX is not a guarantor of these notes.

An aggregate principal amount of $312 million in outstanding borrowings under the CNXM revolver.

CNX is not a guarantor of CNXM's revolving credit facility.

• 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

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

On September 28, 2020, the Merger of CNXM was completed (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

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

The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance can be given that CNX will pay dividends in the future.

CNX's Board of Directors determines whether dividends will be paid quarterly.

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

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

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.

The Company's Credit Facility limits CNX's 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 15% of the aggregate commitments.

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 15% of the aggregate commitments.

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 5.875% Senior Notes due in April 2022 and the 7.25% Senior Notes due in March 2027 limit dividends to $0.50 per share annually unless several conditions are met.

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.

On January 23, 2020, the Board of Directors of CNX Midstream GP LLC, the general partner of CNX Midstream Partners LP, announced the declaration of a cash distribution of $0.4143 per unit with respect to the fourth quarter of 2019.

The distribution will be made on February 13, 2020 to unitholders of record as of the close of business on February 5, 2020.

The distribution, which equates to an annual rate of $1.6572 per unit, represents an increase of 3.6% over the prior quarter, and an increase of 15% over the distribution paid with respect to the fourth quarter of 2018.

Off-Balance Sheet Transactions

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Recent Accounting Pronouncements

In December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12 - Income Taxes - Simplifying the Accounting for Income Taxes (Topic 740), which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740.

This ASU removes the following exceptions:

(1) exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items;

(2) exception to the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment;

(3) exception to the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary;

and (4) exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year.

The amendments in this ASU also improve consistency and simplify other areas of Topic 740 by clarifying and amending existing guidance.

The amendments in this ASU will be applied using different approaches depending on what the specific amendment relates to and, for public entities, are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020.

Early adoption is permitted.

The adoption of this guidance is not expected to have a material impact on the Company's financial statements.

In November 2019, the FASB issued ASU 2019-11 - Financial Instruments - Credit Losses (Topic 326), which clarifies and addresses specific issues about certain aspects of the amendments in ASU 2016-13.

In May 2019, the FASB issued ASU 2019-05 - Financial Instruments - Credit Losses (Topic 326), which provides optional targeted transition relief to entities adopting ASU 2016-13.

ASU 2016-13 replaces the incurred loss impairment methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates.

The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount.

ASU 2019-05 provides the option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost basis.

For those entities, the targeted transition relief will increase comparability of financial statement information by providing an option to align

measurement methodologies for similar financial assets.

The amendments in the ASU will be applied using the modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and interim periods within those annual periods.

Early adoption is permitted.

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.

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