Additionally, the 32,242,975 shares underlying the Convertible Notes are not considered in the calculation of diluted net loss per share for the three and nine months ended September 30, 2020 as these Convertible Notes were not convertible as of September 30, 2020. The Company will settle conversions by paying or delivering, as applicable, cash, shares of its common stock or a combination of cash and shares of its common stock, at the Company’s election, and therefore will use the treasury stock method for calculating any potential dilutive effect of the conversion spread on diluted net income per share, if applicable.

The table below sets forth the share-based awards that have been exercised or released:


	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2020	2019	2020	2019
Options	21,864	6,953	261,703	27,794
Restricted Stock Units	21,186	28,769	525,226	1,002,003
Performance Share Units	0	0	274,716	342,882
	43,050	35,722	1,061,645	1,372,679

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2019 2018 2019 2018
Options 6,953
18,546
27,794
245,847
Restricted Stock Units 28,769
184,176
1,002,003
362,573
Performance Share Units —
192,926
342,882
550,523
35,722
395,648
1,372,679
1,158,943

Pursuant to the terms of the change in control severance agreements of certain CNX employees and CNX officers, outstanding equity awards held by such employees and officers vest upon a stockholder (or stockholder group) becoming the beneficial owner of more than 25% of the Company's outstanding common stock. During the nine months ended September 30, 2019, Southeastern Asset Management, Inc. and its affiliates ("SEAM") acquired shares of CNX's common stock in the open market which resulted in SEAM's aggregate share ownership exceeding more ~~than~~the 25% of CNX's common stock outstanding. This transaction, as such, constituted a change in control event under the severance agreements, resulting in the accelerated vesting of 473,126 restricted stock units and 903,100 performance share units held by the aforementioned employees and officers that were issued prior to 2019. Those affected employees and officers each consented to waive the change in control vesting provision included in the change in control severance agreements with respect to their ~~2019~~ restricted stock unit and performance share unit ~~awards.~~awards that were issued during 2019. The accelerated vesting resulted in $19,654 of additional long-term equity-based compensation expense for the nine months ended September 30, 2019, and is included in Selling, General and Administrative Costs in the Consolidated Statements of Income. The performance share unit awards that vested continue to be subject to the attainment of performance goals as determined by the Compensation Committee of CNX's Board of Directors after the end of the applicable performance period.

The computations for basic and diluted (loss) earnings per share are as follows:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
Net (Loss) Income	$	(188,793)	$	143,960	$	(624,502)	$	272,004
Less: Net Income Attributable to Non-Controlling Interest	15,905		28,422		55,031		81,325


Net (Loss) Income Attributable to CNX Resources Shareholders	$	(204,698)	$	115,538	$	(679,533)	$	190,679

Weighted-Average Shares of Common Stock Outstanding	198,727,472		187,448,749		191,015,680		188,012,044
Effect of Diluted Shares*	0		982,210		0		1,548,899
Weighted-Average Diluted Shares of Common Stock Outstanding	198,727,472		188,430,959		191,015,680		189,560,943

(Loss) Earnings per Share:


Basic	$	(1.03)	$	0.62	$	(3.56)	$	1.01



Diluted	$	(1.03)	$	0.61	$	(3.56)	$	1.01

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2019 2018 2019 2018
Net Income $ 143,960
$ 146,756
$ 272,004
$ 753,696
Less: Net Income Attributable to Non-Controlling Interest 28,422
21,727
81,325
59,090
Net Income Attributable to CNX Resources Shareholders $ 115,538
$ 125,029
$ 190,679
$ 694,606

Weighted-average Shares of Common Stock Outstanding 187,448,749
210,238,509
188,012,044
216,010,561
Effect of Diluted Shares 982,210
2,469,573
1,548,899
2,288,301
Weighted-average Diluted Shares of Common Stock Outstanding 188,430,959
212,708,082
189,560,943
218,298,862

Earnings per Share:
Basic $ 0.62
$ 0.59
$ 1.01
$ 3.22
Diluted $ 0.61
$ 0.59
$ 1.01
$ 3.18
*During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive.

NOTE 3—~~CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS:~~

~~Changes in Accumulated Other Comprehensive Loss related to pension obligations, net of tax, were as follows:~~

Amount
Balance at December 31, 2018 $ (7,904 )
Amounts Reclassified from Accumulated Other Comprehensive Loss, net of tax 126
Balance at September 30, 2019 $ (7,778 )

~~The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2019 2018 2019 2018
Actuarially Determined Long-Term Liability Adjustments
Amortization of Prior Service Costs $ (4 ) $ (6 ) $ (13 ) $ (186 )
Recognized Net Actuarial Loss 60
41
183
749
Total 56
35
170
563
Less: Tax Benefit 15
13
44
202
Net of Tax $ 41
$ 22
$ 126
$ 361

~~NOTE 4—~~REVENUE FROM CONTRACTS WITH CUSTOMERS:

Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to exclude all taxes from the measurement of transaction price.

For natural gas, ~~NGLs~~NGL and oil, and purchased gas revenue, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company’s efforts to satisfy the performance obligations. A portion of the contracts contain fixed consideration (i.e. fixed price contracts or contracts with a fixed differential to NYMEX or index prices). The fixed consideration is allocated to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price. Revenue associated with natural gas, ~~NGLs~~NGL and oil as presented on the accompanying Consolidated Statements of Income represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling natural gas, ~~NGLs~~NGL and oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

~~Midstream revenue consists~~Included in Other Revenue and Operating Income in the Consolidated Statements of Income and in the below table, are revenues generated from natural gas gathering ~~activities.~~services provided to third-parties. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric based fees are based on actual volumes gathered. The Company generally considers the interruptible gathering of each unit (MMBtu) of natural gas as a separate performance obligation. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered.

Disaggregation of Revenue

The following table is a disaggregation of revenue by major source:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
Revenue from Contracts with Customers
Natural Gas Revenue	$	163,054	$	245,815	$	561,162	$	966,574
NGL Revenue	15,053		18,305		40,691		72,095
Oil/Condensate Revenue	4,106		931		7,630		5,193
Total Natural Gas, NGL and Oil Revenue	182,213		265,051		609,483		1,043,862

Purchased Gas Revenue	31,541		29,192		78,324		64,181


Other Sources of Revenue and Other Operating Income
(Loss) Gain on Commodity Derivative Instruments	(168,834)		213,913		(116,995)		240,118
Other Revenue and Operating Income	21,155		21,841		60,463		65,299
Total Revenue and Other Operating Income	$	66,075	$	529,997	$	631,275	$	1,413,460

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2019 2018 2019 2018
Revenue from Contracts with Customers
Natural Gas Revenue $ 245,815
$ 293,864
$ 966,574
$ 930,505
NGLs Revenue 18,305
46,663
72,095
137,104
Condensate Revenue 839
3,426
4,846
14,925
Oil Revenue 92
759
347
2,317
Total Natural Gas, NGLs and Oil Revenue 265,051
344,712
1,043,862
1,084,851

Purchased Gas Revenue 29,192
10,560
64,181
38,546
Midstream Revenue 18,525
19,946
55,863
69,684

Other Sources of Revenue and Other Operating Income
Gain on Commodity Derivative Instruments 213,913
18,005
240,118
78,752
Other Operating Income 3,316
3,903
9,436

23,146
Total Revenue and Other Operating Income $ 529,997
$ 397,126
$ 1,413,460
$ 1,294,979

The disaggregated revenue corresponds with the Company’s segment reporting found in Note 1714 - Segment Information.

Contract Balances

CNX invoices its customers once a performance obligation has been satisfied, at which point payment is unconditional. Accordingly, CNX's contracts with customers do not give rise to contract assets or liabilities under ~~Accounting Standards Codification (ASC)~~ASC 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer. The opening and closing balances of the Company’s receivables related to contracts with customers were ~~$252,424~~$133,480 and ~~$96,997,~~$75,929, respectively, as of September 30, ~~2019.~~2020.

Transaction Price Allocated to Remaining Performance Obligations

ASC 606 requires that the Company disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement, including when variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a series.

A significant portion of CNX's natural gas, ~~NGLs~~NGL and oil and purchased gas revenue is short-term in nature with a contract term of one year or less. For those contracts, CNX has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For revenue associated with contract terms greater than one year, a significant portion of the consideration in those contracts is variable in nature and the Company allocates the variable consideration in its contract entirely to each specific performance obligation to which it relates. Therefore, any remaining variable consideration in the transaction price is allocated entirely to wholly unsatisfied performance obligations. As such, the Company has not disclosed the value of unsatisfied performance obligations pursuant to the practical expedient.

For revenue associated with contract terms greater than one year with a fixed price component, the aggregate amount of the transaction price allocated to remaining performance obligations was ~~$155,567~~$127,887 as of September 30, ~~2019.~~2020. The Company expects to recognize net revenue of ~~$43,538~~$50,125 in the next 12 months and ~~$47,076~~$41,379 over the following 12 months, with the remainder recognized thereafter.

For revenue associated with ~~our~~CNX's midstream contracts, which also have terms greater than one year, the interruptible gathering of each unit of natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior-Period Performance Obligations

CNX records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL revenue may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. CNX records the differences between the estimate and the actual ~~amount~~amounts received in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and the related accruals, and any identified differences between its revenue estimates and the actual revenue received historically have not been significant. For the three and nine months ended September 30, ~~2019~~2020 and ~~2018,~~2019, revenue recognized in the current reporting period related to performance obligations satisfied in a prior reporting period was not material.

NOTE ~~5—ACQUISITIONS AND DISPOSITIONS:~~4—INCOME TAXES:

~~On August 31, 2018,~~The effective tax rates for the three and nine months ended September 30, 2020 were 24.5% and 28.0%, respectively. The effective tax rates for the three and nine months ended September 30, 2019 were 25.4% and 22.3%, respectively. The effective tax rates for the three and nine months ended September 30, 2020 and 2019 differ from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state taxes.

Effective September 28, 2020, CNXM merged with a wholly-owned subsidiary of CNX ~~closed on~~with CNXM surviving as a wholly-owned subsidiary (See Note 13 - Acquisitions and Dispositions for more information). The tax effects of the ~~sale~~Merger were reported as an adjustment to deferred income taxes and capital in excess of substantially all of its Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties, which included approximately 26,000 net undeveloped acres. The net cash proceeds of $381,214 are included in Proceeds from Asset Sales in the Consolidated Statements of Cash Flows and the net gain on the transaction of $130,849 is included in the Gain on Asset Sales and Abandonments in the Consolidated Statements of Income.par value.

On~~May 2, 2018, CNX closed on an Asset Exchange Agreement~~ March 27, 2020, the United States enacted the Coronavirus Aid, Relief, and Economic Security Act (the ~~“AEA”~~"Act") ~~with HG Energy II Appalachia, LLC (“HG Energy”), pursuant to~~ which, among other things, ~~HG Energy (i) paid~~removed the 80% taxable income limitation for utilization of net operating losses generated in tax years 2018 through 2020, allowing for 5-year net operating loss carrybacks, increased the adjusted taxable income limitation for the disallowance of interest expense from 30% to ~~CNX approximately $7,000~~50%, and ~~(ii) assigned to CNX certain undeveloped Marcellus and Utica acreage in Southwest Pennsylvania, in exchange~~provided for CNX (x) assigning its interest in certain non-core midstream assets and surface acreage to HG Energy and (y) releasing certain HG Energy oil and gas acreage from dedication under a gathering agreement that is partially held, indirectly, by CNX.~~In connection with the transaction, CNX also agreed to certain transactions with CNXM, including the amendment~~refunds of the existing gas gathering agreement between CNX and CNXM to increase the existing well commitment by an additional 40 wells. The net gain on the sale was $286 and is included in the Gain on Asset Sales and Abandonments line of the Consolidated Statements of Income.

any remaining alternative minimum tax (“AMT”) credits. As a result of the ~~AEA,~~ Act, the Company recorded AMT refunds of $102,482 in Recoverable Income Taxes in the Consolidated Balance Sheets in anticipation of the AMT refund being received in 2020. The Company received the AMT tax refund in the third quarter of 2020.The impact of other tax implications of the Act on the financial statements and related disclosures are immaterial.

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. The Company early adopted ASU 2019-12 as of January 1, 2020.

The total amount of uncertain tax positions at September 30, 2020 and December 31, 2019 was $33,243 and $31,516, respectively. If these uncertain tax positions were recognized, approximately $33,243 would affect CNX's effective tax rate at September 30, 2020 and December 31, 2019. The increase in the unrecognized tax benefits during the nine months ended September 30, 2020 was due to additional tax credits claimed on the 2019 federal income tax return.

CNX recognizes accrued interest and penalties related to uncertain tax positions in interest expense and income tax expense, respectively. As of September 30, 2020 and December 31, 2019, CNX had 0 accrued liabilities for interest and penalties related to uncertain tax positions.

CNX and its subsidiaries file federal income tax returns with the United States and tax returns within various states. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2016. The Internal Revenue Service and the Joint Committee on Taxation concluded its review of tax years 2016 through 2017 during the third quarter of 2020.

NOTE 5—PROPERTY, PLANT AND EQUIPMENT:


	September 30, 2020		December 31, 2019
Intangible Drilling Cost	$	4,900,667	$	4,688,497
Gas Gathering Equipment	2,505,267		2,463,866
Proved Gas Properties	1,214,416		1,208,046
Gas Wells and Related Equipment	1,102,366		1,042,000
Unproved Gas Properties	765,008		755,590
Surface Land and Other Equipment	222,732		226,285
Other	194,381		187,722
Total Property, Plant and Equipment	10,904,837		10,572,006
Less: Accumulated Depreciation, Depletion and Amortization	3,841,699		3,435,431

Total Property, Plant and Equipment - Net	$	7,063,138	$	7,136,575

Impairment of Proved Property

CNX performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, tests require that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using significant assumptions including projected revenues, future commodity prices, and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions.

During the nine months ended September 30, 2020, CNX recognized certain indicators of impairment specific to our Southwest Pennsylvania (SWPA) coalbed methane (CBM) asset group and determined that the carrying value of ~~a portion~~that asset group was not recoverable. The fair value of the ~~customer relationship intangible assets~~asset group was estimated by using level 3 inputs which consisted of discounting the estimated future cash flows using discount rates and other assumptions that ~~were acquired~~market participants would use in ~~connection with the Midstream Acquisition discussed below (see also Note 8 - Goodwill and Other Intangible Assets) exceeded~~ their estimates of fair ~~value, and recognized~~value. As a result, an impairment of ~~approximately $18,650 which~~$61,849 was recognized and is included in ~~the~~ Impairment of ~~Other Intangible Assets line 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.

On March 30, 2018, CNX Gas completed the sale of substantially all of its shallow oil and gas assets and certain Coalbed Methane (CBM) assets in Pennsylvania and West Virginia for $89,296 in cash consideration.

NOTE 6—GOODWILL AND OTHER INTANGIBLE ASSETS:

In connection with the sale, the buyer assumed approximately $196,514 of asset retirement obligations. The net gain on the sale was $4,432 and is included in Gain on Asset Sales and Abandonments in the Consolidated Statements of Income for the nine months ended September 30, 2018.

On December ~~14,~~ 2017, CNX Gas entered into a purchase agreement with Noble Energy, pursuant to which CNX Gas acquired Noble’s 50% membership interest in ~~CONE~~CNX Gathering ~~LLC ("CNX Gathering"~~(then named "CONE Gathering LLC"), for a cash purchase price of $305,000 ~~and the mutual release of all outstanding claims~~ (the "Midstream Acquisition"). CNX Gathering owns a 100% membership interest in CONE Midstream GP LLC (the "general partner"), which is the general partner of CONE Midstream Partners LP ("CNXM" or the "Partnership"), which is a publicly traded master limited partnership formed in May 2014 by CNX Gas and Noble. In conjunction with the Midstream Acquisition, which closed on January 3, 2018, the general partner, the Partnership and CONE Gathering LLC changed their names to CNX Midstream GP LLC, CNX Midstream Partners LP, and CNX Gathering LLC, respectively.

Prior to the Midstream Acquisition, the Company accounted for its 50% interest in CNX Gathering as an equity method investment as the Company had the ability to exercise significant influence, but not control, over the operating and financial policies of the midstream operations. In conjunction with the Midstream Acquisition, the Company obtained a controlling interest in CNX Gathering and ~~through CNX Gathering's ownership of the general partner,~~ control over the Partnership. Accordingly, the Midstream Acquisition ~~has been~~was accounted for as a business combination using the acquisition method of accounting pursuant to ASC Topic 805, Business Combinations,, or ASC 805. ASC 805 requires that, in circumstances where a business combination is achieved in stages (or step acquisition), previously held equity interests are remeasured at fair ~~value and any difference between the fair value and the carrying value of the equity interest held be recognized as a gain or loss on the statement of income.~~

value. The fair value assigned to the previously held equity interest in CNX Gathering and CNXM ~~for purposes of calculating the gain or loss~~ was $799,033 and was determined using the income approach, based on a discounted cash flow methodology. ~~The~~

resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $623,663 is included in Gain on Previously Held Equity Interest in the Consolidated Statements of Income.

The fair value of the previously held equity interests was based on inputs that are not observable in the market and therefore represent Level 3 inputs (See Note 15 - Fair Value of Financial Instruments). The fair value was measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation included estimates of: (i) gathering volumes; (ii) future operating costs; and (iii) a market-based weighted average cost of capital. These inputs required significant judgments and estimates by management.

The fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, were estimated using the cost approach. Significant unobservable inputs in the valuation include management's assumptions about the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence associated with the acquired assets. As a result, the fair value estimates of the midstream facilities and equipment represents a Level 3 fair value measurement.

As part of the ~~purchase price~~ allocation ~~the Company identified intangible assets for customer relationships with third-party customers. The fair value~~ of the identified intangible assets was determined using the income approach, which requires a forecast of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant unobservable inputs in the valuation include future revenue estimates, future cost assumptions, and estimated customer retention rates. As a result, the fair value estimate of the identified intangible assets represents a Level 3 fair value measurement.

The noncontrolling interest in the acquired business is comprised of the limited partner units in CNXM, which were not acquired by the Company. The CNXM limited partner units are actively traded on the New York Stock Exchange and were valued based on observable market prices as of the transaction date and therefore represent a Level 1 fair value measurement.

~~Allocation of Purchase Price (Midstream Acquisition)~~

~~The following table summarizes the~~ purchase price and ~~the amounts of identified assets acquired and liabilities assumed based on the fair value as of January 3, 2018,~~in connection with ~~any excess of the purchase price over~~ the fair value of ~~the identified net assets acquired recorded as goodwill. The purchase price allocation was finalized as of December 31, 2018.~~

~~Fair Value of Consideration Transferred:~~

Amount
Cash Consideration $ 305,000
CNX Gathering Cash on Hand at January 3, 2018 Distributed to Noble 2,620
Fair Value of Previously Held Equity Interest 799,033
Total Estimated Fair Value of Consideration Transferred $ 1,106,653

~~The following is a summary of the fair values of the net assets acquired:~~

Fair Value of Assets Acquired: Amount
Cash and Cash Equivalents $ 8,348
Accounts and Notes Receivable 21,199
Prepaid Expense 2,006
Other Current Assets 163
Property, Plant and Equipment, Net 1,043,340
Intangible Assets 128,781
Other 593
Total Assets Acquired 1,204,430

Fair Value of Liabilities Assumed:
Accounts Payable 26,059
CNXM Revolving Credit Facility 149,500
Total Liabilities Assumed 175,559

Total Identifiable Net Assets 1,028,871
Fair Value of Noncontrolling Interest in CNXM (718,577 )
Goodwill 796,359
Net Assets Acquired $ 1,106,653

~~Post-Acquisition Operating Results~~ ~~(Midstream Acquisition)~~

~~The Midstream Acquisition contributed the following to the Company's Midstream segment:~~

Three Months Ended Nine Months Ended
September 30, September 30,
2019 2018 2019 2018
Midstream Revenue $ 74,261
$ 61,372
$ 225,280
$ 186,875
Earnings Before Income Tax $ 41,741
$ 31,173
$ 118,739
$ 94,502

~~NOTE 6—INCOME TAXES:~~

The effective tax rates for the three and nine months ended September 30, 2019 were 25.4% and 22.3%, respectively. The effective tax rate for the nine months ended September 30, 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state income taxes.

The effective tax rates for the three and nine months ended September 30, 2018 were 27.9% and 24.1%, respectively. The effective rate for the nine months ended September 30, 2018 differs from the U.S. federal statutory rate of 21% primarily due to increases for both state income taxes and state valuation allowances, offset by the benefit derived from the filing of a Federal 10-year net operating loss (“NOL”) carryback as well as non-controlling interest.

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the "Act") which, among other things, lowered the U.S. Federal corporate income tax rate from 35% to 21%, repealed the corporate alternative minimum tax ("AMT"), and provided for a refund of previously accrued corporate AMT credits. As of December 31, 2018, the Company reclassified $102,482 from Deferred Income Taxes to Recoverable Income Taxes in the Consolidated Balance Sheets in anticipation of the AMT refund that is also included in the Recoverable Income Taxes line of the Consolidated Statements of Cash Flows in the nine months ended September 30, 2019.

~~The total amount of uncertain tax positions~~consideration transferred at each of September 30, 2019 and December 31, 2018 was $31,516. If these uncertain tax positions were recognized, approximately $31,516 would affect CNX's effective tax rate. There were no changes in unrecognized tax benefits during the three and nine months ended September 30, 2019.

CNX recognizes accrued interest related to uncertain tax positions in interest expense. As of September 30, 2019 and December 31, 2018, CNX had 0 accrued liabilities for interest related to uncertain tax positions.

CNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of September 30, 2019 and December 31, 2018, CNX had no accrued liabilities for tax penalties related to uncertain tax positions.

CNX and its subsidiaries file federal income tax returns with the United States and tax returns within various state jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2016. The Company expects the Internal Revenue Service to conclude its audit of tax years 2016 through 2017 in the second quarter of 2020.

~~NOTE 7—PROPERTY, PLANT AND EQUIPMENT:~~

September 30,
2019 December 31,
2018
Property, Plant and Equipment
Intangible Drilling Cost $ 4,566,206
$ 4,120,283
Gas Gathering Equipment 2,399,883
2,126,895
Proved Gas Properties 1,157,361
1,135,411
Gas Wells and Related Equipment 1,047,139
859,359
Unproved Gas Properties 949,529
927,667
Surface Land and Other Equipment 233,812
238,487
Other 158,368
159,326
Total Property, Plant and Equipment 10,512,298
9,567,428
Less: Accumulated Depreciation, Depletion and Amortization 2,981,723
2,624,984
Total Property, Plant and Equipment - Net $ 7,530,575
$ 6,942,444

~~NOTE 8—GOODWILL AND OTHER INTANGIBLE ASSETS:~~

~~In connection with the Midstream Acquisition that closed~~closing on January 3, 2018, ~~(See Note 5 - Acquisitions and Dispositions for more information),~~ CNX recorded $796,359 of goodwill and $128,781 of other intangible assets which are comprised of customer relationships.

Impairment of Goodwill

All goodwill is attributed to the Midstream ~~reportable~~reporting unit within the Shale segment. Goodwill is evaluated for impairment at least annually and whenever events or changes in circumstance indicate that the fair value of a reporting unit is less than its carrying amount. In connection with the evaluation of goodwill for impairment, CNX may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. If after assessing such factors or circumstances, CNX determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. If CNX chooses to bypass the qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then CNX will perform a quantitative assessment. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. The Company uses a combination of the income approach (generally a discounted cash flow method) and market approach (which may include the guideline public company method and/or the guideline transaction method) to estimate the fair value of a reporting unit.

During the first quarter of 2020, the Company identified indicators of impairment in the form of 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. Management concluded that these factors presented indications that the fair value of the Midstream reporting unit was more likely than not below the reporting unit’s carrying value. CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches as described above to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceeded its estimated fair value, and a corresponding impairment of $473,045 was recorded, which was included in Impairment of Goodwill in the accompanying Consolidated Statements of Income. 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.

In estimating the fair value of the Midstream reporting unit, the Company used the income approach’s discounted cash flow method, which applies significant inputs not observable in the public market (Level 3), including estimates and assumptions related to the use of an appropriate discount rate, future throughput volumes, operating costs and capital spending, discounted to present value using an industry rate adjusted for company-specific risk, which management feels reflects the overall level of inherent risk of the reporting unit. These assumptions are affected by expectations about future market, industry and economic conditions. Cash flow projections were derived from board approved budgeted amounts, a five-year operating forecast and an estimate of future cash flows. Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur. The Company used the market approach’s comparable company method. The comparable company method evaluates the value of a company using metrics of other businesses of similar size and industry.

The estimates of future cash flows are subjective in nature and are subject to impacts from business risks as described in “Item 1A. Risk Factors” in CNX's 2019 Annual Report on Form 10-K as filed with the SEC on February 10, 2020 ("2019 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 CNX believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the estimated fair value. Future results could differ from our current estimates and assumptions.

Changes in the carrying amount of goodwill consist of the following activity:


	Amount
December 31, 2019	$	796,359
Impairment	473,045
September 30, 2020	$	323,314

Other Intangible Assets

The carrying amount and accumulated amortization of other intangible assets consist of the following:


	September 30, 2020		December 31, 2019
Other Intangible Assets
Gross Amortizable Asset - Customer Relationships	$	109,752	$	109,752
Less: Accumulated Amortization - Customer Relationships	18,019		13,105
Total Other Intangible Assets, net	$	91,733	$	96,647

September 30,
2019 December 31, 2018
Other Intangible Assets
Gross Amortizable Asset - Customer Relationships $ 109,752
$ 109,752
Less: Accumulated Amortization - Customer Relationships 11,467
6,552
Total Other Intangible Assets, net $ 98,285
$ 103,200

NOTE ~~18—~~15—STOCK REPURCHASE:

Since the October 30, 2017 inception of the current stock repurchase program, CNX's Board of Directors has approved in total a $750,000 stock repurchase program, which is not subject to an expiration date. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans. During the nine months ended September 30, 2019, 12,929,487 shares were repurchased and retired at an average price of $8.91 per share for a total cost of $115,477. There were 0 shares repurchased and retired during the nine months ended September 30, 2020.

NOTE ~~19—~~16—RECENT ACCOUNTING PRONOUNCEMENTS:

In ~~May 2019,~~August 2020, the FASB issued ASU ~~2019-05~~2020-06 - ~~Financial~~Accounting for Convertible Instruments ~~- Credit Losses (Topic 326), which provides optional targeted transition relief to entities adopting~~and Contracts in an Entity's Own Equity. This ASU 2016-13. ASU 2016-13 replaces the incurred loss impairment methodology with a 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 collectabilitysimplifies an entity's accounting for convertible instruments by eliminating two of the ~~reported amount. ASU 2019-05 provides~~three models in ASC 470-20 that require separate accounting for embedded conversion features, simplifies the ~~option~~settlement assessment that entities are required to ~~irrevocably elect~~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 ~~option for certain financial assets previously measured~~of an entity's convertible debt 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.~~instrument level, among other things. The amendments in this ASU ~~will be applied using the modified-retrospective approach and,~~are effective for public entities ~~are effective~~ for fiscal years beginning after December 15, ~~2019 and~~2021, including interim periods within those ~~annual periods.~~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.~~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. The amendments in this ASU 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 - Basis of Presentation 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.

NOTE 17—SUBSEQUENT EVENT:

On October 8, 2020, CNX repurchased the remaining $363,348 of its outstanding 5.875% senior notes due in April 2022 at an average price equal to 100% of the principal amount.

3133


~~ITEM 2.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Form 10-Q. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward-looking statements that are based on the current views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see “Part II. Item 1A. Risk Factors” and the section entitled “Forward-Looking Statements” and the “Risk Factors” contained in our Annual Report on Form 10-K for the year ended December 31, 2019, which we filed with the SEC on February 10, 2020. CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

General

~~During~~CNX continues to monitor the ~~third~~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 factors include: the impact of the COVID-19 pandemic and the related global economic downturn, the historically low natural gas prices and the historically low natural gas liquids prices that began with the crude oil price war between the Organization of Petroleum Exporting Countries ("OPEC")/Saudi Arabia and Russia in the first quarter of ~~2019, CNX sold 128.3 Bcfe of produced~~2020. The natural gas an increase of 7.8% from the 119.0 Bcfe sold in the year-earlier quarter, primarily due to an increase in Marcellus Shale volumes. The increase was offset, in part, by a decrease in Utica Shale volumes due to the sale of substantially all of CNX's Ohio Utica joint venture ("JV") assetsliquids prices have rebounded in the third ~~quarter~~quarter. 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 ~~2018. Total quarterly production costs increased~~the same period in previous years. The results presented in this Form 10-Q are not necessarily indicative of future operating results.

While CNX did not incur significant disruptions to $1.99 per Mcfe, compared to the year-earlier quarter of $1.97 per Mcfe, driven primarily by increases in transportation, gathering and compression, offset, in part, by reductions in depreciation, depletion and amortization and lease operating expense. Capital expenditures increased to $336 million in the third quarter of 2019, compared to $297 million of spend in the third quarter of 2018.

~~Marketing Update:~~

For the third quarter of 2019, CNX's average sales price for natural gas, natural gas liquids (NGLs), oil, and condensate was $2.51 per Mcfe. The average realized price for all liquids for the third quarter of 2019 was $14.26 per barrel.

CNX's weighted average differential from NYMEX in the third quarter of 2019 was negative $0.33 per MMBtu. CNX's average sales price for natural gas before hedging decreased 18.7% to $2.04 per Mcf compared with the average sales price of $2.51 per Mcf in the second quarter of 2019. This decrease resulted primarily from a lower Henry Hub price reflecting current general market conditions coupled with a wider differential. Including the impact of cash settlements from hedging, CNX's average sales price for natural gas was $0.08 per Mcf, or 3.1%, lower thanoperations during the three ~~months ended June 30, 2019, and $0.23 per Mcf,~~ or ~~8.4%, lower than the three~~nine months ended September 30, ~~2018.~~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. These uncertainties include the volatility and severity of the virus, the duration of the outbreak, the availability of a vaccine, governmental or other actions taken to combat the virus (which could include limitations on our operations or the operations of our customers and vendors), and the effect that the COVID-19 pandemic will have on the demand for natural gas and natural gas liquids. The continued health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions is vital to our operations and cannot currently be predicted. Further, the continuing impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, CNX cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact CNX. For instance, in the short term, CNX is starting to see a reduction in overall service and materials costs, due to oversupply of those services and costs, since industrial production has waned. However, if services providers to our industry are forced into bankruptcy or otherwise consolidate due to weakening economic conditions, demand could outpace supply in the long-term and cause these costs to increase. The situation surrounding COVID-19 remains fluid and unpredictable, and CNX is actively managing our response in collaboration with our contractors, customers, employees and vendors and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

CNX ~~Guidance:~~has also taken, and is continuing to take, proactive steps to manage any disruption in our business caused by COVID-19. For instance, even though our operations were not required to close, CNX was an early adopter in employing a work-from-home system, even before any government mandate on non-essential businesses was enacted. CNX increased its technology platform, infrastructure and security to allow for a work-from-home environment ahead of the actual need, and therefore, once the hypothetical became a reality, we believe CNX was ahead of many companies in this respect. CNX has also deployed additional safety protocols at our field sites in order to help keep our employees and contractors safe and to keep our operations running without material disruption. As the COVID-19 pandemic continues to unfold, CNX will continue to assess and update its protocols.

For further information regarding the impact of COVID-19 see Risk factors in Item 1A in our Quarterly Reports on Form 10-Q.

Recent Business Developments:

On September 28, 2020, we completed the acquisition of all of the outstanding common units of CNX ~~updates 2019 production volumes to 530-540 Bcfe, compared~~Midstream Partners LP ("CNXM") and CNXM became our indirect wholly-owned subsidiary (the “Merger”) (See Note 13 - Acquisitions and Dispositions in the Notes to the ~~previous guidance~~Unaudited Consolidated Financial Statements in Item 1 of ~~510-530 Bcfe.~~this Form 10-Q for additional information). In connection with the closing of the Merger, we issued 37.1 million shares of our common stock to acquire the 42.1 million common units of CNXM held by third-party CNXM investors at a fixed exchange ratio of 0.88 shares of CNX ~~updates 2020 production volumes~~common stock for each CNXM common unit, for total implied consideration of $384.6 million.

In conjunction with the Merger and to ~~535-565 Bcfe, compared~~provide a greater level of transparency that is more in-line with how Management views CNX's operations, CNX has updated its segment reporting to now include a Shale segment which is made up of what was formerly the Marcellus, Utica and Midstream Segments (See Note 14 - Segments in the Notes to the ~~previous guidance~~Unaudited Consolidated Financial Statements in Item 1 of ~~570-595 Bcfe. The updated 2020 guidance equates to an approximately 3% increase over 2019's updated midpoint.~~this Form 10-Q for additional information). CNX has recast its current and historical operating results into the new format.

Third quarter 2019 capital expenditure came in lower than expected, and the company is reducing its full-year 2019 capital guidance, while increasing production volumes. For 2020, the company is reducing its full-year capital guidance and production volumes, primarily due to plan changes and associated timing.Hedging Update:

For 2019 and 2020 combined, the company expects to spend approximately $80 million less capital than previously announced, resulting in 17.5 Bcfe less production in 2020, after accounting for 15 Bcfe of production accelerated from 2020 into 2019.

Total hedged natural gas production in the ~~2019~~2020 fourth quarter is ~~115.7~~124.0(1) Bcf. The annual gas hedge position is shown in the table below:

2019 2020
Volumes Hedged (Bcf), as of 10/9/19 405.2* 489.6


	2020	2021
Volumes Hedged (Bcf), as of 10/8/20	448.8(1)(2)	459.1

^*1Net of purchased swaps.

2Includes actual settlements of ~~312.5~~356.2 Bcf.

CNX's hedged gas volumes include a combination of NYMEX financial hedges, index (NYMEX and basis) financial hedges, and physical fixed price sales. In addition, to protect the NYMEX hedge volumes from basis exposure, CNX enters into basis-only financial hedges and physical sales with fixed basis at certain sales points.

3235

Results of Operations - Three Months EndedSeptember 30, ~~2019~~2020 Compared with Three Months Ended September 30, ~~2018~~2019

Net (Loss) Income Attributable to CNX Resources Shareholders

CNX reported a net loss attributable to CNX Resources shareholders of $205 million, or a loss per diluted share of $1.03, for the three months ended September 30, 2020, compared to net income attributable to CNX Resources shareholders of $116 million, or earnings per diluted share of $0.61, for the three months ended September 30, ~~2019, compared to net income attributable to CNX Resources shareholders of $125 million, or earnings per diluted share of $0.59,~~2019.


	For the Three Months Ended September 30,
(Dollars in thousands)	2020		2019		Variance
Net (Loss) Income	$	(188,793)	$	143,960	$	(332,753)
Less: Net Income Attributable to Noncontrolling Interest	15,905		28,422		(12,517)
Net (Loss) Income Attributable to CNX Resources Shareholders	$	(204,698)	$	115,538	$	(320,236)

Included in the loss for the three months ended September 30, ~~2018.~~

For the Three Months Ended September 30,
(Dollars in thousands) 2019 2018 Variance
Net Income $ 143,960
$ 146,756
$ (2,796 )
Less: Net Income Attributable to Noncontrolling Interest 28,422
21,727
6,695
Net Income Attributable to CNX Resources Shareholders $ 115,538
$ 125,029
$ (9,491 )

~~CNX consists~~2020 was an unrealized loss on commodity derivative instruments 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 earnings before income tax of $151 million for the three months ended September 30, 2019, compared to earnings before income tax of $54 million for the three months ended September 30, 2018.$259 million. Included in the earnings for the three months ended September 30, 2019 ~~and 2018 were~~was an unrealized ~~gains~~gain on commodity derivative instruments of $157 ~~million~~million.

Selected Operating Revenue and ~~$15 million, respectively.~~Other Cost Data

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.

CNX's Midstream Division had earnings before income tax of $42 million for the three months ended September 30, 2019, compared to earnings before income tax of $31 million for the three months ended September 30, 2018.

~~E&P Division Summary~~

~~Sales~~The following table presents sales volumes, revenue, costs, average sales ~~price~~prices (including the effects of settled ~~derivative instruments),~~derivatives) and average unit costs for ~~the E&P Division were as follows:~~ production operations on a total Company basis:

For the Three Months Ended September 30,
2019 2018 Variance
Percent
Change
Sales Volumes (Bcfe) 128.3
119.0
9.3
7.8 %

Average Sales Price (per Mcfe) $ 2.51
$ 2.92
$ (0.41 ) (14.0 )%
Lease Operating Expense (per Mcfe) 0.11
0.14
(0.03 ) (21.4 )%
Production, Ad Valorem, and Other Fees (per Mcfe) 0.05
0.06
(0.01 ) (16.7 )%
Transportation, Gathering and Compression (per Mcfe) 0.97
0.84
0.13
15.5 %
Depreciation, Depletion and Amortization (DD&A) (per Mcfe) 0.86
0.93
(0.07 ) (7.5 )%
Average Costs (per Mcfe) 1.99
1.97
0.02
1.0 %
Average Margin (per Mcfe) $ 0.52
$ 0.95
$ (0.43 ) (45.3 )%


	For the Three Months Ended September 30,
	2020			2019			Variance
	in Millions		Per Mcfe	in Millions		Per Mcfe	in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			115.7			128.3			(12.6)
									—
Natural Gas, NGL and Oil Revenue	$	182	1.53	$	265	2.04	$	(83)	(0.51)
Gain on Commodity Derivative Instruments - Cash Settlement - Gas	90		0.83	57		0.47	33		0.36
Total Revenue	272		2.36	322		2.51	(50)		(0.15)
Lease Operating Expense	10		0.09	14		0.11	(4)		(0.02)
Production, Ad Valorem, and Other Fees	6		0.05	6		0.05	—		—
Transportation, Gathering and Compression	69		0.59	80		0.63	(11)		(0.04)
Depreciation, Depletion and Amortization (DD&A)	112		0.98	120		0.93	(8)		0.05
Average Costs	197		1.71	220		1.72	(23)		(0.01)
Average Margin	$	75	0.65	$	102	0.79	$	(27)	(0.14)

~~Natural gas,~~ *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 ~~revenue was $265 million for~~and natural gas, which is not indicative of the ~~three months ended September 30, 2019,~~relationship of NGL, condensate, and natural gas prices.

The 12.6 Bcfe decrease in sales volumes when compared to ~~$345 million for~~ the ~~three months ended September 30, 2018. The decrease~~year-earlier quarter was primarily due to the temporary shut-in of new turn-in-line wells in 2020 due to low natural gas prices and normal production declines for legacy wells.

Changes in 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 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 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 a lower production base in 2020. The lower production volumes was a result of temporary shut-ins due to lower natural gas prices.

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 Three Months Ended September 30,
	2020			2019			Variance
	in Millions		Per Mcfe	in Millions		Per Mcfe	in Millions		Per Mcfe
Total Company Sales Volumes (Bcfe)*			115.7			128.3			(12.6)

Total Other Revenue and Operating Income	$	21	0.18	$	22	0.17	$	(1)	0.01

Depreciation, Depletion and Amortization	2		0.02	—		0.00	2		0.02
Exploration and Production Related Other Costs	2		0.02	6		0.05	(4)		(0.03)
Selling, General and Administrative Costs	23		0.20	24		0.19	(1)		0.01
Other Operating Expense	24		0.21	21		0.16	3		0.05
Total Selected Operating Costs and Expenses	51		0.45	51		0.40	—		0.05
Other Expense	2		0.02	3		0.02	(1)		0.00
Interest Expense	38		0.33	38		0.30	—		0.03
Total Selected Other Expense	40		0.35	41		0.32	(1)		0.03
Total Selected Costs and Expenses	$	91	0.80	$	92	0.72	$	(1)	0.08

* 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, ~~pricing offset, in-part by~~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 ~~7.8% increase in total~~understanding of the Company’s natural gas production and sales ~~volumes.~~portfolio and information regarding settled commodity derivatives:


	For the Three Months Ended September 30,
in thousands (unless noted)	2020		2019		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	6,885		8,019		(1,134)		(14.1)	%
Sales Volume (Mbbls)	1,147		1,337		(190)		(14.2)	%
Gross Price ($/Bbl)	$	13.14	$	13.68	$	(0.54)	(3.9)	%
Gross NGL Revenue	$	15,053	$	18,305	$	(3,252)	(17.8)	%

Oil/Condensate:
Sales Volume (MMcfe)	624		77		547		710.4	%
Sales Volume (Mbbls)	104		13		91		700.0	%
Gross Price ($/Bbl)	$	39.50	$	73.12	$	(33.62)	(46.0)	%
Gross Oil/Condensate Revenue	$	4,106	$	931	$	3,175	341.0	%

GAS
Sales Volume (MMcf)	108,190		120,208		(12,018)		(10.0)	%
Sales Price ($/Mcf)	$	1.51	$	2.04	$	(0.53)	(26.0)	%
Gross Gas Revenue	$	163,054	$	245,815	$	(82,761)	(33.7)	%

Hedging Impact ($/Mcf)	$	0.83	$	0.47	$	0.36	76.6	%
Gain on Commodity Derivative Instruments - Cash Settlement	$	90,311	$	57,041	$	33,270	58.3	%

The decrease in ~~average sales price per Mcfe~~the gross revenue was primarily the result of the ~~$0.67~~$0.53 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 $0.16 per Mcfe~~gas and the 12.6 Bcfe decrease in sales volumes. The decrease in the ~~uplift from NGLs and condensate sales volumes. Both decreases were~~gross revenue was offset, in-part, by ~~a $0.44 per Mcf~~the increase in the realized gain on commodity derivative instruments related to the Company's hedging ~~program during~~program.

SEGMENT ANALYSIS for the ~~current period.~~three months ended September 30, 2020 compared to the three months ended September 30, 2019:

~~Changes~~


	For the Three Months Ended								Difference to Three Months Ended
	September 30, 2020								September 30, 2019
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total
Natural Gas, NGL and Oil Revenue	$	156	$	26	$	—	$	182	$	(73)	$	(10)	$	—	$	(83)
Gain (Loss) on Commodity Derivative Instruments	80		11		(260)		(169)		29		5		(417)		(383)
Purchased Gas Revenue	—		—		32		32		—		—		3		3
Other Revenue and Operating Income	17		—		4		21		(2)		—		1		(1)
Total Revenue and Other Operating Income	253		37		(224)		66		(46)		(5)		(413)		(464)
Lease Operating Expense	7		4		(1)		10		(3)		—		(1)		(4)
Production, Ad Valorem, and Other Fees	5		1		—		6		—		(1)		1		—
Transportation, Gathering and Compression	60		10		(1)		69		(10)		—		(1)		(11)
Depreciation, Depletion and Amortization	94		16		4		114		(7)		(1)		2		(6)

Exploration and Production Related Other Costs	—		—		2		2		—		—		(4)		(4)
Purchased Gas Costs	—		—		32		32		—		—		4		4
Selling, General and Administrative Costs	—		—		23		23		—		—		(1)		(1)
Other Operating Expense	—		—		24		24		—		—		3		3
Total Operating Costs and Expenses	166		31		83		280		(20)		(2)		3		(19)
Other Expense	—		—		2		2		—		—		(1)		(1)
Gain on Asset Sales and Abandonments, net	—		—		(4)		(4)		—		—		(1)		(1)

Interest Expense	—		—		38		38		—		—		—		—
Total Other Expense	—		—		36		36		—		—		(2)		(2)
Total Costs and Expenses	166		31		119		316		(20)		(2)		1		(21)
Earnings (Loss) Before Income Tax	$	87	$	6	$	(343)	$	(250)	$	(26)	$	(3)	$	(414)	$	(443)

SHALE SEGMENT

The Shale segment had earnings before income tax of $87 million for the three months ended September 30, 2020 compared to earnings before income tax of $113 million for the three months ended September 30, 2019.


	For the Three Months Ended September 30,
	2020		2019		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	95.2		106.0		(10.8)		(10.2)	%
NGL Sales Volumes (Bcfe)*	6.9		8.0		(1.1)		(13.8)	%
Oil/Condensate Sales Volumes (Bcfe)*	0.5		0.1		0.4		400.0	%
Total Shale Sales Volumes (Bcfe)*	102.6		114.1		(11.5)		(10.1)	%

Average Sales Price - Gas (per Mcf)	$	1.44	$	1.98	$	(0.54)	(27.3)	%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	0.84	$	0.48	$	0.36	75.0	%
Average Sales Price - NGL (per Mcfe)*	$	2.18	$	2.28	$	(0.10)	(4.4)	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	6.27	$	12.76	$	(6.49)	(50.9)	%

Total Average Shale Sales Price (per Mcfe)	$	2.30	$	2.46	$	(0.16)	(6.5)	%
Average Shale Lease Operating Expenses (per Mcfe)	0.07		0.09		(0.02)		(22.2)	%
Average Shale Production, Ad Valorem, and Other Fees (per Mcfe)	0.04		0.04		—		—	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.58		0.61		(0.03)		(4.9)	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.93		0.89		0.04		4.5	%
Total Average Shale Costs (per Mcfe)	$	1.62	$	1.63	$	(0.01)	(0.6)	%
Average Margin for Shale (per Mcfe)	$	0.68	$	0.83	$	(0.15)	(18.1)	%

The Shale segment had natural gas, NGL and oil revenue of $156 million for the three months ended September 30, 2020 compared to $229 million for the three months ended September 30, 2019. The $73 million decrease was primarily due to a 27.3% decrease in the average ~~costs~~sale price for natural gas and a 4.4% decrease in the average sale price of NGLs, along with a 10.1% decrease in total Shale sales volumes. The decrease in total Shale sales volumes was primarily due to the temporary shut-in of new turn-in-line wells in 2020 due to low natural gas prices.

The decrease in the total average Shale sales price was primarily due to a $0.54 per Mcf decrease in the average sales price for natural gas and a $0.10 per Mcfe decrease in the average NGL sales price, offset in part by a $0.36 per Mcf increase in the realized gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 89.3 Bcf of the Company's produced Shale gas sales volumes for the three months ended September 30, 2020 at an average gain of $0.89 per Mcf hedged. For the three months ended September 30, 2019, these financial hedges represented approximately 90.3 Bcf at an average gain of $0.56 per Mcf hedged.

Total operating costs and expenses for the Shale segment were ~~primarily related~~$166 million for the three months ended September 30, 2020 compared to $186 million for the three months ended September 30, 2019. The decrease in total dollars and decrease in unit costs for the Shale segment were due to the following items:

~~Transportation, gathering,~~

•Shale lease operating expenses were $7 million for the three months ended September 30, 2020 compared to $10 million for the three months ended September 30, 2019. The decrease in total dollars and ~~compression expense increased on~~in unit costs was primarily due to a ~~per unit basis primarily~~decrease in water disposal costs in the current period due to an increase in ~~CNXM~~the reuse of produced water in well completions activity.

•Shale transportation, gathering ~~fees~~and compression costs were $60 million for the three months ended September 30, 2020 compared to $70 million for the three months ended September 30, 2019. The decreases in total dollars and unit costs were primarily related to ~~an increase in our Marcellus production~~lower processing costs and ~~an increase~~a decrease in firm transportation expense ~~primarily as~~due to lower gas sales volumes.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $94 million for the three months ended September 30, 2020 compared to $101 million for the three months ended September 30, 2019. These amounts included

depletion on a ~~result~~unit of ~~new contracts that give CNX the ability to move~~production basis of $0.81 per Mcfe and ~~sell natural gas outside of the Appalachian basin.~~$0.82 per Mcfe, respectively. The decrease in units of production ~~from CNX's~~depreciation, depletion and amortization rate in the current period is the result of positive reserve revisions within our core SWPA development area and lower cost ~~dry Utica volumes also contributed~~reserves added in our core SWPA development area from the 2019 development program partially offset by an increase in the units of production depreciation, depletion and amortization rate due to ~~the increase~~negative reserves revisions within our Ohio operations. The remaining depreciation, depletion and amortization costs were either recorded on a ~~per unit basis.~~straight-line basis or related to asset retirement obligations.

~~Lease~~

Total Shale other revenue and operating ~~expense decreased on a per unit basis~~income relates to natural gas gathering services provided to third-parties. The Shale segment had other revenue and operating income of $17 million for the three months ended September 30, 2020 compared to $19 million for the three months ended September 30, 2019. The decrease in the period-to-period comparison was primarily due to a reduction in third-party volumes transported related to temporary production curtailments.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $6 million for the ~~number~~three months ended September 30, 2020 compared to earnings before income tax of ~~employees~~$9 million for the three months ended September 30, 2019.


	For the Three Months Ended September 30,
	2020		2019		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	13.0		14.1		(1.1)		(7.8)	%

Average Sales Price - Gas (per Mcf)	$	1.98	$	2.52	$	(0.54)	(21.4)	%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	0.81	$	0.43	$	0.38	88.4	%

Total Average CBM Sales Price (per Mcf)	$	2.79	$	2.95	$	(0.16)	(5.4)	%


Average CBM Lease Operating Expenses (per Mcf)	0.28		0.28		—		—	%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)	0.09		0.10		(0.01)		(10.0)	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	0.76		0.71		0.05		7.0	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.21		1.24		(0.03)		(2.4)	%
Total Average CBM Costs (per Mcf)	$	2.34	$	2.33	$	0.01	0.4	%
Average Margin for CBM (per Mcf)	$	0.45	$	0.62	$	(0.17)	(27.4)	%

The CBM segment had natural gas revenue of $26 million for the three months ended September 30, 2020 compared to $36 million for the three months ended September 30, 2019. The $10 million decrease was due to the 7.8% decrease in total CBM sales volumes and the ~~associated costs~~21.4% decrease in the ~~period-to-period comparison.~~average sales price for natural gas. 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 $0.54 per Mcf decrease in average gas sales price, offset in part by a $0.38 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 11.8 Bcf of the Company's produced CBM sales volumes for the three months ended September 30, 2020 at an average gain of $0.89 per Mcf hedged. For the three months ended September 30, 2019, these financial hedges represented approximately 11.3 Bcf at an average gain of $0.53 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $31 million for the three months ended September 30, 2020 compared to $33 million for the three months ended September 30, 2019. The decrease in total dollars and increase in unit costs for the CBM segment was primarily due to the following:

•CBM transportation, gathering and compression costs remained consistent at $10 million for both the three months ended September 30, 2020 and 2019. The increase in unit costs were primarily related to the 7.8% decrease in CBM sales volumes.

•Depreciation, depletion and amortization ~~expense decreased~~costs attributable to the CBM segment were $16 million for the three months ended September 30, 2020 compared to $17 million for the three months ended September 30, 2019. These amounts included depletion on a unit of production basis of $0.67 per ~~unit basis primarily~~Mcfe and $0.70 per Mcfe, respectively. The decrease in the units of

production depreciation, depletion and amortization rate was due to positive reserve revisions. The remaining depreciation, depletion and amortization costs were either recorded on a ~~reduction~~straight-line basis or related to asset retirement obligations.

OTHER SEGMENT

The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, impairments of exploration and production properties, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative (SG&A), interest expense and income taxes.

The Other segment had a loss before income tax of $343 million for the three months ended September 30, 2020 compared to earnings before income tax of $71 million for the three months ended September 30, 2019.


	For the Three Months Ended September 30,
	2020	2019	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	—	0.1	(0.1)	(100.0)	%
Oil/Condensate Sales Volumes (Bcfe)*	0.1	—	0.1	100.0	%

* 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.

Gain or Loss on Commodity Derivative Instruments and Monetization

For the three months ended September 30, 2020, the Other Gas segment recognized an unrealized loss on commodity derivative instruments of $259 million and cash settlements paid of $1 million. For the three months ended September 30, 2019, the Other Gas segment recognized an unrealized gain on commodity derivative instruments of $157 million. The unrealized loss/gain on commodity derivative instruments represents changes in ~~Marcellus rates as~~the fair value of all of the Company's existing commodity hedges on a ~~result~~mark-to-market basis.

Purchased Gas

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were $32 million for the three months ended September 30, 2020 compared to $29 million for the three months ended September 30, 2019. Purchased gas costs were $32 million for the three months ended September 30, 2020 compared to $28 million for the three months ended September 30, 2019. The period-to-period increase in purchased gas revenue was due to an increase in ~~the Company's associated reserves.~~

~~The following table presents a breakout of net liquid and natural~~purchased gas sales ~~information~~volumes, offset in part by a decrease in average sales price.


	For the Three Months Ended September 30,
	2020		2019		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	20.7		13.6		7.1		52.2	%
Average Sales Price (per Mcf)	$	1.52	$	2.14	$	(0.62)	(29.0)	%
Average Cost (per Mcf)	$	1.53	$	2.02	$	(0.49)	(24.3)	%

Other Operating Income


	For the Three Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Gathering Income	$	3	$	2	$	1	50.0	%
Water Income	1		—		1		100.0	%
Equity in Earnings of Affiliates	—		1		(1)		(100.0)	%
Total Other Operating Income	$	4	$	3	$	1	33.3	%

•Gathering income represents revenue from the sale of excess firm transportation capacity to ~~assist~~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.

Exploration and Production Related Other Costs


	For the Three Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Seismic Activity	$	—	$	5	$	(5)	(100.0)	%
Lease Expiration Costs	1		1		—		—	%
Land Rentals	1		—		1		100.0	%

Total Exploration and Production Related Other Costs	$	2	$	6	$	(4)	(66.7)	%

•Seismic activity decreased in the ~~understanding of~~period-to-period comparison due to additional geophysical research in the ~~Company’s natural gas production and sales portfolio.~~prior period.

For the Three Months Ended September 30,
in thousands (unless noted) 2019 2018 Variance Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe) 8,019
9,972
(1,953 ) (19.6 )%
Sales Volume (Mbbls) 1,337
1,662
(325 ) (19.6 )%
Gross Price ($/Bbl) $ 13.68
$ 28.08
$ (14.40 ) (51.3 )%
Gross Revenue $ 18,305
$ 46,663
$ (28,358 ) (60.8 )%

Oil:
Sales Volume (MMcfe) 9
72
(63 ) (87.5 )%
Sales Volume (Mbbls) 2
12
(10 ) (83.3 )%
Gross Price ($/Bbl) $ 56.64
$ 63.00
$ (6.36 ) (10.1 )%
Gross Revenue $ 92
$ 759
$ (667 ) (87.9 )%

Condensate:
Sales Volume (MMcfe) 67
351
(284 ) (80.9 )%
Sales Volume (Mbbls) 11
58
(47 ) (81.0 )%
Gross Price ($/Bbl) $ 75.54
$ 58.56
$ 16.98
29.0 %
Gross Revenue $ 839
$ 3,426
$ (2,587 ) (75.5 )%

GAS
Sales Volume (MMcf) 120,208
108,565
11,643
10.7 %
Sales Price ($/Mcf) $ 2.04
$ 2.71
$ (0.67 ) (24.7 )%
Gross Revenue $ 245,815
$ 293,864
$ (48,049 ) (16.4 )%

Hedging Impact ($/Mcf) $ 0.47
$ 0.03
$ 0.44
1,466.7 %
Gain on Commodity Derivative Instruments - Cash Settlement 57,041
2,825
54,216
1,919.2 %

Selling, General and Administrative ~~(SG&A) - Total Company~~("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. SG&A costs also include non-cash long-term equity-based compensation expense.


	For the Three Months Ended September 30,										For the Three Months Ended September 30,
(in millions)	2019		2018		Variance			Percent Change		(in millions)	2020		2019		Variance		Percent Change
SG&A
Salaries and Wages										Salaries and Wages	$	8	$	10	$	(2)	(20.0)	%
Long-Term Equity-Based Compensation (Non-Cash)										Long-Term Equity-Based Compensation (Non-Cash)	2		2		—		—	%
Short-Term Incentive Compensation	$	2	$	6	$	(4	)	(66.7	)%	Short-Term Incentive Compensation	3		2		1		50.0	%
Long-Term Equity-Based Compensation (Non-Cash)	2		5		(3		)	(60.0	)%
Salaries and Wages	10		9		1			11.1	%
Other	10		12		(2		)	(16.7	)%	Other	10		10		—		—	%
Total SG&A	$	24	$	32	$	(8	)	(25.0	)%	Total SG&A	$	23	$	24	$	(1)	(4.2)	%


•	~~Short-term incentive compensation decreased~~ $4 ~~million due to lower projected payouts in the current period.~~

~~Unallocated~~•Salaries and Wages decreased $2 million due to an overall reduction in employees and employee related costs resulting from a reduction in staff at the end of 2019 period.

Other Operating Expense

~~Certain costs~~


	For the Three Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	20	$	15	$	5	33.3	%
Idle Equipment and Service Charges	2		—		2		100.0	%
Insurance Expense	1		1		—		—	%
Other	1		5		(4)		(80.0)	%
Total Other Operating Expense	$	24	$	21	$	3	14.3	%

•Unutilized firm transportation and ~~expenses, such~~processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as ~~other expense, gain on asset~~ sales ~~and abandonments related to non-core assets, loss on debt extinguishment and income taxes are unallocated expenses and therefore are excluded from the per unit costs above~~volumes increase, as well as ~~segment reporting. Below~~additional processing capacity for NGLs. The increase of $5 million 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 or to process the Company’s wet natural gas production. The increase in unutilized capacity was primarily due to the temporary shut-in of new turn-in-line wells in 2020 due to low natural gas price. 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 Other Revenue and Operating Income above.

•Idle Equipment and Service Charges primarily relate to the temporary idling of one 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 $2 million in the period-to-period comparison was primarily the result of CNX idling one of its drilling rigs in the third-quarter.

•Other decreased $4 million in the period-to-period comparison primarily due to a ~~summary~~write-off of ~~these costs and expenses:~~obsolete inventory in the 2019 period.

Other Expense


	For the Three Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Other Income


Interest Income	$	2	$	1	$	1	100.0	%
Other	6		—		6		100.0	%
Total Other Income	$	8	$	1	$	7	700.0	%

Other Expense
Professional Services	$	2	$	1	$	1	100.0	%
Merger Related Costs	5		—		5		100.0	%
Bank Fees	3		3		—		—	%
Total Other Expense	$	10	$	4	$	6	150.0	%

Total Other Expense	$	2	$	3	$	(1)	(33.3)	%

For the Three Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
Other Income
Royalty Income $ —
$ 2
$ (2 ) (100.0 )%
Right of Way Sales —
1
(1 ) (100.0 )%
Interest Income 1
—
1
100.0 %
Other —
1
(1 ) (100.0 )%
Total Other Income $ 1
$ 4
$ (3 ) (75.0 )%

Other Expense
Professional Services $ 1
$ 1
$ —
— %
Bank Fees 3
3
—
— %
Other Corporate Expense —
1
(1 ) (100.0 )%
Total Other Expense $ 4
$ 5
$ (1 ) (20.0 )%

Total Other Expense $ 3
$ 1
$ 2
200.0 %

~~Gain on Asset Sales and Abandonments~~

~~A gain on asset sales~~•Other income increased $7 million in the period-to-period comparison primarily due to the receipt of ~~$3 million~~a severance tax refund related to ~~non-core assets was recognized~~a prior period in the three months ended September 30, ~~2019 compared to a gain of $134 million in the three months ended September 30, 2018, primarily~~2020 as well as additional interest income related to the ~~Ohio Utica JV asset sale. See~~alternative minimum tax (“AMT”) credit refund CNX received (See Note ~~5 -~~4- Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

•Merger-related costs consist of transaction costs directly attributable to the CNXM Merger (See Note 13- Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional ~~information.~~information), including financial advisory, legal service and other professional fees, which were recorded to Other Expense in the Consolidated Statements of Income.

~~Loss~~Gain on ~~Debt Extinguishment~~Asset Sales and Abandonments, net

~~Loss~~

A gain on ~~debt extinguishment~~asset sales of ~~$15~~$4 million related to the sale of various non-core assets was recognized in the three months ended September 30, ~~2018 due~~2020 compared to ~~the $200~~a gain of $3 million ~~redemption of the 8.00% Senior notes due in April 2023 at an average price equal to 106.0% of the principal amount. No such transactions occurred~~ in the ~~current period.~~three months ended September 30, 2019.

Loss (Gain) Loss on Debt Extinguishment

A nominal loss on debt extinguishment was recognized in the three months ended September 30, 2020. See Note 119 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

3543

Interest Expense


	For the Three Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Total Interest Expense	$	38	$	38	$	—	—	%

•Interest expense remained unchanged quarter over quarter. In 2020, the Company purchased $531 million of the outstanding 5.875% senior notes due in April 2022 during the nine months ended September 30, 2020 and had lower average borrowings under the CNX credit facility. These decreases were offset by the addition of $345 million of convertible senior notes due 2026 (the “Convertible Notes”) during the three months ended June 30, 2020 and by the addition of the $125 million Cardinal States Facility and $50 million CSG Holdings Facility during the three months ended March 31, 2020. Realized and unrealized losses on interest rate swap agreements also offset the decreases in interest expense mentioned above.

Income Taxes


	For the Three Months Ended September 30,
(in millions)	2020			2019			Variance			Percent Change
Total Company (Loss) Earnings Before Income Tax	$	(250)		$	193		$	(443)		(229.5)	%
Income Tax (Benefit) Expense	$	(61)		$	49		$	(110)		(224.5)	%
Effective Income Tax Rate	24.5		%	25.4		%	(0.9)		%

The effective income tax rate was 24.5% for the three months ended September 30, 2020 compared to 25.4% for the three months ended September 30, ~~2019 compared to 27.9% for the three months ended September 30, 2018.~~2019. The effective rate for the three months ended September 30, 2020 and 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state income taxes. The effective rate for the three months ended September 30, 2018 differs from the U.S. federalFederal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state income taxes.

See Note 64 - Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

For the Three Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
Total Company Earnings Before Income Tax $ 193
$ 203
$ (10 ) (4.9 )%
Income Tax Expense $ 49
$ 57
$ (8 ) (14.0 )%
Effective Income Tax Rate 25.4 % 27.9 % (2.5 )%

Results of Operations - Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019

~~TOTAL E&P DIVISION ANALYSIS~~

Net (Loss) Income Attributable to CNX Resources Shareholders

CNX reported a net loss attributable to CNX Resources shareholders of $680 million, or a loss per diluted share of $3.56, for the ~~three~~nine months ended September 30, 2020, compared to net income attributable to CNX Resources shareholders of $191 million, or earnings per diluted share of $1.01, for the nine months ended September 30, 2019.


	For the Nine Months Ended September 30,
(Dollars in thousands)	2020		2019		Variance
Net (Loss) Income	$	(624,502)	$	272,004	$	(896,506)
Less: Net Income Attributable to Noncontrolling Interest	55,031		81,325		(26,294)
Net (Loss) Income Attributable to CNX Resources Shareholders	$	(679,533)	$	190,679	$	(870,212)

Included in the loss for the nine months ended September 30, 2020 was a $62 million non-cash impairment charge related to exploration and production properties, a $473 million non-cash impairment charge related to goodwill and an unrealized loss on commodity derivative instruments of $501 million. Included in the earnings for the nine months ended September 30, 2019 ~~compared to the three months ended September 30, 2018:~~was an unrealized gain on commodity derivative instruments of $214 million.

Selected Operating Revenue and Other Cost Data

The ~~E&P division had earnings before income tax~~following table presents sales volumes, average sales prices (including the effects of $151 million for the three months ended September 30, 2019 compared to earnings before income tax of $54 million for the three months ended September 30, 2018. Variances by individual E&P segment are discussed below.settled derivatives and excluding hedge monetizations) and average costs on a total Company basis:

For the Three Months Ended Difference to Three Months Ended
September 30, 2019 September 30, 2018
(in millions) Marcellus Utica CBM Other
Gas Total E&P Marcellus Utica CBM Other
Gas Total
E&P
Natural Gas, NGLs and Oil Revenue $ 179
$ 50
$ 36
$ —
$ 265
$ (28 ) $ (38 ) $ (12 ) $ (2 ) $ (80 )
Gain on Commodity Derivative Instruments 38 13
6
157
214
36
13
5
142
196
Purchased Gas Revenue —
—
—
29
29
—
—
—
18
18
Other Operating Income —
—
—
4
4
—
—
—
1
1
Total Revenue and Other Operating Income 217
63
42
190
512
8
(25 ) (7 ) 159
135
Lease Operating Expense 6
4
4
—
14
(1 ) (1 ) (1 ) 1
(2 )
Production, Ad Valorem, and Other Fees 3
1
2
—
6
—
(1 ) —
—
(1 )
Transportation, Gathering and Compression 106
8
10
—
124
29
(4 ) (1 ) —
24
Depreciation, Depletion and Amortization 61
32
17
2
112
3
4
(4 ) (3 ) —
Exploration and Production Related Other Costs —
—
—
6
6
—
—
—
3
3
Purchased Gas Costs —
—
—
27
27
—
—
—
16
16
Other Operating Expense —
—
—
21
21
—
—
—
3
3
Selling, General and Administrative Costs —
—
—
20
20
—
—
—
(7 ) (7 )
Total Operating Costs and Expenses 176
45
33
76
330
31
(2 ) (6 ) 13
36
Interest Expense —
—
—
31
31
—
—
—
2
2
Total E&P Division Costs 176
45
33
107
361
31
(2 ) (6 ) 15
38
Earnings Before Income Tax $ 41
$ 18
$ 9
$ 83
$ 151
$ (23 ) $ (23 ) $ (1 ) $ 144
$ 97


	For the Nine Months Ended September 30,
	2020			2019			Variance
	in Millions		Per Mcfe	in Millions		Per Mcfe	in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			364.6			395.8			(31.2)

Natural Gas, NGL and Oil Revenue	$	609	1.62	$	1,044	2.63	$	(435)	(1.01)
Gain on Commodity Derivative Instruments - Cash Settlement - Gas **	300		0.87	26		0.07	274		0.80
Total Revenue	909		2.49	1,070		2.70	(161)		(0.21)
Lease Operating Expense	31		0.08	53		0.13	(22)		(0.05)
Production, Ad Valorem, and Other Fees	17		0.04	20		0.05	(3)		(0.01)
Transportation, Gathering and Compression	212		0.58	244		0.62	(32)		(0.04)
Depreciation, Depletion and Amortization (DD&A)	350		0.97	373		0.94	(23)		0.03
Average Costs	610		1.67	690		1.74	(80)		(0.07)
Average Margin	$	299	0.82	$	380	0.96	$	(81)	(0.14)

~~MARCELLUS SEGMENT~~

The Marcellus segment had earnings before income tax of $41 million for the three months ended September 30, 2019 compared to earnings before income tax of $64 million for the three months ended September 30, 2018.

For the Three Months Ended September 30,
2019 2018 Variance
Percent
Change
Marcellus Gas Sales Volumes (Bcf) 79.2
61.9
17.3
27.9 %
NGLs Sales Volumes (Bcfe)* 8.0
8.4
(0.4 ) (4.8 )%
Condensate Sales Volumes (Bcfe)* 0.1
0.3
(0.2 ) (66.7 )%
Total Marcellus Sales Volumes (Bcfe)* 87.3
70.6
16.7
23.7 %

Average Sales Price - Gas (per Mcf) $ 2.02
$ 2.66
$ (0.64 ) (24.1 )%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.48
$ 0.03
$ 0.45
1,500.0 %
Average Sales Price - NGLs (per Mcfe)* $ 2.28
$ 4.80
$ (2.52 ) (52.5 )%
Average Sales Price - Condensate (per Mcfe)* $ 14.09
$ 9.66
$ 4.43
45.9 %

Total Average Marcellus Sales Price (per Mcfe) $ 2.49
$ 2.96
$ (0.47 ) (15.9 )%
Average Marcellus Lease Operating Expenses (per Mcfe) 0.07
0.10
(0.03 ) (30.0 )%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe) 0.04
0.05
(0.01 ) (20.0 )%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe) 1.22
1.10
0.12
10.9 %
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe) 0.69
0.80
(0.11 ) (13.8 )%
Total Average Marcellus Costs (per Mcfe) $ 2.02
$ 2.05
$ (0.03 ) (1.5 )%
Average Margin for Marcellus (per Mcfe) $ 0.47
$ 0.91
$ (0.44 ) (48.4 )%

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

**Excluding $84 million gain from hedge monetization

The ~~Marcellus segment had natural gas, NGLs and oil revenue of $179 million for~~31.2 Bcfe decrease in volumes in the ~~three months ended September 30, 2019 compared to $207 million for the three months ended September 30, 2018. The $28 million decrease~~period-to period comparison was primarily due to the ~~24.1%~~temporary shut-in of a portion of CNX's liquids-rich Shirley-Pennsboro production in May and June of 2020 in response to low NGL prices. Additionally, four new pads of dry gas turn-in-lines from April and May were temporarily shut-in May through September due to low natural gas prices. Normal production declines also contributed to the decrease in total volumes.

Changes in the average ~~gas sales price and~~costs per Mcfe were primarily related to the 52.5% decrease in the average NGL sales price, offset in part by the 23.7% increase in total Marcellus sales volumes. The increase in sales volumes was primarily due to additional wells being turned in-line throughout 2018 and the first nine months of 2019 as part of the Company's ongoing drilling and completions program.following items:

~~The decrease in the total average Marcellus sales price was~~•Lease operating expense decreased on a per unit basis primarily due to a ~~$0.64 per Mcf~~ decrease in ~~the average gas sales price and a $2.52 per Mcfe decrease~~water disposal costs in the ~~average NGL sales price, offset~~period-to-period comparison as a result of increased reuse of produced water in ~~part by a $0.45 per Mcf increase~~well completions in the realized gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 68.7 Bcf of the Company's produced Marcellus gas sales volumes for the three months ended September 30, 2019 at an average gain of $0.56 per Mcf. For the three months ended September 30, 2018, these financial hedges represented approximately 53.9 Bcf at an average gain of $0.03 per Mcf. There was a $0.25 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging.

Total operating costs and expenses for the Marcellus segment were $176 million for the three months ended September 30, 2019 compared to $145 million for the three months ended September 30, 2018. The increase in total dollars and decrease in unit costs for the Marcellus segment were due to the following items:

current period.

•~~Marcellus lease operating~~Transportation, gathering, and compression expense ~~was $6 million for the three months ended September 30, 2019 compared~~decreased on a per unit basis primarily due to ~~$7 million for the three months ended September 30, 2018. The~~lower processing costs due to a drier production mix and a decrease in ~~unit~~firm transportation costs ~~was driven by the decreased total dollars, along with the 23.7% increase in total Marcellus~~due to lower gas sales volumes.

•Marcellus production, ad valorem, and other fees were consistent at $3 million for the three months ended September 30, 2019 and September 30, 2018. The decrease in unit costs was driven by the 23.7% increase in total Marcellus sales volumes and the 24.1% decrease in the average gas sales price.

•Marcellus transportation, gathering and compression costs were $106 million for the three months ended September 30, 2019 compared to $77 million for the three months ended September 30, 2018. The increase in total dollars was primarily related to the increase in production which resulted in 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 also related to new contracts that give CNX the ability to move and sell natural gas outside of the Appalachian basin. The increase in unit costs was driven by the increased total dollars described above.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $61 million for the three months ended September 30, 2019 compared to $58 million for the three months ended September 30, 2018. These amounts included depletionexpense increased on a per 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~~as a result of ~~positive reserve revisions within our core development area. The remaining~~fixed depreciation ~~depletion and amortization~~ costs ~~were either recorded on a straight-line basis or~~ related to ~~asset retirement obligations.~~CNX's gathering infrastructure being spread over a lower production base in 2020. The lower production volumes was a result of temporary shut-ins due to lower natural gas prices.

~~UTICA SEGMENT~~

The ~~Utica segment had~~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 ~~of $18 million for~~on a total company Mcfe equivalent and excluded from the ~~three months ended September 30, 2019 compared to earnings before income tax of $41 million for the three months ended September 30, 2018.~~previous table.

For the Three Months Ended September 30,
2019 2018 Variance
Percent
Change
Utica Gas Sales Volumes (Bcf) 26.8
31.9
(5.1 ) (16.0 )%
NGLs Sales Volumes (Bcfe)* —
1.6
(1.6 ) (100.0 )%
Condensate Sales Volumes (Bcfe)* —
0.1
(0.1 ) (100.0 )%
Total Utica Sales Volumes (Bcfe)* 26.8
33.6
(6.8 ) (20.2 )%

Average Sales Price - Gas (per Mcf) $ 1.86
$ 2.53
$ (0.67 ) (26.5 )%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.47
$ —
$ 0.47
100.0 %
Average Sales Price - NGLs (per Mcfe)* $ —
$ 4.00
$ (4.00 ) (100.0 )%
Average Sales Price - Condensate (per Mcfe)* $ —
$ 10.01
$ (10.01 ) (100.0 )%

Total Average Utica Sales Price (per Mcfe) $ 2.34
$ 2.62
$ (0.28 ) (10.7 )%
Average Utica Lease Operating Expenses (per Mcfe) 0.15
0.14
0.01
7.1 %
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe) 0.04
0.07
(0.03 ) (42.9 )%
Average Utica Transportation, Gathering and Compression Costs (per Mcfe) 0.29
0.35
(0.06 ) (17.1 )%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe) 1.18
0.83
0.35
42.2 %
Total Average Utica Costs (per Mcfe) $ 1.66
$ 1.39
$ 0.27
19.4 %
Average Margin for Utica (per Mcfe) $ 0.68
$ 1.23
$ (0.55 ) (44.7 )%


	For the Nine Months Ended September 30,
	2020			2019			Variance
	in Millions		Per Mcfe	in Millions		Per Mcfe	in Millions		Per Mcfe
Total Company Sales Volumes (Bcfe)*			364.6			395.8			(31.2)

Total Other Revenue and Operating Income	$	61	0.17	$	65	0.16	$	(4)	0.01

Depreciation, Depletion and Amortization	7		0.02	2		0.01	5		0.01
Exploration and Production Related Other Costs	9		0.02	15		0.04	(6)		(0.02)
Selling, General and Administrative Costs	76		0.21	109		0.28	(33)		(0.07)
Other Operating Expense	71		0.19	61		0.15	10		0.04
Total Selected Operating Costs and Expenses	163		0.44	187		0.48	(24)		(0.04)
Other Expense	12		0.03	3		0.01	9		0.02
Interest Expense	133		0.36	114		0.29	19		0.07
Total Selected Other Expense	145		0.39	117		0.30	28		0.09
Total Selected Costs and Expenses	$	308	0.83	$	304	0.78	$	4	0.05

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

Average Realized Price Reconciliation

The ~~Utica segment had~~following table presents a breakout of liquids and natural gas ~~NGLs~~sales information and ~~oil revenue of $50 million for the three months ended September 30, 2019 compared~~settled derivative information to ~~$88 million for the three months ended September 30, 2018. The $38 million decrease was primarily due to the 20.2% decrease in total Utica sales volumes, along with the 26.5% decrease~~assist in the ~~average~~understanding of the Company’s natural gas production and sales price. 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 as well as normal production declines in the remaining dry Utica wells.portfolio and information regarding settled commodity derivatives:


	For the Nine Months Ended September 30,
in thousands (unless noted)	2020		2019		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	19,927		22,556		(2,629)		(11.7)	%
Sales Volume (Mbbls)	3,321		3,759		(438)		(11.7)	%
Gross Price ($/Bbl)	$	12.24	$	19.20	$	(6.96)	(36.3)	%
Gross Revenue	$	40,691	$	72,095	$	(31,404)	(43.6)	%

Oil/Condensate:
Sales Volume (MMcfe)	1,236		690		546		79.1	%
Sales Volume (Mbbls)	206		115		91		79.1	%
Gross Price ($/Bbl)	$	37.01	$	45.16	$	(8.15)	(18.0)	%
Gross Revenue	$	7,630	$	5,193	$	2,437	46.9	%

GAS
Sales Volume (MMcf)	343,403		372,524		(29,121)		(7.8)	%
Sales Price ($/Mcf)	$	1.63	$	2.59	$	(0.96)	(37.1)	%
Gross Revenue	$	561,162	$	966,574	$	(405,412)	(41.9)	%

Hedging Impact ($/Mcf)	$	0.87	$	0.07	$	0.80	1,142.9	%
Gain on Commodity Derivative Instruments - Cash Settlement*	$	299,730	$	26,331	$	273,399	1,038.3	%

* Excluding gains from hedge monetizations

The decrease in ~~total average Utica sales price~~gross revenue was primarily ~~due to a $0.67~~the result of the $0.96 per Mcf decrease in general natural gas prices, when excluding the ~~average~~impact of hedging, in the markets in which CNX sells its natural gas, the 31.2 Bcfe decrease in sales ~~price,~~volumes, and the $6.96 per Bbl. decrease in NGL prices. These decreases were offset, ~~in part~~in-part, by ~~a $0.47 per Mcf~~the increase in the realized gain on commodity derivative ~~instruments. The notional amounts associated with these financial hedges represented approximately 21.6 Bcf of~~instruments related to the Company's ~~produced Utica gas sales volumes~~hedging program.

SEGMENT ANALYSIS for the ~~three~~nine months ended September 30, ~~2019 at an average gain of $0.58 per Mcf. For~~2020 compared to the ~~three~~nine months ended September 30, ~~2018, these financial hedges represented approximately 23.1 Bcf at an average gain of $0.04 per Mcf. Additionally, there was a $0.08 per~~2019:


	For the Nine Months Ended								Difference to the Nine Months Ended
	September 30, 2020								September 30, 2019
(in millions)	Shale		CBM		Other		Total E&P		Shale		CBM		Other		Total E&P



Natural Gas, NGL and Oil Revenue	$	529	$	79	$	1	$	609	$	(389)	$	(46)	$	—	$	(435)
Gain (Loss) on Commodity Derivative Instruments	266		33		(416)		(117)		242		30		(629)		(357)
Purchased Gas Revenue	—		—		78		78		—		—		14		14
Other Revenue and Operating Income	47		—		14		61		(9)		—		5		(4)

Total Revenue and Other Operating Income	842		112		(323)		631		(156)		(16)		(610)		(782)
Lease Operating Expense	19		11		1		31		(21)		(2)		1		(22)
Production, Ad Valorem, and Other Fees	14		4		—		18		(1)		(1)		—		(2)
Transportation, Gathering and Compression	183		29		—		212		(32)		—		—		(32)
Depreciation, Depletion and Amortization	295		50		12		357		(22)		(2)		6		(18)
Impairment of Exploration and Production Properties	—		—		62		62		—		—		62		62
Impairment of Goodwill	—		—		473		473		—		—		473		473
Exploration and Production Related Other Costs	—		—		9		9		—		—		(6)		(6)
Purchased Gas Costs	—		—		77		77		—		—		15		15
Other Operating Expense	—		—		71		71		—		—		10		10
Selling, General and Administrative Costs	—		—		76		76		—		—		(33)		(33)
Total Operating Costs and Expenses	511		94		781		1,386		(76)		(5)		528		447
Other Expense	—		—		12		12		—		—		9		9
Gain on Asset Sales and Abandonments, net	—		—		(22)		(22)		—		—		(21)		(21)
Gain on Debt Extinguishment	—		—		(11)		(11)		—		—		(19)		(19)
Interest Expense	—		—		133		133		—		—		19		19
Total Other Expenses	—		—		112		112		—		—		(12)		(12)
Total Costs and Expenses	511		94		893		1,498		$	(76)	$	(5)	$	516	$	435
Earnings (Loss) Before Income Tax	$	331	$	18	$	(1,216)	$	(867)	$	(80)	$	(11)	$	(1,126)	$	(1,217)

3947

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 JV assets in the third quarter of 2018, which consisted primarily of wet gas production.

Total operating costs and expenses for the Utica segment were $45 million for the three months ended September 30, 2019 compared to $47 million for the three months ended September 30, 2018. The decrease in total dollars and increase in unit costs for the Utica segment were due to the following items:

SHALE SEGMENT

•
Utica lease operating expense was $4 million for the three months ended September 30, 2019 compared to $5 million for the three months ended September 30, 2018. The decrease in total dollars was primarily due to a reduction in repairs and maintenance costs due to the sale of the Ohio JV assets in 2018, along with a reduction in the number of employees and the associated costs in the period-to-period comparison. The increase in unit costs was driven by the decrease in production volumes.

•Utica transportation, gathering and compression costs were $8 million for the three months ended September 30, 2019 compared to $12 million for the three months ended September 30, 2018. The $4 million decrease in total dollars and $0.06 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 $32 million for the three months ended September 30, 2019 compared to $28 million for the three months ended September 30, 2018. These amounts included depletion on a unit of production basis of $1.17 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 remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

~~COALBED METHANE (CBM) SEGMENT~~

The ~~CBM~~Shale segment had earnings before income tax of $9$331 million for the ~~three~~nine months ended September 30, ~~2019~~2020 compared to earnings before income tax of ~~$10~~$411 million for the ~~three~~nine months ended September 30, ~~2018.~~2019.

For the Three Months Ended September 30,
2019 2018 Variance
Percent
Change
CBM Gas Sales Volumes (Bcf) 14.1
14.7
(0.6 ) (4.1 )%

Average Sales Price - Gas (per Mcf) $ 2.52
$ 3.29
$ (0.77 ) (23.4 )%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.43
$ 0.04
$ 0.39
975.0 %

Total Average CBM Sales Price (per Mcf) $ 2.95
$ 3.33
$ (0.38 ) (11.4 )%
Average CBM Lease Operating Expenses (per Mcf) 0.28
0.32
(0.04 ) (12.5 )%
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) 0.71
0.77
(0.06 ) (7.8 )%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.24
1.47
(0.23 ) (15.6 )%
Total Average CBM Costs (per Mcf) $ 2.33
$ 2.68
$ (0.35 ) (13.1 )%
Average Margin for CBM (per Mcf) $ 0.62
$ 0.65
$ (0.03 ) (4.6 )%

The CBM segment had natural gas revenue of $36 million for the three months ended September 30, 2019 compared to $48 million for the three months ended September 30, 2018. The $12 million decrease was primarily due to the 4.1% decrease in total CBM sales volumes and the 23.4% decrease in the average gas sales price. The decrease in CBM sales volumes was primarily due to normal well declines.

The total average CBM sales price decreased $0.38 per Mcf due to a $0.77 decrease in the average gas sales price, offset in part by a $0.39 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 11.3 Bcf of the Company's produced CBM sales volumes for the three months ended September 30, 2019 at an average gain of $0.53 per Mcf. For the three months ended September 30, 2018, these financial hedges represented approximately 11.7 Bcf at an average gain of $0.03 per Mcf.

Total operating costs and expenses for the CBM segment were $33 million for the three months ended September 30, 2019 compared to $39 million for the three months ended September 30, 2018. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:

•CBM lease operating expense was $4 million for the three months ended September 30, 2019 compared to $5 million for the three months ended September 30, 2018. The $1 million decrease was primarily due to reductions in contractor services and a decrease in repairs and maintenance costs. The decrease in unit costs was also due to the decrease in total dollars.

•CBM transportation, gathering and compression costs were $10 million for the three months ended September 30, 2019 compared to $11 million for the three months ended September 30, 2018. The $1 million decrease in total dollars as well as the $0.06 per Mcf decrease in unit costs were primarily related to a decrease in electrical power expense as well as a decrease in contractor services.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $17 million for the three months ended September 30, 2019 compared to $21 million for the three months ended September 30, 2018. These amounts included depletion on a unit of production basis of $0.68 per Mcfe and $0.70 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

~~OTHER GAS SEGMENT~~

The Other Gas segment had earnings before income tax of $83 million for the three months ended September 30, 2019 compared to a loss before income tax of $61 million for the three months ended September 30, 2018.

For the Three Months Ended September 30,
2019 2018 Variance Percent
Change
Other Gas Sales Volumes (Bcf) 0.1
—
0.1
100.0 %
Oil Sales Volumes (Bcfe)* —
0.1
(0.1 ) (100.0 )%
Total Other Sales Volumes (Bcfe)* 0.1
0.1
—
— %


	For the Nine Months Ended September 30,
	2020		2019		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	304.0		330.6		(26.6)		(8.0)	%
NGLs Sales Volumes (Bcfe)*	19.9		22.6		(2.7)		(11.9)	%
Oil/Condensate Sales Volumes (Bcfe)*	1.2		0.6		0.6		100.0	%
Total Shale Sales Volumes (Bcfe)*	325.1		353.8		(28.7)		(8.1)	%

Average Sales Price - Gas (per Mcf)	$	1.58	$	2.54	$	(0.96)	(37.8)	%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)	$	0.88	$	0.07	$	0.81	1,157.1	%
Average Sales Price - NGLs (per Mcfe)*	$	2.04	$	3.20	$	(1.16)	(36.3)	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	5.98	$	7.50	$	(1.52)	(20.3)	%

Total Average Shale Sales Price (per Mcfe)	$	2.45	$	2.66	$	(0.21)	(7.9)	%
Average Shale Lease Operating Expenses (per Mcfe)	0.06		0.11		(0.05)		(45.5)	%
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)	0.56		0.61		(0.05)		(8.2)	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.92		0.89		0.03		3.4	%
Total Average Shale Costs (per Mcfe)	$	1.58	$	1.66	$	(0.08)	(4.8)	%
Average Margin for Shale (per Mcfe)	$	0.87	$	1.00	$	(0.13)	(13.0)	%

*~~Oil is~~ 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, oil, condensate, and natural gas prices.

The ~~Other Gas~~Shale segment ~~includes activity not assigned~~had natural gas, NGL and oil/condensate revenue of $529 million for the nine months ended September 30, 2020 compared to $918 million for the nine months ended September 30, 2019. The $389 million decrease was due primarily to a 37.8% decrease in the average sales price for natural gas, an 8.1% decrease in total Shale sales volumes, and a 36.3% decrease in the average sales price of NGLs.

The decrease in total Shale volumes was due to the ~~Marcellus, Utica, or CBM segments. This segment~~temporary shut-in of a portion of CNX's liquids-rich Shirley-Pennsboro production in May and June of 2020 in response to low NGL prices. Additionally, four new pads of dry gas turn-in-lines from April and May were temporarily shut-in during May through September due to low natural gas prices. Normal production declines also ~~includes purchased~~contributed to the decrease in total Shale volumes.

The decrease in total average Shale sales price was primarily due to a $0.96 per Mcf decrease in average gas ~~activity, unrealized~~sales price and a $1.16 per Mcfe decrease in the average NGL sales price. These decreases were offset in part by a $0.81 per Mcf increase in the realized gain on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 296.6 Bcf of the Company's produced Shale gas sales volumes for the nine months ended September 30, 2020 at an average gain of $0.90 per Mcf hedged. For the nine months ended September 30, 2019, these financial hedges represented approximately 246.5 Bcf at an average gain of $0.10 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $511 million for the nine months ended September 30, 2020 compared to $587 million for the nine months ended September 30, 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 $19 million for the nine months ended September 30, 2020 compared to $40 million for the nine months ended September 30, 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 $183 million for the nine months ended September 30, 2020 compared to $215 million for the nine months ended September 30, 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 contributed to the decrease in total dollars.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $295 million for the nine months ended September 30, 2020 compared to $317 million for the nine months ended September 30, 2019. These amounts included depletion on a unit of production basis of $0.81 per Mcfe and $0.82 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period is the result of positive reserve revisions within our core SWPA development area and lower cost reserves added in our core SWPA development area from the 2019 development program partially offset by an increase in the units of production depreciation, depletion and amortization rate due to negative reserves revisions within our Ohio operations. 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 $47 million for the nine months ended September 30, 2020 compared to $56 million for the nine months ended September 30, 2019. The decrease in the period-to-period comparison was primarily due to a reduction in third-party volumes transported related to temporary production curtailments.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $18 million for the nine months ended September 30, 2020 compared to earnings before income tax of $29 million for the nine months ended September 30, 2019.


	For the Nine Months Ended September 30,
	2020		2019		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	39.3		41.7		(2.4)		(5.8)	%

Average Sales Price - Gas (per Mcf)	$	2.02	$	3.00	$	(0.98)	(32.7)	%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	0.84	$	0.07	$	0.77	1,100.0	%

Total Average CBM Sales Price (per Mcf)	$	2.86	$	3.07	$	(0.21)	(6.8)	%
Average CBM Lease Operating Expenses (per Mcf)	0.29		0.30		(0.01)		(3.3)	%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)	0.10		0.13		(0.03)		(23.1)	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	0.74		0.70		0.04		5.7	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.25		1.24		0.01		0.8	%
Total Average CBM Costs (per Mcf)	$	2.38	$	2.37	$	0.01	0.4	%
Average Margin for CBM (per Mcf)	$	0.48	$	0.70	$	(0.22)	(31.4)	%

The CBM segment had natural gas revenue of $79 million for the nine months ended September 30, 2020 compared to $125 million for the nine months ended September 30, 2019. The $46 million decrease was due to the 5.8% decrease in total CBM sales volumes and the 32.7% 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 $0.21 per Mcf due to a $0.98 per Mcf decrease in average gas sales price, offset in part by a $0.77 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 37.0 Bcf of the Company's produced CBM sales volumes for the nine months ended September 30, 2020 at an average gain of $0.90 per Mcf hedged. For the nine months ended September 30, 2019, these financial hedges represented approximately 29.6 Bcf at an average gain of $0.10 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $94 million for the nine months ended September 30, 2020 compared to $99 million for the nine months ended September 30, 2019. The decrease in total dollars and increase in unit costs for the CBM segment were due to the following items:

•CBM lease operating expense was $11 million for the nine months ended September 30, 2020 compared to $13 million for the nine months ended September 30, 2019. The decrease in total dollars was due to a decrease in water disposal costs as well as a decrease in 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 $50 million for the nine months ended September 30, 2020 compared to $52 million for the nine months ended September 30, 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 to reduced production, offset in part by negative reserve revisions. 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 settlement dates, exploration and production related other costs, impairments of exploration and production properties, as well as various other ~~operational activity not assigned~~expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes.

The Other Gas segment had a loss before income tax of $1,216 million for the nine months ended September 30, 2020 compared to a ~~specific segment.~~loss before income tax of $90 million for the nine months ended September 30, 2019.

~~Other Gas sales volumes are primarily related to shallow oil~~


	For the Nine Months Ended September 30,
	2020	2019	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.1	0.3	(0.2)	(66.7)	%

Gain or Loss on Commodity Derivative Instruments and ~~gas production. CNX sold substantially all of these assets on March~~Monetization

For the nine months ended September 30, 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). There was nominal natural gas and oil revenue related to2020, the Other Gas segment ~~for both~~recognized an unrealized loss on commodity derivative instruments of $501 million as well as cash settlements received of $85 million. For the ~~three~~nine months ended September 30, 2019, ~~and 2018. Total operating costs and expenses related to these other gas sales volumes were $2 million for~~ the ~~three months ended September 30, 2019 compared to $4 million for the three months ended September 30, 2018.~~

~~The~~ Other Gas segment recognized an unrealized gain on commodity derivative instruments of ~~$157~~$214 million ~~for the three months ended September 30, 2019 compared to $15 million for the three months ended September 30, 2018.~~as well as cash settlements paid of $1 million. The unrealized ~~gain~~gain/loss on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis. Included in cash settlements for the nine months ended September 30, 2020 is $84 million related to natural gas hedges and financial basis hedges that were partially monetized or terminated prior to their settlement date. See Note 11 - Derivative Instruments in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the cash settlements.

Purchased Gas

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were ~~$29~~$78 million for the ~~three~~nine months ended September 30, ~~2019~~2020 compared to ~~$11~~$64 million for the ~~three~~nine months ended September 30, ~~2018.~~2019. Purchased gas costs were ~~$27~~$77 million for the ~~three~~nine months ended September 30, ~~2019~~2020 compared to ~~$11~~$62 million for the ~~three~~nine months ended September 30, ~~2018.~~2019. The period-to-period increase in purchased gas revenue was due to ~~the~~an increase in purchased gas sales volumes, offset in part by a decrease in ~~the average~~averages sales price.


	For the Nine Months Ended September 30,
	2020		2019		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	48.2		26.9		21.3		79.2	%
Average Sales Price (per Mcf)	$	1.63	$	2.39	$	(0.76)	(31.8)	%
Average Cost (per Mcf)	$	1.59	$	2.33	$	(0.74)	(31.8)	%

4150

For the Three Months Ended September 30,
2019 2018 Variance Percent
Change
Purchased Gas Sales Volumes (in Bcf) 13.6
4.1
9.5
231.7 %
Average Sales Price (per Mcf) $ 2.14
$ 2.55
$ (0.41 ) (16.1 )%
Average Cost (per Mcf) $ 2.02
$ 2.56
$ (0.54 ) (21.1 )%

Other Operating Income

~~Other operating~~


	For the Nine Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Water Income	$	5	$	1	$	4	400.0	%
Gathering Income	9		7		2		28.6	%
Equity in (Loss) Earnings of Affiliates	(1)		1		(2)		(200.0)	%
Other	1		—		1		100.0	%

Total Other Operating Income	$	14	$	9	$	5	55.6	%

•Water income ~~was~~increased $4 million ~~for~~in the ~~three months ended September 30, 2019 compared to $3 million for the three months ended September 30, 2018. The $1 million increase was~~2020 period due to ~~the following items:~~

For the Three Months Ended September 30,
(in millions) 2019 2018 Variance Percent
Change
Equity in Earnings of Affiliates $ 1
$ 1
$ —
— %
Gathering Income 2
2
—
— %
Other 1
—
1
100.0 %
Total Other Operating Income $ 4
$ 3
$ 1
33.3 %

~~Exploration and Production Related Other Costs~~

~~Exploration and production related other costs were $6 million~~increased revenue for ~~the three months ended September 30, 2019 compared to $3 million~~accepting deliveries of produced water from third-parties for ~~the three months ended September 30, 2018. The $3 million increase was due to the following items:~~

For the Three Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
Seismic Activity $ 5
$ —
$ 5
100.0 %
Lease Expiration Costs 1
1
—
— %
Land Rentals —
1
(1 ) (100.0 )%
Other —
1
(1 ) (100.0 )%
Total Exploration and Production Other Costs $ 6
$ 3
$ 3
100.0 %

~~Seismic activity increased~~reuse in the ~~period-to-period comparison due~~Company's hydraulic fracturing and increased sales of freshwater to ~~additional geophysical research in~~third-parties for hydraulic fracturing.

•Gathering income represents revenue from the ~~current period related~~sale of excess firm transportation capacity to ~~the Utica segment.~~

~~Other Operating Expense~~

~~Other operating expense was $21 million for the three months ended September 30, 2019 compared to $18 million for the three months ended September 30, 2018.~~third-parties. The ~~$3 million increase was due to the following items:~~

For the Three Months Ended September 30,
2019 2018 Variance Percent
Change
Unutilized Firm Transportation and Processing Fees $ 15
$ 11
$ 4
36.4 %
Insurance Expense 1
—
1
100.0 %
Consulting and Professional Services —
1
(1 ) (100.0 )%
Litigation Expense —
2
(2 ) (100.0 )%
Other 5
4
1
25.0 %
Total Other Operating Expense $ 21
$ 18
$ 3
16.7 %

~~Unutilized Firm Transportation and Processing Fees represent~~Company obtains firm 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 Company attemptsincrease. In order to minimize this unutilized firm transportation expense, ~~by releasing (selling)~~CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The

revenue ~~received when this~~(Gathering income) from released capacity ~~is released (sold) is included~~helps offsets the unutilized firm transportation and processing fees in ~~Gathering Income in Total Other Operating Income above.~~

~~Selling, General and Administrative~~

total other operating expense.

~~SG&A costs represent direct charges for~~

Impairment of Exploration and Production Properties

During the ~~management and operation of CNX's E&P division. SG&A costs were $20 million for the three~~nine months ended September 30, ~~2019 compared~~2020, CNX recognized certain indicators of impairments specific to ~~$27 million for~~our Southwest Pennsylvania (SWPA) CBM asset group and determined that the ~~three months ended September 30, 2018. Refer to~~carrying value of that asset group was not recoverable. The fair value of the ~~discussion~~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 ~~total company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders"~~fair value. As a result, an impairment of ~~this Form 10-Q for a detailed cost explanation.~~

~~Interest Expense~~

~~Interest expense of $31~~$62 million was recognized and is included in Impairment of Exploration and Production Properties in the ~~three months ended September 30, 2019 compared~~Consolidated Statements of Income. The impairment was related to ~~$29~~an economic decision to temporarily idle certain wells and the related processing facility during the first quarter.

Impairment of Goodwill

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

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 ~~three months ended September 30, 2018. The $2 million increase was primarily due~~first quarter of 2020 in relation to ~~additional borrowings on~~ the ~~CNX credit facility, offset, in part, by~~deteriorating macroeconomic conditions, and the ~~reduction in higher-cost long-term debt resulting from the $500 million purchase,~~decline in the ~~2018 period,~~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 ~~outstanding 8.00% senior notes due~~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 ~~April 2023, $200 million~~Impairment of ~~which was purchased during~~Goodwill in the ~~three months ended September 30, 2018.~~Consolidated Statement of Income. No such impairment occurred in the prior period. See Note 116 - ~~Long-Term Debt~~Goodwill and Other Intangible Assets in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

~~TOTAL MIDSTREAM DIVISION ANALYSIS for the three months ended September 30, 2019 compared to the three months ended September 30, 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 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). CNX Gathering holds all of the interests in CNX Midstream GP LLC, which holds the general partner interest and incentive distribution rights 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.

For the Three Months Ended September 30,
(in millions)

2019 2018 Variance
Midstream Revenue - Related Party $ 56
$ 41
$ 15
Midstream Revenue - Third Party 19
20
(1 )
Total Revenue $ 75
$ 61
$ 14

Transportation, Gathering and Compression $ 12
$ 10
$ 2
Depreciation, Depletion and Amortization 9
8
1
Selling, General, and Administrative Costs
4
5
(1 )
Total Operating Costs and Expenses 25
23
2
Interest Expense 8
7
1
Total Midstream Division Costs 33
30
3
Earnings Before Income Tax $ 42
$ 31
$ 11
51

~~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 depending upon delivery point and may change dynamically depending on commodity prices at time of shipment.

~~The table below summarizes volumes gathered by gas type:~~

For the Three Months Ended September 30,
2019 2018 Variance
Dry Gas (BBtu/d) (*) 857
702
155
Wet Gas (BBtu/d) (*) 685
705
(20 )
Other (BBtu/d) (*)(**) 273
3
270
Total Gathered Volumes 1,815
1,410
405

(*) 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 $12 million for the three months ended September 30, 2019 compared to $10 million for the three months ended September 30, 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 $4 million for the three months ended September 30, 2019 compared to $5 million for the three months ended September 30, 2018. Refer to the discussion of total Company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders"~~of this Form 10-Q 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.~~

~~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 $8 million for the three months ended September 30, 2019 compared to $7 million for the three months ended September 30, 2018.

~~Results of Operations -~~ ~~Nine Months Ended September 30, 2019 Compared with Nine Months Ended September 30, 2018~~

~~Net Income Attributable to CNX Resources Shareholders~~

CNX reported net income attributable to CNX Resources shareholders of $191 million, or earnings per diluted share of $1.01, for the nine months ended September 30, 2019, compared to net income attributable to CNX Resources shareholders of $695 million, or earnings per diluted share of $3.18, for the nine months ended September 30, 2018.

For the Nine Months Ended September 30,
(Dollars in thousands) 2019 2018 Variance
Net Income $ 272,004
$ 753,696
$ (481,692 )
Less: Net Income Attributable to Noncontrolling Interest 81,325
59,090
22,235
Net Income Attributable to CNX Resources Shareholders $ 190,679
$ 694,606
$ (503,927 )

~~CNX consists of two principal business divisions:~~ Exploration and Production ~~(E&P) and Midstream.~~Related Other Costs

~~The principal~~


	For the Nine Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Seismic Activity	$	—	$	6	$	(6)	(100.0)	%
Land Rentals	2		2		—		—	%
Lease Expiration Costs	5		5		—		—	%
Permitting Expense	2		—		2		100.0	%
Other	—		2		(2)		(100.0)	%
Total Exploration and Production Related Other Costs	$	9	$	15	$	(6)	(40.0)	%

•Seismic 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 earnings before income tax of $233 million for the nine months ended September 30, 2019, compared to earnings before income tax of $196 million for the nine months ended September 30, 2018. Included in the earnings for the nine months ended September 30, 2019 and 2018 were unrealized gains on commodity derivative instruments of $214 million and $76 million, respectively.

As a result of the Midstream Acquisition (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q), 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 $119 million for the nine months ended September 30, 2019, compared to earnings before income tax of $95 million for the period from January 3, 2018 through September 30, 2018.

~~E&P Division Summary~~

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

For the Nine Months Ended September 30,
2019 2018 Variance
Percent
Change
Sales Volumes (Bcfe) 395.8
371.0
24.8
6.7 %

Average Sales Price (per Mcfe) $ 2.70
$ 2.93
$ (0.23 ) (7.8 )%
Lease Operating Expense (per Mcfe) 0.13
0.21
(0.08 ) (38.1 )%
Production, Ad Valorem, and Other Fees (per Mcfe) 0.05
0.07
(0.02 ) (28.6 )%
Transportation, Gathering and Compression (per Mcfe) 0.96
0.84
0.12
14.3 %
Depreciation, Depletion and Amortization (DD&A) (per Mcfe) 0.87
0.90
(0.03 ) (3.3 )%
Average Costs (per Mcfe) 2.01
2.02
(0.01 ) (0.5 )%
Average Margin (per Mcfe) $ 0.69
$ 0.91
$ (0.22 ) (24.2 )%

Excluding the effects of settled derivative instruments, natural gas, NGLs, and oil revenue was $1,044 million for the nine months ended September 30, 2019, compared to $1,085 million for the nine months ended September 30, 2018. The decrease was primarily due to a decrease in natural gas and NGL pricing, offset in-part by a 6.7% increase in total sales volumes.

The decrease in average sales price per Mcfe was the result of the $0.15 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 $0.13 per Mcfe decrease in the uplift from NGLs and condensate sales volumes. Both decreases were offset, in-part by the $0.06 per Mcf increase in the realized gain on commodity derivative instruments related to the Company's hedging program during the current 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~~additional geophysical research 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.prior period.

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 natural 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.

~~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.~~

For the Nine Months Ended September 30,
in thousands (unless noted) 2019 2018 Variance Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe) 22,556
29,445
(6,889 ) (23.4 )%
Sales Volume (Mbbls) 3,759
4,908
(1,149 ) (23.4 )%
Gross Price ($/Bbl) $ 19.20
$ 27.96
$ (8.76 ) (31.3 )%
Gross Revenue $ 72,095
$ 137,104
$ (65,009 ) (47.4 )%

Oil:
Sales Volume (MMcfe) 43
236
(193 ) (81.8 )%
Sales Volume (Mbbls) 7
39
(32 ) (82.1 )%
Gross Price ($/Bbl) $ 48.24
$ 58.98
$ (10.74 ) (18.2 )%
Gross Revenue $ 347
$ 2,317
$ (1,970 ) (85.0 )%

Condensate:
Sales Volume (MMcfe) 647
1,670
(1,023 ) (61.3 )%
Sales Volume (Mbbls) 108
278
(170 ) (61.2 )%
Gross Price ($/Bbl) $ 44.94
$ 53.64
$ (8.70 ) (16.2 )%
Gross Revenue $ 4,846
$ 14,925
$ (10,079 ) (67.5 )%

GAS
Sales Volume (MMcf) 372,524
339,679
32,845
9.7 %
Sales Price ($/Mcf) $ 2.59
$ 2.74
$ (0.15 ) (5.5 )%
Gross Revenue $ 966,574
$ 930,505
$ 36,069
3.9 %

Hedging Impact ($/Mcf) $ 0.07
$ 0.01
$ 0.06
600.0 %
Gain on Commodity Derivative Instruments - Cash Settlement 26,331
2,518
23,813
945.7 %

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


	For the Nine Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	$	12	$	37	$	(25)	(67.6)	%
Salaries and Wages	23		31		(8)		(25.8)	%
Short-Term Incentive Compensation	7		9		(2)		(22.2)	%
Other	34		32		2		6.3	%
Total SG&A	$	76	$	109	$	(33)	(30.3)	%

For the Nine Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
SG&A
Long-Term Equity-Based Compensation (Non-Cash) $ 37
$ 16
$ 21
131.3 %
Salaries and Wages 31
30
1
3.3 %
Short-Term Incentive Compensation 9
17
(8 ) (47.1 )%
Other 32
36
(4 ) (11.1 )%
Total SG&A $ 109
$ 99
$ 10
10.1 %

•Long-term equity-based compensation ~~increased $21~~decreased $25 million in the period-to-period comparison due to a change in control event that occurred in the ~~Company incurring an additional $20 million~~second quarter of ~~long-term equity-based compensation (non-cash) expense during the nine months ended September 30, 2019. The additional expense was a result of~~2019 and resulted in the acceleration of vesting of certain restricted stock units and performance share units held by certain ~~employees related to a change in control event (See~~employees. See Note 2 - Earnings Per Share in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional ~~information).~~ information.

~~Short-term incentive compensation~~•Salaries and Wages decreased $8 million due to ~~lower projected payouts~~an overall reduction in ~~the current period.~~

~~Unallocated Expense~~

~~Certain~~employees and employee related costs and expenses, such as other expense (income), gain on asset sales and abandonments 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)~~

For the Nine Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
Other Income
Royalty Income $ 4
$ 12
$ (8 ) (66.7 )%
Right of Way Sales 4
5
(1 ) (20.0 )%
Interest Income 2
—
2
100.0 %
Other —
5
(5 ) (100.0 )%
Total Other Income $ 10
$ 22
$ (12 ) (54.5 )%

Other Expense
Professional Services $ 2
$ 6
$ (4 ) (66.7 )%
Bank Fees 9
8
1
12.5 %
Other Corporate Expense 2
3
(1 ) (33.3 )%
Total Other Expense $ 13
$ 17
$ (4 ) (23.5 )%

Total Other Expense (Income) $ 3
$ (5 ) $ 8
(160.0 )%

~~Gain on Asset Sales and Abandonments~~

A gain on asset sales of $8 million related to non-core assets was recognized in the nine months ended September 30, 2019 compared to a gain of $147 million in the nine months ended September 30, 2018, primarily due to the sale of substantially all of CNX's Ohio Utica JV assets. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

~~Also refer to the discussion of Loss (Gain) on Asset Sales and Abandonmentscontained in the section "Total Midstream Division Analysis"of this Form 10-Q 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 nine months ended September 30, 2018 due to the Midstream Acquisition in January 2018. No such transactions occurred in the current period. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

~~Loss on Debt Extinguishment~~

Loss on debt extinguishment of $8 million was recognized in the nine months ended September 30, 2019 compared to a loss on debt extinguishment of $54 million in the nine months ended September 30, 2018. During the nine months ended September 30, 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 nine months end September 30, 2018 CNX purchased $391 million of its 5.875% Senior notes due in April 2022 at an average price equal to 103.8% of the principal amount and redeemed the $500 million 8.00% Senior notes due in April 2023 at an average price equal to 106.0% of the principal amount. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q 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 5 - Acquisition and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) that occurred during the nine months ended September 30, 2018, CNX determined that the carrying value of the other intangible asset - customer relationships 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.

~~Income Taxes~~

The effective income tax rate was 22.3% for the nine months ended September 30, 2019 compared to 24.1% for the nine months ended September 30, 2018. The effective rate for the nine months ended September 30, 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state income taxes. The effective rate for the nine months ended September 30, 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%, as well as non-controlling interest. The benefits were offset by increases for both state income taxes and state valuation allowances.

~~See Note 6 - Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.~~

For the Nine Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
Total Company Earnings Before Income Tax $ 350
$ 993
$ (643 ) (64.8 )%
Income Tax Expense $ 78
$ 239
$ (161 ) (67.4 )%
Effective Income Tax Rate 22.3 % 24.1 % (1.8 )%

~~TOTAL E&P DIVISION ANALYSIS for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018:~~

The E&P division had earnings before income tax of $233 million for the nine months ended September 30, 2019 compared to earnings before income tax of $196 million for the nine months ended September 30, 2018. Variances by individual E&P segment are discussed below.

For the Nine Months Ended Difference to Nine Months Ended
September 30, 2019 September 30, 2018
(in millions) Marcellus Utica CBM
Other
Gas
Total E&P Marcellus Utica CBM
Other
Gas

Total
E&P
Natural Gas, NGLs and Oil Revenue $ 709
$ 208
$ 125
$ 2
$ 1,044
$ 118
$ (118 ) $ (28 ) $ (13 ) $ (41 )
Gain on Commodity Derivative Instruments 18
6
3
213
240
17
5
3
136
161
Purchased Gas Revenue —
—
—
64
64
—
—
—
25
25
Other Operating Income —
—
—
10
10
—
—
—
(12 ) (12 )
Total Revenue and Other Operating Income 727
214
128
289
1,358
135
(113 ) (25 ) 136
133
Lease Operating Expense 27
13
13
—
53
(7 ) (13 ) (4 ) (1 ) (25 )
Production, Ad Valorem, and Other Fees 11
4
5
—
20
(2 ) (1 ) —
(1 ) (4 )
Transportation, Gathering and Compression 325
24
29
—
378
97
(20 ) (8 ) (4 ) 65
Depreciation, Depletion and Amortization 186
105
52
7
350
25
(3 ) (7 ) (4 ) 11
Exploration and Production Related Other Costs —
—
—
15
15
—
—
—
6
6
Purchased Gas Costs —
—
—
62
62
—
—
—
25
25
Other Operating Expense —
—
—
60
60
—
—
—
9
9
Selling, General and Administrative Costs

—
—
—
95
95
—
—
—
13
13
Total Operating Costs and Expenses 549
146
99
239
1,033
113
(37 ) (19 ) 43
100
Interest Expense —
—
—
92
92
—
—
—
(4 ) (4 )
Total E&P Division Costs 549
146
99
331
1,125
113
(37 ) (19 ) 39
96
Earnings (Loss) Before Income Tax $ 178
$ 68
$ 29
$ (42 ) $ 233
$ 22
$ (76 ) $ (6 ) $ 97
$ 37

~~MARCELLUS SEGMENT~~

The Marcellus segment had earnings before income tax of $178 million for the nine months ended September 30, 2019 compared to earnings before income tax of $156 million for the nine months ended September 30, 2018.

For the Nine Months Ended September 30,
2019 2018 Variance
Percent
Change
Marcellus Gas Sales Volumes (Bcf) 245.3
176.0
69.3
39.4 %
NGLs Sales Volumes (Bcfe)* 22.5
23.9
(1.4 ) (5.9 )%
Condensate Sales Volumes (Bcfe)* 0.6
1.3
(0.7 ) (53.8 )%
Total Marcellus Sales Volumes (Bcfe)* 268.4
201.2
67.2
33.4 %

Average Sales Price - Gas (per Mcf) $ 2.58
$ 2.66
$ (0.08 ) (3.0 )%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.07
$ 0.01
$ 0.06
600.0 %
Average Sales Price - NGLs (per Mcfe)* $ 3.20
$ 4.67
$ (1.47 ) (31.5 )%
Average Sales Price - Condensate (per Mcfe)* $ 7.43
$ 8.91
$ (1.48 ) (16.6 )%

Total Average Marcellus Sales Price (per Mcfe) $ 2.71
$ 2.94
$ (0.23 ) (7.8 )%
Average Marcellus Lease Operating Expenses (per Mcfe) 0.10
0.17
(0.07 ) (41.2 )%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe) 0.04
0.06
(0.02 ) (33.3 )%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe) 1.21
1.13
0.08
7.1 %
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe) 0.70
0.81
(0.11 ) (13.6 )%
Total Average Marcellus Costs (per Mcfe) $ 2.05
$ 2.17
$ (0.12 ) (5.5 )%
Average Margin for Marcellus (per Mcfe) $ 0.66
$ 0.77
$ (0.11 ) (14.3 )%

* 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 Marcellus segment had natural gas, NGLs and oil revenue of $709 million for the nine months ended September 30, 2019 compared to $591 million for the nine months ended September 30, 2018. The $118 million increase was due to a 33.4% increase in total Marcellus sales volumes. The increase in sales volumes was primarily due to additional wells being turned in-line throughout 2018 and the first nine months of 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 an $0.08 per Mcf decrease in the average sales price for natural gas and a $1.47 per Mcfe decrease in the average NGL sales price, offset in part by a $0.06 per Mcf increase in the realized gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 185.9 Bcf of the Company's produced Marcellus gas sales volumes for the nine months ended September 30, 2019 at an average gain of $0.10 per Mcf. For the nine months ended September 30, 2018, these financial hedges represented approximately 148.9 Bcf at an average gain of $0.01 per Mcf.

Total operating costs and expenses for the Marcellus segment were $549 million for the nine months ended September 30, 2019 compared to $436 million for the nine months ended September 30, 2018. The increase in total dollars and decrease in unit costs for the Marcellus segment were due to the following items:

•Marcellus lease operating expenses were $27 million for the nine months ended September 30, 2019 compared to $34 million for the nine months ended September 30, 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 33.4% increase in total Marcellus sales volumes.~~

•Marcellus production, ad valorem, and other fees were $11 million for the nine months ended September 30, 2019 compared to $13 million for the nine months ended September 30, 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 decreased total dollars, along with the 33.4% increase in total Marcellus sales volumes.

•Marcellus transportation, gathering and compression costs were $325 million for the nine months ended September 30, 2019 compared to $228 million for the nine months ended September 30, 2018. The increase in total dollars was primarily related to the increase in production which resulted in 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 also related to new contracts, which began during the 2019 period, that give CNX the ability to move and sell natural gas outside of the Appalachian basin. These increases were offset by lower processing costs from a drier production mix. The increase in unit costs was driven by the increased total dollars described above.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $186 million for the nine months ended September 30, 2019 compared to $161 million for the nine months ended September 30, 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 our core development area in the current period. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

~~UTICA SEGMENT~~

The Utica segment had earnings before income tax of $68 million for the nine months ended September 30, 2019 compared to earnings before income tax of $144 million for the nine months ended September 30, 2018.

For the Nine Months Ended September 30,
2019 2018 Variance
Percent
Change
Utica Gas Sales Volumes (Bcf) 85.4
113.7
(28.3 ) (24.9 )%
NGLs Sales Volumes (Bcfe)* —
5.5
(5.5 ) (100.0 )%
Condensate Sales Volumes (Bcfe)* —
0.4
(0.4 ) (100.0 )%
Total Utica Sales Volumes (Bcfe)* 85.4
119.7
(34.3 ) (28.7 )%

Average Sales Price - Gas (per Mcf) $ 2.43
$ 2.61
$ (0.18 ) (6.9 )%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.07
$ 0.01
$ 0.06
600.0 %
Average Sales Price - NGLs (per Mcfe)* $ —
$ 4.60
$ (4.60 ) (100.0 )%
Average Sales Price - Condensate (per Mcfe)* $ —
$ 9.03
$ (9.03 ) (100.0 )%

Total Average Utica Sales Price (per Mcfe) $ 2.50
$ 2.73
$ (0.23 ) (8.4 )%
Average Utica Lease Operating Expenses (per Mcfe) 0.15
0.22
(0.07 ) (31.8 )%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe) 0.04
0.04
—
— %
Average Utica Transportation, Gathering and Compression Costs (per Mcfe) 0.28
0.37
(0.09 ) (24.3 )%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe) 1.23
0.90
0.33
36.7 %
Total Average Utica Costs (per Mcfe) $ 1.70
$ 1.53
$ 0.17
11.1 %
Average Margin for Utica (per Mcfe) $ 0.80
$ 1.20
$ (0.40 ) (33.3 )%

*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 $208 million for the nine months ended September 30, 2019 compared to $326 million for the nine months ended September 30, 2018. The $118 million decrease was due to the 28.7% decrease in total Utica sales volumes and a 6.9% 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 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 $0.18 per Mcf decrease in average gas sales price. Additionally, there was a $0.11 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. The decreases were partially offset by a $0.06 per Mcf increase in the realized gain on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 60.6 Bcf of the

Company's produced Utica gas sales volumes for the nine months ended September 30, 2019 at an average gain of $0.10 per Mcf. For the nine months ended September 30, 2018, these financial hedges represented approximately 78.7 Bcf at an average gain of $0.01 per Mcf.

Total operating costs and expenses for the Utica segment were $146 million for the nine months ended September 30, 2019 compared to $183 million for the nine months ended September 30, 2018. The decrease in total dollars and increase in unit costs for the Utica segment were due to the following items:

•Utica lease operating expense was $13 million for the nine months ended September 30, 2019 compared to $26 million for the nine months ended September 30, 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 decrease in unit costs was driven by the decrease in total dollars.

•Utica transportation, gathering and compression costs were $24 million for the nine months ended September 30, 2019 compared to $44 million for the nine months ended September 30, 2018. The $20 million decrease in total dollars and $0.09 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 $105 million for the nine months ended September 30, 2019 compared to $108 million for the nine months ended September 30, 2018. These amounts included depletion on a unit of production basis of $1.17 per Mcfe and $0.90 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 remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

~~COALBED METHANE (CBM) SEGMENT~~

The CBM segment had earnings before income tax of $29 million for the nine months ended September 30, 2019 compared to earnings before income tax of $35 million for the nine months ended September 30, 2018.

For the Nine Months Ended September 30,
2019 2018 Variance
Percent
Change
CBM Gas Sales Volumes (Bcf) 41.7
45.4
(3.7 ) (8.1 )%

Average Sales Price - Gas (per Mcf) $ 3.00
$ 3.37
$ (0.37 ) (11.0 )%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ 0.07
$ 0.01
$ 0.06
600.0 %

Total Average CBM Sales Price (per Mcf) $ 3.07
$ 3.37
$ (0.30 ) (8.9 )%
Average CBM Lease Operating Expenses (per Mcf) 0.30
0.37
(0.07 ) (18.9 )%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf) 0.13
0.12
0.01
8.3 %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) 0.70
0.82
(0.12 ) (14.6 )%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.24
1.29
(0.05 ) (3.9 )%
Total Average CBM Costs (per Mcf) $ 2.37
$ 2.60
$ (0.23 ) (8.8 )%
Average Margin for CBM (per Mcf) $ 0.70
$ 0.77
$ (0.07 ) (9.1 )%

The CBM segment had natural gas revenue of $125 million for the nine months ended September 30, 2019 compared to $153 million for the nine months ended September 30, 2018. The $28 million decrease was due to the 8.1% decrease in total CBM sales volumes and the 11.0% decrease in the average gas sales price. The decrease in CBM sales volumes was primarily due to normal well declines, as well as the sale of certain CBM assets that were sold along with the majority of CNX's shallow oil and gas assets in 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

The total average CBM sales price decreased $0.30 per Mcf due to a $0.37 decrease in average gas sales price, offset in part by a $0.06 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 29.6 Bcf of the Company's produced CBM sales volumes for the nine months ended September 30, 2019 at an average gain of $0.10 per Mcf. For the nine months ended September 30, 2018, these financial hedges represented approximately 34.8 Bcf at an average gain of $0.01 per Mcf.

Total operating costs and expenses for the CBM segment were $99 million for the nine months ended September 30, 2019 compared to $118 million for the nine months ended September 30, 2018. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:

•CBM lease operating expense was $13 million for the nine months ended September 30, 2019 compared to $17 million for the nine months ended September 30, 2018. The $4 million decrease was primarily due to reductions in contractor services, a decrease in repairs and maintenance costs, and a reduction in employee costs. The decrease in unit costs was also due to the decrease in total dollars.

•CBM transportation, gathering and compression costs were $29 million for the nine months ended September 30, 2019 compared to $37 million for the nine months ended September 30, 2018. The $8 million decrease in total dollars as well as the $0.12 per Mcf decrease in unit costs were primarily related to a decrease in electrical power expense as well as a decrease in contractor services.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $52 million for the nine months ended September 30, 2019 compared to $59 million for the nine months ended September 30, 2018. These amounts included depletion on a unit of production basis of $0.68 per Mcfe and $0.70 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

~~OTHER GAS SEGMENT~~

The Other Gas segment had a loss before income tax of $42 million for the nine months ended September 30, 2019 compared to a loss before income tax of $139 million for the nine months ended September 30, 2018.

For the Nine Months Ended September 30,
2019 2018 Variance Percent
Change
Other Gas Sales Volumes (Bcf) 0.3
4.6
(4.3 ) (93.5 )%
Oil Sales Volumes (Bcfe)* —
0.1
(0.1 ) (100.0 )%
Total Other Sales Volumes (Bcfe)* 0.3
4.7
(4.4 ) (93.6 )%

*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.

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, unrealized gain on commodity derivative instruments, exploration and production related other costs and other operational activity not assigned to a specific segment.

Other Gas sales volumes were primarily related to shallow oil and gas production. CNX sold substantially all of these assets on March 30, 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). There was $2 million of natural gas and oil revenue related to the Other Gas segment for the nine months ended September 30, 2019 compared to $15 million for the nine months ended September 30, 2018. The decrease in natural gas and oil revenue was due to the asset sale. Total operating costs and expenses related to these other gas sales volumes were $5 million for the nine months ended September 30, 2019 compared to $17 million for the nine months ended September 30, 2018.

The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $214 million as well as cash settlements paid of $1 million for the nine months ended September 30, 2019. For the nine months ended September 30, 2018, the Other Gas segment recognized an unrealized gain on commodity derivative instruments of $76 million as well as cash settlements received of $1 million. The unrealized gain on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis.

~~Purchased Gas~~

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were $64 million for the nine months ended September 30, 2019 compared to $39 million for the nine months ended September 30, 2018. Purchased gas costs were $62 million for the nine months ended September 30, 2019 compared to $37 million for the nine months ended September 30, 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 averages sales price.

For the Nine Months Ended September 30,
2019 2018 Variance Percent
Change
Purchased Gas Sales Volumes (in Bcf) 26.9
12.9
14.0
108.5 %
Average Sales Price (per Mcf) $ 2.39
$ 2.98
$ (0.59 ) (19.8 )%
Average Cost (per Mcf) $ 2.33
$ 2.89
$ (0.56 ) (19.4 )%

~~Other Operating Income~~

Other operating income was $10 million for the nine months ended September 30, 2019 compared to $22 million for the nine months ended September 30, 2018. The $12 million decrease was due to the following items:

For the Nine Months Ended September 30,
(in millions) 2019 2018 Variance Percent
Change
Water Income $ 1
$ 11
$ (10 ) (90.9 )%
Equity in Earnings of Affiliates 2
4
(2 ) (50.0 )%
Gathering Income 7
7
—
— %
Total Other Operating Income $ 10
$ 22
$ (12 ) (54.5 )%

~~Water income decreased $10 million due to nominal sales of freshwater to third-parties for hydraulic fracturing~~staff in the 2019 ~~period compared to the 2018~~ period.

~~Exploration and Production Related Other Costs~~

Exploration and production related other costs were $15 million for the nine months ended September 30, 2019 compared to $9 million for the nine months ended September 30, 2018. The $6 million increase was due to the following items:

For the Nine Months Ended September 30,
(in millions) 2019 2018 Variance
Percent
Change
Seismic Activity $ 6
$ —
$ 6
100.0 %
Lease Expiration Costs 5
4
1
25.0 %
Land Rentals 2
3
(1 ) (33.3 )%
Other 2
2
—
— %
Total Exploration and Production Other Costs $ 15
$ 9
$ 6
66.7 %

~~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 Expense


	For the Nine Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	54	$	43	$	11	25.6	%
Water Expense	1		1		—		—	%
Insurance Expense	2		2		—		—	%
Idle Equipment and Service Charges	8		8		—		—	%

Severance Expense	—		1		(1)		(100.0)	%
Other	6		6		—		—	%
Total Other Operating Expense	$	71	$	61	$	10	16.4	%

Other operating expense was $60 million for the nine months ended September 30, 2019 compared to $51 million for the nine months ended September 30, 2018. The $9 million increase was due to the following items:

For the Nine Months Ended September 30,
2019 2018 Variance Percent
Change
Unutilized Firm Transportation and Processing Fees $ 43
$ 29
$ 14
48.3 %
Idle Equipment and Service Charges 8
5
3
60.0 %
Insurance Expense 2
2
—
— %
Severance Expense 1
1
—
— %
Litigation Expense —
3
(3 ) (100.0 )%
Water Expense 1
5
(4 ) (80.0 )%
Other 5
6
(1 ) (16.7 )%
Total Other Operating Expense $ 60
$ 51
$ 9
17.6 %

•Unutilized ~~Firm Transportation~~firm transportation and ~~Processing Fees~~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 of $11 million in the period-to-period comparison was primarily due to ~~previously-acquired~~previously acquired capacity which was not utilized during the current period to transport the Company's flowing production or to process the Company’s ~~flowing~~wet natural gas production. The increase in unutilized capacity results in part from the temporary shut-in of a portion of CNX's liquids-rich Shirley-Pennsboro production in May and June of 2020 and due to the temporary shut-in of new

turn-in-line wells due to low natural gas prices. 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.

~~Idle Equipment~~

Gain on Asset Sales and ~~Service Charges primarily relate to the temporary idling~~Abandonments, net

A gain on asset sales 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 $3~~$22 million in the period-to-period comparison was primarily the result of the acceleration of five months of idle rig expense due to CNX terminating one of its drilling rig contacts early, as well as additional idle service expense related to the ~~Shaw 1G Utica Shale well that occurred~~sale of various non-core assets was recognized in ~~the first quarter of 2019.~~


•	~~Water Expense~~ ~~decrease~~d $4 million due to the associated costs related to the sales of freshwater to third-parties for hydraulic fracturing in the 2018 period in Total Other Operating Income above. There were nominal sales in the 2019 period.

~~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 $95 million for~~ the nine months ended September 30, ~~2019~~2020 compared to ~~$82~~a gain of $1 million ~~for~~in the nine months ended September 30, ~~2018. Refer to the discussion~~2019.

Loss (Gain) on Debt Extinguishment

A gain on debt extinguishment of ~~total company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders"of this Form 10-Q for a detailed cost explanation.~~

~~Interest Expense~~

~~Interest expense of $92~~$11 million was recognized in the nine months ended September 30, ~~2019~~2020 compared to ~~$96~~a loss on debt extinguishment of $8 million in the nine months ended September 30, 2018. The $4 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 $391 million purchase of the outstanding 5.875% senior notes due in April 2022 during2019. During the nine months ended September 30, ~~2018. Additionally, the Company~~2020, CNX purchased ~~$400~~$531 million of its ~~outstanding~~ 5.875% ~~senior~~Senior notes due in April 2022 ~~during~~at an average price equal to 97.5% of the ~~nine months ended September 30, 2019. These decreases were partially offset by a completed private offering of $500 million of 7.25% senior notes due March 2027 during~~principal amount. During the nine months ended September 30, 2019 ~~as well as additional borrowings on~~CNX purchased $400 million of its 5.875% Senior notes due in April 2022 at an average price equal to 101.5% of the ~~CNX credit facility.~~principal amount. See Note 119 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Other Expense


	For the Nine Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Other Income
Royalty Income	$	—	$	4	$	(4)	(100.0)	%
Right of Way Sales	2		4		(2)		(50.0)	%
Interest Income	2		2		—		—	%
Other	7		2		5		250.0	%
Total Other Income	$	11	$	12	$	(1)	(8.3)	%

Other Expense
Professional Services	$	6	$	2	$	4	200.0	%
Merger Related Costs	5		—		5		100.0	%
Bank Fees	9		9		—		—	%

Other Corporate Expense	3		4		(1)		(25.0)	%
Total Other Expense	$	23	$	15	$	8	53.3	%

Total Other Expense	$	12	$	3	$	9	(300.0)	%

~~TOTAL MIDSTREAM DIVISION ANALYSIS for~~•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 activity.

•Other income increased $5 million in the period-to-period comparison primarily due to the receipt of a severance tax refund related to a prior period in the nine months ended September 30, ~~2019 compared~~2020 (See Note 4- Income Taxes in the Notes to the ~~period January 3, 2018 through September 30, 2018:~~Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

~~CNX's Midstream Division's principal activity is~~•Merger-related costs consist of transaction costs directly attributable to 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~~Merger (See Note ~~5 -~~13- Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information)~~. CNX Gathering holds all~~, including financial advisory, legal service and other professional fees, which were recorded to Other Expense in the Consolidated Statements of Income.

•Professional services increased $4 million in the ~~interests in CNX Midstream GP LLC, which holds the general partner interest and~~period-to-period comparison primarily due to fees related to an agreement to eliminate CNXM's incentive distribution rights, or IDRs, in ~~CNXM. As a result~~January of ~~this transaction, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus~~2020, prior to the ~~Company began consolidating CNXM on January 3, 2018.~~Merger.

(in millions) For the nine months ended September 30, 2019 For the period January 3, 2018 through September 30, 2018 Variance
Midstream Revenue - Related Party $ 169
$ 117
$ 52
Midstream Revenue - Third Party 56
70
(14 )
Total Revenue $ 225
$ 187
$ 38

Transportation, Gathering and Compression $ 36
$ 36
$ —
Depreciation, Depletion and Amortization 25
24
1
Selling, General, and Administrative Costs
14
17
(3 )
Total Operating Costs and Expenses 75
77
(2 )
Other Expense 1
—
1
Loss (Gain) on Asset Sales and Abandonments 7
(2 ) 9
Interest Expense 23
17
6
Total Midstream Division Costs 106
92
14
Earnings Before Income Tax $ 119
$ 95
$ 24
Interest Expense


	For the Nine Months Ended September 30,
(in millions)	2020		2019		Variance		Percent Change
Total Interest Expense	$	133	$	114	$	19	16.7	%

~~Midstream Revenue~~

•The ~~table below summarizes volumes gathered by gas type:~~

For the nine months ended September 30, 2019 For the period January 3, 2018 through September 30, 2018 Variance
Dry Gas (BBtu/d) (*) 862
702
160
Wet Gas (BBtu/d) (*) 705
690
15
Other (BBtu/d) (*)(**) 196
12
184
Total Gathered Volumes 1,763
1,404
359

(*) 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,$19 million increase was primarily due to ~~any number of factors, volumes may be classified as “wet” in one period~~realized 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 $36 million for both~~unrealized losses on interest rate swap agreements during the nine months ended September 30, ~~2019~~2020. The addition of $345 million of convertible senior notes due 2026, the addition of the $125 million Cardinal States Facility and the $50 million CSG Holdings Facility all in the current period ~~January 3, 2018 through~~also contributed to the increase. These increases were offset in part by the purchase of $531 million of the outstanding 5.875% senior notes due in April 2022 during the nine months ended September 30, ~~2018, and are comprised of items directly related~~2020, as well as lower borrowings on the CNX credit facility. See Note 9 - Long-Term Debt in the Notes to the ~~cost~~Unaudited Consolidated Financial Statements in Item 1 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.

this Form 10-Q for additional information.

~~Selling, General and Administrative Expense~~

Income Taxes


	For the Nine Months Ended September 30,
(in millions)	2020			2019			Variance			Percent Change
Total Company (Loss) Earnings Before Income Tax	$	(867)		$	350		$	(1,217)		(347.7)	%
Income Tax (Benefit) Expense	$	(243)		$	78		$	(321)		(411.5)	%
Effective Income Tax Rate	28.0		%	22.3		%	5.7		%

~~SG&A expense is comprised of direct charges for the management and operation of CNXM assets. SG&A costs were $14 million~~

The effective income tax rate was 28.0% for the nine months ended September 30, ~~2019~~2020 compared to $17 million for the period January 3, 2018 through September 30, 2018. Refer to the discussion of total Company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders"~~of this Form 10-Q 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~~

During the nine months ended September 30, 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 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 September 30, 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 $23 million~~22.3% for the nine months ended September 30, ~~2019 compared to $17 million~~2019. The effective rate for the ~~period January 3, 2018 through~~nine months ended September 30, ~~2018.~~2020 and 2019 differs from the U.S. Federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state income taxes.

See Note 4 - Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

5754

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 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 and to provide required letters of ~~credit.~~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, including the current COVID 19 pandemic, some of which are beyond CNX’s control.

From time to time, CNX is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

~~Uncertainty~~CNX continuously reviews its liquidity and capital resources. If market conditions were to change, for instance due to the significant decline in oil prices or uncertainty created by the ~~financial markets brings additional potential risks~~COVID-19 pandemic, and our revenue was reduced significantly or operating costs were to ~~CNX. These risks include declines~~increase significantly, our cash flows and liquidity could be reduced.

As of September 30, 2020, CNX was 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 creditworthinesscompliance with all of its ~~customers~~debt covenants. After considering the current and ~~counterparties~~potential effect of the significant decline in oil prices, current and ~~manages credit exposure through payment terms, credit limits, prepayments~~expected future natural gas prices, and ~~security.~~uncertainty created by the COVID-19 pandemic on its operations, CNX ~~believes that~~currently expects to remain in compliance with its ~~current group of customers is financially sound and represents no abnormal business risk.~~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. The fair value of these contracts was a net ~~asset~~liability of ~~$313~~$95 million at September 30, ~~2019~~2020 and a net asset of ~~$99~~$406 million at December 31, ~~2018.~~2019. The Company has not experienced any issues of non-performance by derivative counterparties.

CNX frequently evaluates potential acquisitions. CNX has funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CNX on terms which CNX finds acceptable, or at all.

Cash Flows (in millions)


	For the Nine Months Ended September 30,
	2020		2019		Change
Cash Provided by Operating Activities	$	634	$	866	$	(232)
Cash Used in Investing Activities	$	(363)	$	(949)	$	586
Cash (Used in) Provided by Financing Activities	$	(131)	$	71	$	(202)

For the Nine Months Ended September 30,
2019 2018 Change
Cash Provided by Operating Activities $ 866
$ 690
$ 176
Cash Used in Investing Activities $ (949 ) $ (585 ) $ (364 )
Cash Provided by (Used in) Financing Activities $ 71
$ (572 ) $ 643

Cash flows from operating activities changed in the period-to-period comparison primarily due to the following items:

•Net income decreased ~~$482~~$897 million in the period-to-period comparison.

•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a ~~$181~~$473 million impairment of goodwill, a $62 million impairment of exploration and production properties, a $265 million change in deferred income taxes, a ~~$624~~$729 million net change in derivative instruments, a $25 million decrease in ~~gain on previously held equity interest,~~stock-based compensation expense, a ~~$148~~$21 million ~~decrease~~increase in gain on asset sales and abandonments, and a ~~$138 million net change in commodity derivative instruments, a $21~~$18 million increase in ~~stock-based compensation, a $19 million decrease in impairment of other intangible assets, and a $47 million decrease in~~ the ~~loss~~gain on debt extinguishment.

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

•Capital expenditures ~~increased $170~~decreased $569 million in the period-to-period comparison primarily due to ~~increased~~decreased expenditures in the ~~Utica and Marcellus~~ Shale ~~plays~~segment resulting from ~~increased~~decreased drilling and completions ~~activity as well as additional water~~activity. Gathering capital expenditures decreased due primarily to the ~~installation of new water pipelines. CNXM's capital expenditures increased due to additional spend in order to support both CNX's and third-party customer development plans.~~substantial build out that was completed during 2019.

•Proceeds from asset sales ~~decreased $486~~increased $17 million ~~primarily~~mainly 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,~~increased surface sales and ~~Noble counties along with the 2018 sale of our shallow~~ oil and gas ~~and CBM assets~~assignment sales in ~~Pennsylvania and West Virginia. See Note 5 - Acquisitions~~

the nine months ended September 30, 2020.

5855

~~and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.~~

In January 2018, CNX completed the Midstream Acquisition for a net payment of $299 million. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

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

•During the nine months ended September 30, 2020, CNX paid $519 million to purchase $531 million of senior notes due in 2022 at 97.7% of the principal amount. During the nine months ended September 30, 2019, CNX paid $406 million to ~~repurchase~~purchase $400 million of the senior notes due in 2022 at 101.5% of the principal amount. During the nine months ended September 30, 2018, CNX paid $530 million to repurchase all of the remaining senior notes due in 2023 at 106.0% of the principal amount as well as $405 million to repurchase $391 million of the senior notes due in 2022 at 103.8% of the principal amount. See Note 119 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

•In the nine months ended September 30, 2020, there were $31 million of net proceeds from the CNXM credit facility compared to $162 million of net proceeds during the nine months ended September 30, 2019.

•In the nine months ended September 30, 2020, there were $251 million of net payments on the CNX credit facility compared to $1 million of net proceeds during the nine months ended September 30, 2019.

•During the nine months ended September 30, ~~2019,~~2020, CNX ~~received proceeds~~closed on $200 million aggregate principal amount of ~~$500 million from the issuance of~~its senior notes due in ~~2027. During~~2027 at a price of 103.5% for cash proceeds of $207 million. These new $200 million senior notes due in 2027 were offered as additional notes to the previously issued $500 million senior notes due in 2027 during the nine months ended September 30, ~~2018, CNX received proceeds of $394 million from the issuance of CNXM's senior notes due in 2026.~~2019. See Note 119 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

•In the nine months ended September 30, 2020, there were $164 million of net proceeds from the Cardinal States Gathering LLC and CSG Holdings II LLC non-revolving credit facilities. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

•During the nine months ended September 30, 2020, CNX received proceeds of $335 million from the issuance of the Convertible Notes. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

•During the nine months ended September 30, 2020, CNX paid $36 million for capped call transactions related to the issuance of the Convertible Notes. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

•In the nine months ended September 30, 2019, CNX repurchased $117 million of its common stock on the open market compared to ~~$294 million~~no purchases in the nine months ended September 30, ~~2018.~~2020.

~~In the nine months ended September 30, 2019, there was $1 million of net proceeds from the CNX credit facility and $439 million of proceeds in the 2018 period.~~

In the nine months ended September 30, 2019, there were $162 million of net proceeds from the CNXM credit facility compared to $106 million of net payments during the nine months ended September 30, 2018.

~~In the nine months ended September 30, 2019, there were $10 million in debt~~•Debt issuance and financing fees ~~compared~~increased $5 million primarily due to ~~$20 million during~~ the ~~nine months ended September 30, 2018.~~fees associated with the borrowings on the Cardinal States Gathering LLC and CSG Holdings II LLC non-revolving credit facilities as well as the issuance of the Convertible Notes.

~~In the nine months ended September 30, 2019, there were $47 million in distributions to CNXM unitholders, compared to $41 million during the nine months ended September 30, 2018.~~

The following is a summary of the Company's significant contractual obligations at September 30, ~~2019~~2020 (in thousands):


												Payments due by Year
												Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Purchase Order Firm Commitments	$	7,670	$	2,185	$	485	$	—	$	10,340	Purchase Order Firm Commitments	$	806	$	1,131	$	—	$	—	$	1,937
Gas Firm Transportation and Processing	244,865		486,838		412,475		1,113,008		2,257,186		Gas Firm Transportation and Processing	241,980		427,931		369,444		930,189		1,969,544
Long-Term Debt	—		895,415		859,200		895,187		2,649,802		Long-Term Debt	22,488		411,411		798,992		1,384,511		2,617,402
Interest on Long-Term Debt	147,753		297,695		173,943		129,626		749,017		Interest on Long-Term Debt	132,249		239,504		186,647		101,764		660,164
Finance Lease Obligations	7,203		8,881		519		—		16,603		Finance Lease Obligations	7,419		2,049		273		—		9,741
Interest on Finance Lease Obligations	933		498		94		—		1,525		Interest on Finance Lease Obligations	396		63		19		—		478
Operating Lease Obligations	65,061		88,077		7,574		26,863		187,575		Operating Lease Obligations	52,032		35,436		7,369		23,375		118,212
Interest on Operating Lease Obligations	7,714		7,400		3,326		5,171		23,611		Interest on Operating Lease Obligations	4,101		4,054		2,924		3,808		14,887
Long-Term Liabilities—Employee Related (a)	1,841		3,934		4,399		25,344		35,518		Long-Term Liabilities—Employee Related (a)	1,860		3,999		4,633		31,274		41,766
Other Long-Term Liabilities (b)	207,067		7,625		8,325		18,173		241,190		Other Long-Term Liabilities (b)	281,530		10,000		10,000		41,761		343,291
Total Contractual Obligations (c)	$	690,107	$	1,798,548	$	1,470,340	$	2,213,372	$	6,172,367	Total Contractual Obligations (c)	$	744,861	$	1,135,578	$	1,380,301	$	2,516,682	$	5,777,422

_________________________


~~(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 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.~~

(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.

5956

Debt

At September 30, ~~2019,~~2020, CNX had total long-term debt of ~~$2,650~~$2,617 million, including the current portion of long-term debt of $22 million and excluding unamortized debt issuance costs. This long-term debt consisted of:

•An aggregate principal amount of ~~$895~~$700 million of ~~5.875% Senior Notes~~7.25% senior notes due in ~~April 2022~~March 2027 plus $1$7 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 $613 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.~~ 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.~~CNXM or CSG Holdings III LLC (or its subsidiaries).

•An aggregate principal amount of $410 million in outstanding borrowings under the CNX Revolving Credit Facility.

•An aggregate principal amount of $400 million of 6.50% ~~Senior Notes~~senior notes due in March 2026 issued by CNXM, less $5$4 million of unamortized bond discount. Interest on the notes is payable March 15 and September 15 of each year. Payment of the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of these notes.

•An aggregate principal amount of ~~$246~~$363 million of 5.875% senior notes due in April 2022 plus a nominal 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 (or its subsidiaries or general partner) or CSG Holdings III LLC (or its subsidiaries).

•An aggregate principal amount of $345 million of 2.25% senior notes due in May 2026, unless earlier redeemed, repurchased, or converted, less $112 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 (or its subsidiaries).

•An aggregate principal amount of $343 million in outstanding borrowings under the CNXM revolver. CNX is not a guarantor of CNXM's revolving credit facility.

•An aggregate principal amount of $119 million in outstanding borrowings under the Cardinal States Gathering Company Credit Facility, less $1 million of unamortized discount. Interest and a portion of the obligation are paid quarterly.

•An aggregate principal amount of $47 million in outstanding borrowings under the CSG Holdings II LLC Credit Facility, less a nominal unamortized discount. Interest and a portion of the obligation are paid quarterly.

Total Equity and Dividends

CNX had total equity of ~~$5,222~~$4,270 million at September 30, ~~2019~~2020 compared to ~~$5,082~~$4,962 million at December 31, ~~2018.~~2019. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

On September 28, 2020, the Merger of CNXM was completed (See Note 13 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q 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. 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. The net leverage ratio was ~~2.45~~2.34 to 1.00 at September 30, ~~2019.~~2020. The Credit Facility does not permit dividend payments in the event of default. The indentures to the 5.875% ~~Senior Notes~~senior notes due in April 2022 and the 7.25% ~~Senior Notes~~senior notes due in March 2027 limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the nine months ended September 30, ~~2019.~~2020.

On October 16, 2019 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 $0.4001 per unit with respect to the third quarter of 2019. The distribution will be made on November 12, 2019 to unitholders of record as of the close of business on November 5, 2019. The distribution, which equates to an annual rate of $1.6004 per unit, represents an increase of 3.5% over the prior quarter, and an increase of 15% over the distribution paid with respect to the third quarter of 2018.

Off-Balance Sheet Transactions

CNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CNX uses a combination of

surety bonds, corporate guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected in the Consolidated Balance Sheet at September 30, ~~2019.~~2020. Management believes these items will expire without being funded. See Note 1310 - Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CNX.

Forward-Looking Statements

We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” "will," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe a strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•prices for natural gas and natural gas liquids are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand for our products, weather and the price and availability of alternative fuels;

•our dependence on gathering, processing and transportation facilities and other midstream facilities owned by ~~CNX Midstream Partners LP (NYSE: CNXM) (CNXM) and others;~~third-parties;

•uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates;

•the high-risk nature of drilling, developing and ~~developing~~operating natural gas wells;

•our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their development or drilling;

•challenges associated with strategic determinations, including the allocation of capital and other resources to strategic opportunities;

•the substantial capital expenditures required for our development and exploration projects, as well as ~~CNXM’s~~ midstream system ~~development, require substantial capital expenditures;~~development;

•the impact of potential, as well as any adopted, environmental regulations, including ~~any~~those relating to greenhouse gas ~~emissions on our operating costs as well as on the market for natural gas and for our securities;~~emissions;

•environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;

our operations are subject to operating risks that could increase our operating expenses and decrease our production levels which could adversely affect our results of operation and our operations are also subject to hazards and any losses or liabilities we suffer from hazards, which occur in our operations may not be fully covered by our insurance policies;

•decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials in sufficient quantities or at reasonable costs to support our operations;

•if natural gas prices decrease or drilling efforts are unsuccessful, we may be required to record write-downs of our proved natural gas properties;

•the availability of storage capacity for refined products such as crude, and refinery inputs including condensate, c5+ and butane;

•changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in our stock price, weighted-average cost of capital, terminal growth rates and industry multiples, could cause goodwill and other intangible assets we hold to become impaired and result in material non-cash charges to earnings;

•a loss of our competitive position because of the competitive nature of the natural gas industry, consolidation within the industry or overcapacity in the industry adversely affecting our ability to sell our products and midstream ~~services, which could impair our profitability;~~services;

•deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions;

•the impact of outbreaks of communicable diseases such as COVID-19 on business activity, the Company’s operations and national and global economic conditions, generally;

•hedging activities may prevent us from benefiting from price increases and may expose us to other risks;

•existing and future government laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations;

•significant costs and liabilities may be incurred as a result of pipeline operations and related increase in the regulation of gas gathering pipelines;

•our ability to find adequate water sources for our use in shale gas drilling and production operations, or our ability to dispose of, transport or recycle water used or removed in connection with our gas operations at a reasonable cost and within applicable environmental rules;

•failure to successfully estimate the rate of decline or existing reserves or to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;

•risks associated with our ~~debt;~~current long-term debt obligations;

•a decrease in our borrowing base, which could decrease for a variety of reasons including lower natural gas prices, declines in natural gas proved reserves, asset sales and lending requirements or regulations;

•changes in federal or state income tax laws;

•cyber-incidents could have a material adverse effect on our business, financial condition or results of operations;

•construction of new gathering, compression, dehydration, treating or other midstream assets ~~by CNXM~~ may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks;

•our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel;

•terrorist activities could materially ~~and~~ adversely affect our business and results of operations;

•we may operate a portion of our business with one or more joint venture partners or in circumstances where we are not the operator, which may restrict our operational and corporate flexibility and we may not realize the benefits we expect to realize from a joint venture;

•acquisitions and divestitures, we anticipate may not occur or produce anticipated benefits;

•the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the Exchange Act;

•there is no guarantee that we will continue to repurchase shares of our common stock under our current or any future share repurchase program at levels undertaken previously or at all;

•negative public perception regarding our industry could have an adverse effect on our operations;

•CONSOL Energy may not be able to satisfy its indemnification obligations in the future and such indemnities may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy will be allocated responsibility;

•Risks associated with our Convertible Notes, including the ~~separation~~potential impact that the Convertible Notes may have on our reported financial results, potential dilution, our ability to raise funds to repurchase the Convertible Notes, and that provisions of ~~CONSOL Energy~~the Convertible Notes could ~~result~~delay or prevent a beneficial takeover of the Company;

•the potential impact of the capped call transaction undertaken in ~~substantial~~tandem with the Convertible Notes issuance, including counterparty risk;

•the possibility that Company and CNXM may be the targets of securities class actions and derivative lawsuits;

•the risk that cost savings, tax ~~liability;~~benefits and any other synergies from the Merger may not be fully realized or may take longer to realize than expected;

•the impact and outcome of pending and future litigation, including litigation, relating to the Merger; and

•certain other factors ~~discussed~~addressed in this report.

Although forward-looking statements reflect our good faith beliefs at the time they are made, they involve known and unknown risks, uncertainties and other factors. For more information concerning factors that could cause actual results to differ materially from those conveyed in the ~~Company's 2018~~forward-looking statements, including, among others, that our business plans may change as circumstances warrant, please refer to the “Risk Factors” and “Forward-Looking Statements” sections of our Annual Report on Form 10-K ~~under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file at~~for the year ended December 31, 2019 filed with the Securities and ~~Exchange Commission.~~Commission on February 10, 2020 and subsequent Quarterly Reports on Form 10-Q. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.


~~ITEM 3.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In addition to the risks inherent in operations, CNX is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CNX's exposure to the risks of changing commodity prices, interest rates and foreign exchange rates.

CNX is exposed to market price risk in the normal course of selling natural ~~gas.~~gas and liquids. CNX uses fixed-price contracts, options and derivative commodity instruments (over-the-counter swaps) to minimize exposure to market price volatility in the sale of natural gas. Under our risk management policy, it is not our intent to engage in derivative activities for speculative purposes. Typically, CNX “sells” swaps under which it receives a fixed price from counterparties and pays a floating market price. During the second quarter of 2020, CNX purchased, rather than sold, financial swaps for the period May through November of 2020 under which CNX will pay a fixed price to and receive a floating price from its hedge counterparties.

CNX has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. The Company's market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

CNX believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates our exposure to material risks. The use of derivative instruments without other risk assessment procedures could materially affect the Company's results of operations depending on market prices; however, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity due to our risk assessment procedures and internal controls.

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX's ~~2018~~2019 Annual Report on Form 10-K.

At September 30, ~~2019~~2020 our open gas derivative instruments were in a net liability position with a fair value of $95 million, and at December 31, ~~2018,~~2019 our open gas derivative instruments were in a net asset position with a fair value of ~~$313 million and $99 million, respectively.~~$406 million. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at September 30, ~~2019~~2020 and December 31, ~~2018.~~2019. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by ~~$411~~$393 million and ~~$427~~$383 million at September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by ~~$428~~$389 million and ~~$453~~$402 million at September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, respectively.

CNX's interest expense is sensitive to changes in the general level of interest rates in the United States. The Company uses derivative instruments to manage risk related to interest rates. At September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, CNX had ~~$1,798~~$1,700 million and ~~$1,703~~$1,797 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $10 million and $9 million, respectively. At September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, CNX had ~~$859~~$910 million and ~~$696~~$973 million, respectively, of debt outstanding under variable-rate ~~instruments.~~instruments, including unamortized debt issuance costs of $7 million at September 30, 2020. CNX’s primary exposure to market risk for changes in interest rates relates to our Credit Facility, under which there were ~~$613~~$410 million of borrowings at September 30, ~~2019~~2020 and ~~$612~~$661 million at December 31, ~~2018, and~~2019, CNXM's revolving credit facility, under which there were ~~$246~~$343 million of borrowings at September 30, ~~2019~~2020 and ~~$84~~$312 million at December 31, ~~2018.~~2019, and the Cardinal States Gathering LLC and CSG Holdings II LLC Credit Agreements, under which there were $166 million of borrowings at September 30, 2020. A hypothetical 100 basis-point increase in the average rate for CNX's ~~and CNXM's revolving credit facilities~~variable-rate instruments would decrease pre-tax future earnings as of September 30, ~~2019~~2020 and December 31, ~~2018~~2019 by $9 million and $7$10 million, respectively, on an annualized basis.

All of the Company’s transactions are denominated in U.S. dollars and, as a result, it does not have material exposure to currency exchange-rate risks.

Natural Gas Hedging Volumes

As of October ~~9, 2019,~~8, 2020, our hedged volumes for the periods indicated are as follows:


	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2020 Fixed Price Volumes*
Hedged Bcf	N/A		N/A		N/A		130.2		130.2
Weighted Average Hedge Price per Mcf	N/A		N/A		N/A		$	2.50	$	2.50
2021 Fixed Price Volumes
Hedged Bcf	120.6		110.9		112.8		115.6		459.1**
Weighted Average Hedge Price per Mcf	$	2.56	$	2.42	$	2.42	$	2.48	$	2.47
2022 Fixed Price Volumes
Hedged Bcf	99.5		97.1		98.1		95.3		390.0
Weighted Average Hedge Price per Mcf	$	2.37	$	2.30	$	2.30	$	2.28	$	2.32
2023 Fixed Price Volumes
Hedged Bcf	67.2		68.0		68.7		68.7		272.6
Weighted Average Hedge Price per Mcf	$	2.26	$	2.24	$	2.24	$	2.25	$	2.24
2024 Fixed Price Volumes
Hedged Bcf	64.2		61.3		61.9		61.9		249.3
Weighted Average Hedge Price per Mcf	$	2.34	$	2.28	$	2.28	$	2.28	$	2.30
2025 Fixed Price Volumes
Hedged Bcf	22.0		22.2		22.5		22.4		89.1
Weighted Average Hedge Price per Mcf	$	2.10	$	2.10	$	2.10	$	2.10	$	2.10

For the Three Months Ended
March 31, June 30, September 30, December 31, Total Year
2019 Fixed Price Volumes
Hedged Bcf N/A N/A N/A 115.8
115.8
Weighted Average Hedge Price per Mcf N/A N/A N/A $ 2.66
$ 2.66
2020 Fixed Price Volumes
Hedged Bcf 121.3
123.6
126.4
121.5
489.6*
Weighted Average Hedge Price per Mcf $ 2.68
$ 2.49
$ 2.49
$ 2.52
$ 2.54
2021 Fixed Price Volumes
Hedged Bcf 104.5
105.7
106.9
105.2
422.3
Weighted Average Hedge Price per Mcf $ 2.40
$ 2.40
$ 2.40
$ 2.39
$ 2.40
2022 Fixed Price Volumes
Hedged Bcf 68.6
69.3
70.1
70.1
278.1
Weighted Average Hedge Price per Mcf $ 2.45
$ 2.45
$ 2.45
$ 2.43
$ 2.44
2023 Fixed Price Volumes
Hedged Bcf 35.7
36.1
36.4
36.4
144.6
Weighted Average Hedge Price per Mcf $ 2.28
$ 2.28
$ 2.28
$ 2.28
$ 2.28
2024 Fixed Price Volumes
Hedged Bcf 30.5
30.6
30.9
30.9
122.9
Weighted Average Hedge Price per Mcf $ 2.45
$ 2.45
$ 2.45
$ 2.45
$ 2.45
*Excludes purchased swaps. The Company's purchased swaps are as follows:


	For the Three Months Ended
	December 31, 2020
Hedged Bcf	6.2
Weighted Average Fixed Price per Mcf	$	1.75

**Quarterly volumes do not add to annual volumes inasmuch as a discrete condition in individual quarters, where basis hedge volumes exceed NYMEX hedge volumes, does not exist for the year taken as a whole.


~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~

ITEM 4.CONTROLS AND PROCEDURES

Disclosure controls and procedures. CNX, under the supervision and with the participation of its management, including CNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CNX’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, ~~2019~~2020 to ensure that information required to be disclosed by CNX in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CNX in such reports is accumulated and communicated to CNX’s management, including CNX’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over financial reporting that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II: OTHER INFORMATION


~~ITEM 1.~~	~~LEGAL PROCEEDINGS~~

ITEM 1.LEGAL PROCEEDINGS

The first and second paragraph of Note ~~13—~~10—Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q is incorporated herein by reference.

Environmental Proceedings

From time to time, CNX and federal, state, and local regulatory agencies that oversee CNX’s activities enter into agreements regarding notices of noncompliance. With respect to the subsurface pressure anomaly experienced at one of our Utica wells in January 2019, CNX and the Pennsylvania Department of Environmental Protection executed a consent order and agreement, which was immaterial to CNX’s financial statements.

ITEM 1A. RISK FACTORS

CNX is also subject to ~~certain~~additional risks and hazards due to the nature of the business activities it conducts. For a discussion of these risks, see “Item 1A. Risk Factors” in CNX's ~~2018~~2019 Annual Report on Form 10-K as filed with the SEC on February 7, 10, 2020 ("2019 ~~("2018~~ Form 10-K"). and in our Quarterly Reports on Form 10Q for the quarters ended March 31, 2020 and June 30, 2020. The risks described ~~in the 2018 Form 10-K~~ could materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. ~~There have been no material changes to the risks described in the 2018 Form 10-K.~~ CNX may experience additional risks and uncertainties not currently known; or, as a result of developments occurring in the future, conditions that are currently deemed to be immaterial may also materially and adversely affect CNX's business, financial condition, cash flows, and results of operations.

Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.

The recent outbreak of the coronavirus pandemic (COVID-19) has affected, and may materially and adversely affect, our business, operating and financial results and liquidity. The severity, magnitude and duration of the current COVID-19 outbreak remains uncertain, but continues to be rapidly changing and hard to predict. While the full impact of this virus and the long-term worldwide reaction to it and impact from it remains unknown at this time, government reaction to the pandemic and restrictions and limitations applied by the government as a result, continued widespread growth in infections, travel restrictions, quarantines, or site closures as a result of the virus could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, lead to disruptions in our supply chain (including necessary contractors), lead to a disruption in our resource acquisition or permitting activities and cause disruption in our relationship with our customers. Additionally, the COVID-19 outbreak has significantly impacted economic activity and markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:

•our revenue may be reduced if the outbreak results in an economic downturn or recession, as many experts predict, to the extent it leads to a prolonged decrease in the demand for natural gas and liquefied natural gas ("LNG") and, to a lesser extent, NGLs and oil;

•our operations may be disrupted or impaired, thus lowering our production level, if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the outbreak;

•the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGLs and oil, may be disrupted or suspended in response to containing the outbreak, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties; and

•the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to find attractive asset monetization opportunities and successfully execute our plan to deleverage our business on the timeframe previously anticipated or at all; for example, the market value of the assets to be monetized may be reduced and the financial condition or prospects of prospective purchasers and other counterparties, and such parties’ access to financing on acceptable terms, may be adversely affected.

In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we may experience difficulty accessing the capital or financing needed to fund our exploration and production operations, which have substantial capital requirements, or refinance our upcoming maturities on satisfactory terms or at all. We typically fund our capital expenditures with existing cash and cash generated by operations (which is subject to a number of variables, including many beyond our control) and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.

To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019, such as those relating to our financial performance and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, LNG, NGLs and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic. Any of these outcomes could have a material adverse effect on our business, operations, financial results and liquidity.

The accounting method for convertible debt securities that may be settled in cash, such as the Convertible Notes, could have a material effect on our reported financial results.

Under Accounting Standards Codification 470-20, Debt with Conversion and Other Options (“ASC 470-20”), an entity must separately account for the liability and equity components of the convertible debt instruments (such as the Convertible Notes) that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer’s economic interest cost. The effect of ASC 470-20 on the accounting for the Convertible Notes is that the equity component is required to be included in the Capital in Excess of Par Value section of Stockholders’ Equity on our Consolidated Balance Sheet at the issuance date and the value of the equity component would be treated as debt discount for purposes of accounting for the debt component of the Convertible Notes. As a result, we will be required to record non-cash interest expense through the amortization of the excess of the face amount over the carrying amount of the expected life of the Convertible Notes. We will report larger net losses (or lower net income) in our financial results because ASC 470-20 will require interest to include both the amortization of the debt discount and the instrument’s cash coupon interest rate, which could adversely affect our reported or future financial results, the trading price of our common stock and the trading price of the Convertible Notes.

In addition, under certain circumstances, convertible debt instruments (such as the Convertible Notes) that may be settled entirely or partly in cash may be accounted for utilizing the treasury stock method, the effect of which is that the shares issuable upon conversion of such Convertible Notes are not included in the calculation of diluted earnings per share except to the extent that the conversion value of such Convertible Notes exceeds their principal amount. Under the treasury stock method, for diluted earnings per share purposes, the transaction is accounted for as if the number of shares of common stock that would be necessary to settle such excess, if we elected to settle such excess in shares, are included in the denominator for purposes of calculating diluted earnings per share. We cannot be sure that the accounting standards in the future will continue to permit the use of the treasury stock method. If we are unable or otherwise elect not to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, then our diluted earnings per share could be adversely affected.

The capped call transactions may affect the value of the Convertible Notes and our common stock.

In connection with the pricing of the Convertible Notes, we entered into capped call transactions with certain financial institutions. The capped call transactions are expected generally to reduce the potential dilution to our common stock upon any conversion of the Convertible Notes and/or offset any potential cash payments we are required to make in excess of the principal amount of converted Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap.

In connection with establishing their initial hedges of the capped call transactions, these financial institutions or their respective affiliates purchased shares of our common stock and/or entered into various derivative transactions with respect to our common stock concurrently with or shortly after the pricing of the Convertible Notes. These financial institutions or their respective affiliates may modify their hedge positions by entering into or unwinding various derivatives with respect to our common stock and/or purchasing or selling our common stock or other securities of ours in secondary market transactions following the pricing of the Convertible Notes and prior to the maturity of the Convertible Notes (and are likely to do so during any observation period related to a conversion of Convertible Notes). This activity could also cause or avoid an increase or a decrease in the market price of our common stock or the Convertible Notes.

The potential effect, if any, of these transactions and activities on the price of our common stock or the Convertible Notes will depend in part on market conditions and cannot be ascertained at this time. Any of these activities could adversely affect the value of our common stock.

We are subject to counterparty risk with respect to the capped call transactions.

The counterparties to the capped call transactions are financial institutions or affiliates of financial institutions, and we will be subject to the risk that they might default under the capped call transactions. Our exposure to the credit risk of the counterparties will not be secured by any collateral. Global economic conditions have from time to time resulted in the actual or perceived failure or financial difficulties of many financial institutions. If a counterparty becomes subject to insolvency proceedings, with respect to such option counterparty’s obligations under the relevant capped call transaction, we will become an unsecured creditor in those proceedings with a claim equal to our exposure at that time under our transactions with that counterparty. Our exposure will depend on many factors, but, generally, the increase in our exposure will be positively correlated to the increase in the market price and in the volatility of our common stock. In addition, upon a default by a counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any counterparty.

Conversion of the Convertible Notes may dilute the ownership interest of existing stockholders, including holders who had previously converted their Convertible Notes, or may otherwise depress the price of our common stock.

The conversion of some or all of the Convertible Notes will dilute the ownership interests of existing stockholders to the extent we deliver shares of our common stock upon conversion of any of the Convertible Notes and the potential dilution is not reduced or offset by the capped call transactions we entered into. The Convertible Notes may become convertible at the option of holders prior to their scheduled terms under certain circumstances. Any sales in the public market of the common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the Convertible Notes may encourage short selling by market participants because the conversion of the Convertible Notes could be used to satisfy short positions, or anticipated conversion of the Convertible Notes into shares of our common stock could depress the price of our common stock.

We may be unable to raise the funds necessary to repurchase the Convertible Notes for cash following a fundamental change, or to pay any cash amounts due upon conversion, and our other indebtedness may limit our ability to repurchase the Convertible Notes or pay cash upon their conversion.

Noteholders may, subject to a limited exception, require us to repurchase their Convertible Notes following a fundamental change at a cash repurchase price generally equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any. In addition, upon conversion, we will satisfy part or all of our conversion obligation in cash unless we elect to settle conversions solely in shares of our common stock. We may not have enough available cash or be able to obtain financing at the time we are required to repurchase the Convertible Notes or pay the cash amounts due upon conversion. In addition, applicable law, regulatory authorities and the agreements governing our other indebtedness, may restrict our ability to repurchase the Convertible Notes or pay the cash amounts due upon conversion. Our inability to satisfy our obligations under the Convertible Notes could harm our reputation and affect the trading price of our common stock.

Our failure to repurchase the Convertible Notes or to pay the cash amounts due upon conversion when required will constitute a default under the indenture. A default under the indenture or the occurrence of the fundamental change itself could also lead to a default under agreements governing our other indebtedness, which may result in that other indebtedness becoming immediately payable in full. We may not have sufficient funds to satisfy all amounts due under the other indebtedness and the Convertible Notes.

The conditional conversion feature of the Convertible Notes, if triggered, may adversely affect our financial condition and operating results.

In the event the conditional conversion feature of the Convertible Notes is triggered, holders of Convertible Notes will be entitled to convert their Convertible Notes at any time during specified periods at their option. If one or more holders elect to convert their Convertible Notes, unless we elect to satisfy our conversion obligation by delivering solely common stock (other than paying cash in lieu of delivering any fractional shares), we would be required to settle a portion or all of our conversion obligation through the payment of cash, which could adversely affect our liquidity.

Provisions of our Convertible Notes could delay or prevent an otherwise beneficial takeover of us.

Certain provisions of our Convertible Notes and the indenture governing the Convertible Notes could make a third-party attempt to acquire us more difficult or expensive. For example, if a takeover constitutes a “fundamental change” (as defined in the indenture), then noteholders will have the right to require us to repurchase their Convertible Notes for cash. In addition, if a takeover constitutes a “make-whole fundamental change” (as defined in the indenture), then we may be required to temporarily increase the conversion rate. In either case, and in other cases, our obligations under the Convertible Notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us, including in a transaction that noteholders or holders of our common stock may view as favorable.

In connection with the separation of our coal business, CONSOL Energy has agreed to indemnify us for certain liabilities, and we have agreed to indemnify CONSOL Energy for certain liabilities. If we are required to pay under these indemnities to CONSOL Energy, our financial results could be negatively impacted. The CONSOL Energy indemnity may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy has been allocated responsibility, and CONSOL Energy may not be able to satisfy its indemnification obligations in the future.

Pursuant to the Separation and Distribution Agreement and certain other agreements with CONSOL Energy, CNX and CONSOL Energy have agreed to indemnify the other for certain liabilities in each case for uncapped amounts.

We remain liable as a guarantor on certain liabilities that were assumed by CONSOL Energy in connection with the separation. The estimated value of these guarantees was approximately $166 million as of September 30, 2020. Although CONSOL Energy agreed to indemnify us to the extent that we are called upon to pay any of these liabilities, there is no assurance that CONSOL Energy will satisfy its obligations to indemnify us in these situations.

For example, we could be liable for liabilities assumed by Murray Energy and its subsidiaries (Murray Energy) in connection with the disposition of certain mines to Murray Energy in 2013 in the event that both Murray Energy and CONSOL Energy are unable to satisfy those liabilities.

Indemnities that CNX may be required to provide CONSOL Energy are not subject to any cap, may be significant and could negatively impact our business. Third parties could also seek to hold us responsible for any of the liabilities that CONSOL Energy has agreed to retain, including in respect of certain statutory obligations related to, among others, health and environmental matters. For example, see disclosure in Note 10 Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for information regarding a lawsuit filed by the UMWA 1992 Benefit Plan against CNX and CONSOL Energy in May 2020.

Any amounts we are required to pay pursuant to these indemnification obligations and other liabilities could require us to divert cash that would otherwise have been used in furtherance of our operating business. Further, the indemnity from CONSOL Energy may not be sufficient to protect us against the full amount of such liabilities, and CONSOL Energy may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from CONSOL Energy any amounts for which we are held liable, CNX may be temporarily required to bear such losses. Each of these risks could negatively affect our business, results of operations and financial condition.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~The following table sets forth repurchases~~There were no issuer purchases of equity securities in the third quarter of fiscal year 2020. Under our ~~common~~current stock ~~during the three months ended September 30, 2019:~~

ISSUER PURCHASES OF EQUITY SECURITIES
(a) (b) (c) (d)
Period
Total Number of Shares Purchased (1)
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (000's omitted)
July 1, 2019-
July 31, 2019 —
$ —
—
$ 156,143
August 1, 2019-
August 31, 2019 —
$ —
—
$ 156,143
September 1, 2019-
September 30, 2019 1,000,000
$ 7.68
1,000,000
$ 148,466
Total 1,000,000

~~(1)~~ ~~Includes shares withheld from employees to satisfy minimum tax withholding obligations associated with the vesting of restricted stock during the period.~~

~~(2)~~ ~~Shares repurchased as part of the Company’s current $750 million share~~ repurchase program, ~~authorized by the~~which is not subject to an expiration date, CNX's Board of Directors ~~on October~~has approved up to $750 million of repurchases. As of September 30, ~~2017~~2020, approximately $148.5 million remained available under the stock repurchase program. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and ~~subsequently amended from time to time (See~~the Board may modify, suspend, or discontinue its authorization of the program at any time. See Note 1815 - Stock Repurchase in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for more ~~information), which is not subject~~information.

See Part III. Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" included in CNX Resources Corporation's Annual Report on Form 10-K as filed with the Securities and Exchange Commission on February 10, 2020 for information relating to ~~an expiration date.~~CNX's equity compensation plans.

ITEM 6.EXHIBITS


~~ITEM 6.~~	~~EXHIBITS~~



10.1*2.1	Agreement and Plan of Merger, dated as of July 26, 2020, by and among CNX Resources Corporation, CNX Resources Holdings LLC, CNX Midstream GP LLC and CNX Midstream Partners LP (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (file number 001-14901) filed on July 27, 2020).
~~Change in Control Severance~~10.1	Support Agreement, dated ~~October 28, 2019, between the~~as of July 26, 2020, by and among CNX Midstream Partners LP, CNX Gas Company LLC and ~~Chad A. Griffith.~~CNX Gas Holdings, Inc. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (file number 001-14901) filed on July 27, 2020).
10.2*10.2	~~Change in Control Severance~~Purchase Agreement, dated ~~October 28, 2019, between~~as of September 8, 2020 among CNX Resources Corporation, the ~~Company~~subsidiary guarantors party thereto and ~~Olayemi Akinkugbe.~~BofA Securities, Inc. and Wells Fargo Securities, LLC, as representatives of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (file number 001-14901) filed on September 9, 2020).
31.1*10.3	Amendment to CNX Resources Corporation Amended and Restated Equity Incentive Plan (incorporated by reference to Exhibit 4.5 to Form S-8 (file number 333-249096) filed on September 28, 2020).
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS			XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*			XBRL Taxonomy Extension Schema Document.
101.CAL*			XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*			XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*			XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*			XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed herewith

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated: October 29, ~~2019~~2020


CNX RESOURCES CORPORATION

~~CNX RESOURCES CORPORATION~~
	By:
	~~By:~~	/s/S/ NICHOLAS J. DEIULIIS
			Nicholas J. DeIuliis
			Director, Chief Executive Officer and President (Duly Authorized Officer and Principal Executive Officer)

		By:	/S/ DONALD W. RUSH
			Donald W. Rush
			Chief Financial Officer ~~and Executive Vice President~~ (Duly Authorized Officer and Principal Financial Officer)

		By:	/S/ J~~ASON~~ ~~L. MUMFORD~~ALAN K. SHEPARD
			~~Jason L. Mumford~~Alan K. Shepard
			Chief Accounting Officer and Vice President (Duly Authorized Officer and Principal Accounting Officer)

		By:	/S/ JASON L. MUMFORD
			Jason L. Mumford
			Vice President and Controller

6567



Delaware						51-0337383
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


Class						Shares outstanding as of October 15, 2020
Common stock, $0.01 par value						224,528,583


			Page
PART I FINANCIAL INFORMATION

~~Class~~		~~Shares outstanding as of October 15, 2019~~
~~Common stock, $0.01 par value~~	~~186,586,751~~

~~TABLE OF CONTENTS~~

		~~Page~~
~~PART I FINANCIAL INFORMATION~~

ITEM 1.	Unaudited Condensed Consolidated Financial Statements
			Consolidated Statements of Income for the three and nine months ended September 30, ~~2019~~2020 and ~~2018~~2019	4
			Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, ~~2019~~2020 and ~~2018~~ 2019	5
			Consolidated Balance Sheets at September 30, ~~2019~~2020 and December 31, ~~2018~~2019	6
			Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, ~~2019~~2020 and ~~2018~~2019	8
			Consolidated Statements of Cash Flows for the nine months ended September 30, ~~2019~~2020 and ~~2018~~2019	910
			Notes to Unaudited Consolidated Financial Statements	1011

ITEM 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations	3234

ITEM 3.			Quantitative and Qualitative Disclosures About Market Risk	6260

ITEM 4.			Controls and Procedures	6362

PART II OTHER INFORMATION

ITEM 1.			Legal Proceedings	6462

ITEM 1A.			Risk Factors	6462

ITEM 2.			Unregistered Sales of Equity Securities and Use of Proceeds	6466

ITEM 6.			Exhibits	6566


	(Unaudited)					(Unaudited)
(Dollars in thousands)	September 30, 2019		December 31, 2018		(Dollars in thousands)	September 30, 2020		December 31, 2019
ASSETS					ASSETS
Current Assets:					Current Assets:
Cash and Cash Equivalents	$	5,484	$	17,198	Cash and Cash Equivalents	$	150,132	$	16,283
Restricted Cash					Restricted Cash	733		0
Accounts and Notes Receivable:					Accounts and Notes Receivable:
Trade	96,997		252,424
Other Receivables	11,462		11,077
Trade, net					Trade, net	75,929		133,480
Other Receivables, net					Other Receivables, net	4,653		13,679
Supplies Inventories	7,527		9,715		Supplies Inventories	10,090		6,984

Recoverable Income Taxes	11,184		149,481		Recoverable Income Taxes	644		62,425
Derivative Instruments					Derivative Instruments	77,608		247,794
Prepaid Expenses	213,072		61,791		Prepaid Expenses	12,450		17,456

Total Current Assets	345,726		501,686		Total Current Assets	332,239		498,101
Property, Plant and Equipment:					Property, Plant and Equipment:
Property, Plant and Equipment	10,512,298		9,567,428		Property, Plant and Equipment	10,904,837		10,572,006
Less—Accumulated Depreciation, Depletion and Amortization	2,981,723		2,624,984		Less—Accumulated Depreciation, Depletion and Amortization	3,841,699		3,435,431

Total Property, Plant and Equipment—Net	7,530,575		6,942,444		Total Property, Plant and Equipment—Net	7,063,138		7,136,575
Other Assets:
Other Non-Current Assets:					Other Non-Current Assets:

Operating Lease Right-of-Use Assets	205,647		—		Operating Lease Right-of-Use Assets	124,329		187,097
Investment in Affiliates	17,110		18,663		Investment in Affiliates	15,685		16,710
Derivative Instruments					Derivative Instruments	160,098		314,096
Goodwill	796,359		796,359		Goodwill	323,314		796,359
Other Intangible Assets	98,285		103,200		Other Intangible Assets	91,733		96,647
Restricted Cash					Restricted Cash	5,456		0
Other	292,556		229,818		Other	13,182		15,221
Total Other Assets	1,409,957		1,148,040

Total Other Non-Current Assets					Total Other Non-Current Assets	733,797		1,426,130
TOTAL ASSETS	$	9,286,258	$	8,592,170	TOTAL ASSETS	$	8,129,174	$	9,060,806



☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.



☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


(Dollars in thousands, except per share data)	Three Months Ended				Nine Months Ended
(Unaudited)	September 30,				September 30,
Revenue and Other Operating Income:	2020		2019		2020		2019
Natural Gas, NGL and Oil Revenue	$	182,213	$	265,051	$	609,483	$	1,043,862
(Loss) Gain on Commodity Derivative Instruments	(168,834)		213,913		(116,995)		240,118
Purchased Gas Revenue	31,541		29,192		78,324		64,181

Other Revenue and Operating Income	21,155		21,841		60,463		65,299
Total Revenue and Other Operating Income	66,075		529,997		631,275		1,413,460
Costs and Expenses:
Operating Expense
Lease Operating Expense	10,377		14,202		30,654		52,706
Production, Ad Valorem, and Other Fees	5,994		6,127		17,540		20,103
Transportation, Gathering and Compression	68,810		80,193		212,077		244,217
Depreciation, Depletion and Amortization	114,464		120,459		357,174		374,619
Exploration and Production Related Other Costs	2,141		6,075		9,339		14,900
Purchased Gas Costs	31,721		27,490		76,709		62,476
Impairment of Exploration and Production Properties	0		0		61,849		0
Impairment of Goodwill	0		0		473,045		0
Selling, General, and Administrative Costs	22,714		24,307		76,350		109,016
Other Operating Expense	23,284		19,746		70,561		61,197
Total Operating Expense	279,505		298,599		1,385,298		939,234
Other Expense
Other Expense	2,180		3,439		12,184		2,757
Gain on Asset Sales and Abandonments	(3,567)		(3,308)		(21,559)		(610)

Loss (Gain) on Debt Extinguishment	108		0		(10,812)		7,614
Interest Expense	37,921		38,405		133,173		114,328
Total Other Expense	36,642		38,536		112,986		124,089
Total Costs and Expenses	316,147		337,135		1,498,284		1,063,323
(Loss) Earnings Before Income Tax	(250,072)		192,862		(867,009)		350,137
Income Tax (Benefit) Expense	(61,279)		48,902		(242,507)		78,133


Net (Loss) Income	(188,793)		143,960		(624,502)		272,004
Less: Net Income Attributable to Noncontrolling Interest	15,905		28,422		55,031		81,325
Net (Loss) Income Attributable to CNX Resources Shareholders	$	(204,698)	$	115,538	$	(679,533)	$	190,679

(Loss) Earnings per Share
Basic	$	(1.03)	$	0.62	$	(3.56)	$	1.01
Diluted	$	(1.03)	$	0.61	$	(3.56)	$	1.01

Dividends Declared	$	0	$	0	$	0	$	0


(Dollars in thousands) (Unaudited)	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total CNX Resources Stockholders’ Equity		Non- Controlling Interest		Total Equity
June 30, 2020	$	1,878	$	2,261,729	$	1,495,197	$	(12,382)	$	3,746,422	$	820,532	$	4,566,954
Net (Loss) Income	—		—		(204,698)		—		(204,698)		15,905		(188,793)
Issuance of Common Stock	—		151		—		—		151		—		151

Shares Withheld for Taxes	—		—		(1)		—		(1)		—		(1)
Amortization of Stock-Based Compensation Awards	—		1,902		—		—		1,902		601		2,503
Equity Component of Convertible Senior Notes, net of Issuance Costs	—		10		—		—		10		—		10

Other Comprehensive Income	—		—		—		112		112		—		112
Distributions to CNXM Noncontrolling Interest Holders	—		—		—		—		—		(21,055)		(21,055)
CNXM Merger	371		725,907		—		—		726,278		(815,983)		(89,705)
September 30, 2020	$	2,249	$	2,989,699	$	1,290,498	$	(12,270)	$	4,270,176	$	0	$	4,270,176
(Dollars in thousands) (Unaudited)
June 30, 2019	$	1,879	$	2,203,969	$	2,127,627	$	(7,819)	$	4,325,656	$	774,339	$	5,099,995
Net Income	—		—		115,538		—		115,538		28,422		143,960
Issuance of Common Stock	1		48		—		—		49		—		49
Purchase and Retirement of Common Stock	(10)		(7,687)		—		—		(7,697)		—		(7,697)
Shares Withheld for Taxes	—		—		(61)		—		(61)		—		(61)
Amortization of Stock-Based Compensation Awards	—		1,453		—		—		1,453		328		1,781
Other Comprehensive Income	—		—		—		41		41		—		41
Distributions to CNXM Noncontrolling Interest Holders	—		—		—		—		—		(16,250)		(16,250)
September 30, 2019	$	1,870	$	2,197,783	$	2,243,104	$	(7,778)	$	4,434,979	$	786,839	$	5,221,818



(Unaudited)	Nine Months Ended
Dollars in Thousands	September 30,
Cash Flows from Operating Activities:	2019			2018
Net Income	$	272,004		$	753,696
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	374,619			363,338
Amortization of Deferred Financing Costs	6,057			6,640
Impairment of Other Intangible Assets	—			18,650
Stock-Based Compensation	36,557			15,861
Gain on Asset Sales and Abandonments	(610		)	(148,942		)
Gain on Previously Held Equity Interest	—			(623,663		)
Loss on Debt Extinguishment	7,614			54,433
Gain on Commodity Derivative Instruments	(240,118		)	(78,752		)
Net Cash Received in Settlement of Commodity Derivative Instruments	26,331			2,518
Deferred Income Taxes	78,133			259,116
Equity in Earnings of Affiliates	(1,703		)	(4,688		)
Return on Equity Investment	3,256			—
Changes in Operating Assets:
Accounts and Notes Receivable	154,715			50,125
Recoverable Income Taxes	138,406			(8,501		)
Supplies Inventories	2,188			1,016
Prepaid Expenses	5,725			(337		)
Changes in Operating Liabilities:
Accounts Payable	55,280			2,532
Accrued Interest	2,359			5,812
Other Operating Liabilities	(31,689		)	30,418
Changes in Other Liabilities	(23,041		)	(9,736		)
Other	9			683
Net Cash Provided by Operating Activities	866,092			690,219
Cash Flows from Investing Activities:
Capital Expenditures	(964,502		)	(794,124		)
CNX Gathering LLC Acquisition, Net of Cash Acquired	—			(299,272		)
Proceeds from Asset Sales	15,276			500,811
Net Distributions from Equity Affiliates	—			7,750
Net Cash Used in Investing Activities	(949,226		)	(584,835		)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	(5,322		)	(5,455		)
Payments on Long-Term Notes	(405,876		)	(935,419		)
Net Proceeds from (Payments on) CNXM Revolving Credit Facility	162,000			(105,500		)
Proceeds from CNX Revolving Credit Facility	1,200			439,000
Proceeds from Issuance of CNX Senior Notes	500,000			—
Proceeds from Issuance of CNXM Senior Notes	—			394,000
Distributions to CNXM Noncontrolling Interest Holders	(47,062		)	(40,839		)
Proceeds from Issuance of Common Stock	210			1,689
Shares Withheld for Taxes	(6,284		)	(5,335		)
Purchases of Common Stock	(117,477		)	(294,365		)
Debt Repurchase and Financing Fees	(9,969		)	(19,655		)
Net Cash Provided by (Used in) Financing Activities	71,420			(571,879		)
Net Decrease in Cash and Cash Equivalents	(11,714		)	(466,495		)
Cash and Cash Equivalents at Beginning of Period	17,198			509,167
Cash and Cash Equivalents at End of Period	$	5,484		$	42,672


(Dollars in thousands)	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total CNX Resources Stockholders’ Equity		Non- Controlling Interest		Total Equity
December 31, 2019	$	1,870	$	2,199,605	$	1,971,676	$	(12,605)	$	4,160,546	$	801,763	$	4,962,309
(Unaudited)
Net (Loss) Income	—		—		(679,533)		—		(679,533)		55,031		(624,502)
Issuance of Common Stock	8		1,797		—		—		1,805		—		1,805

Shares Withheld for Taxes	—		—		(1,645)		—		(1,645)		(309)		(1,954)
Amortization of Stock-Based Compensation Awards	—		10,424		—		—		10,424		1,485		11,909
Equity Component of Convertible Senior Notes, net of Issuance Costs	—		78,317		—		—		78,317		—		78,317
Purchase of Capped Call	—		(26,351)		—		—		(26,351)		—		(26,351)
Other Comprehensive Income	—		—		—		335		335		—		335
Distributions to CNXM Noncontrolling Interest Holders	—		—		—		—		—		(41,987)		(41,987)
CNXM Merger	371		725,907		—		—		726,278		(815,983)		(89,705)
September 30, 2020	$	2,249	$	2,989,699	$	1,290,498	$	(12,270)	$	4,270,176	$	0	$	4,270,176
(Dollars in thousands)
December 31, 2018	$	1,990	$	2,264,063	$	2,071,809	$	(7,904)	$	4,329,958	$	751,785	$	5,081,743
(Unaudited)
Net Income	—		—		190,679		—		190,679		81,325		272,004
Issuance of Common Stock	9		202		—		—		211		—		211
Purchase and Retirement of Common Stock	(129)		(101,558)		(13,790)		—		(115,477)		—		(115,477)
Shares Withheld for Taxes	—		—		(5,594)		—		(5,594)		(690)		(6,284)
Amortization of Stock-Based Compensation Awards	—		35,076		—		—		35,076		1,481		36,557
Other Comprehensive Income	—		—		—		126		126		—		126
Distributions to CNXM Noncontrolling Interest Holders	—		—		—		—		—		(47,062)		(47,062)
September 30, 2019	$	1,870	$	2,197,783	$	2,243,104	$	(7,778)	$	4,434,979	$	786,839	$	5,221,818



	Amount
Balance at December 31, 2018	$	(7,904	)
Amounts Reclassified from Accumulated Other Comprehensive Loss, net of tax	126
Balance at September 30, 2019	$	(7,778	)



	Amount
Cash Consideration	$	305,000
CNX Gathering Cash on Hand at January 3, 2018 Distributed to Noble	2,620
Fair Value of Previously Held Equity Interest	799,033
Total Estimated Fair Value of Consideration Transferred	$	1,106,653



Fair Value of Assets Acquired:	Amount
Cash and Cash Equivalents	$	8,348
Accounts and Notes Receivable	21,199
Prepaid Expense	2,006
Other Current Assets	163
Property, Plant and Equipment, Net	1,043,340
Intangible Assets	128,781
Other	593
Total Assets Acquired	1,204,430

Fair Value of Liabilities Assumed:
Accounts Payable	26,059
CNXM Revolving Credit Facility	149,500
Total Liabilities Assumed	175,559

Total Identifiable Net Assets	1,028,871
Fair Value of Noncontrolling Interest in CNXM	(718,577		)
Goodwill	796,359
Net Assets Acquired	$	1,106,653


	September 30, 2020		December 31, 2019
Royalties	$	53,343	$	74,061
Transportation Charges	19,556		16,533
Accrued Interest	16,896		30,862
Accrued Other Taxes	9,681		9,115
Deferred Revenue	8,934		13,964
Short-Term Incentive Compensation	7,785		21,030
Accrued Payroll & Benefits	6,082		6,248
Other	35,471		37,610
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations	5,076		5,076
Salary Retirement	1,649		1,587
Total Other Accrued Liabilities	$	164,473	$	216,086


~~ITEM 1.~~	~~CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


	September 30, 2020		December 31, 2019
Senior Notes due March 2027 at 7.25% (Principal of $700,000 and $500,000 plus Unamortized Premium of $6,955 at September 30, 2020)	$	706,955	$	500,000
CNX Revolving Credit Facility	410,000		661,000
CNX Midstream Partners LP Senior Notes due March 2026 at 6.50% (Principal of $400,000 less Unamortized Discount of $4,062 and $4,625, respectively)*	395,938		395,375
Senior Notes due April 2022 at 5.875% (Principal of $363,348 and $894,307 plus Unamortized Premium of $276 and $1,001, respectively)	363,624		895,308
CNX Midstream Partners LP Revolving Credit Facility*	343,000		311,750
Convertible Senior Notes due May 2026 at 2.25% (Principal of $345,000 less Unamortized Discount and Issuance Costs of $111,621)	233,379		0
Cardinal States Gathering Company Credit Facility maturing in March 2028 (Principal of $118,776 less Unamortized Discount of $1,165)	117,611		0
CSG Holdings II LLC Credit Facility maturing in December 2026 (Principal of $47,355 less Unamortized Discount of $460)	46,895		0
Less: Unamortized Debt Issuance Costs	16,940		8,990
	2,600,462		2,754,443
Less: Amounts Due in One Year	22,488		0
Long-Term Debt	$	2,577,974	$	2,754,443


	September 30, 2020
Liability Component:
Principal	$	345,000
Unamortized Discount	(105,004)
Unamortized Issuance Costs	(6,617)
Net Carrying Amount	$	233,379

Equity Component, net of Purchase Discounts and Issuance Costs	$	78,317



	September 30,
	2019
Operating Leases:
Operating Lease Right-of-Use Asset	$	205,647

Current Portion of Operating Lease Obligations	65,061
Operating Lease Obligations	122,514
Total Operating Lease Liabilities	$	187,575

Finance Leases:
Property, Plant and Equipment	$	73,363
Less—Accumulated Depreciation, Depletion and Amortization	62,191
Property, Plant and Equipment—Net	$	11,172

Current Portion of Finance Lease Obligations	$	7,203
Finance Lease Obligations	9,400
Total Finance Lease Liabilities	$	16,603



	For the Nine Months Ended
	September 30, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating Cash Flows from Operating Leases	$	48,308
Operating Cash Flows from Finance Leases	$	974
Financing Cash Flows from Finance Leases	$	5,322
Right-of-Use Assets Obtained in Exchange for Lease Obligations:
Operating Leases	$	15,347
Finance Leases	$	1,722



	Operating		Finance
	Leases		Leases
Twelve months ended September 30,
2020	$	72,775	$	8,136
2021	57,943		7,794
2022	37,534		1,584
2023	5,460		413
2024	5,440		201
Thereafter	32,034		—
Total Lease Payments	211,186		18,128
Less: Interest	23,611		1,525
Present Value of Lease Liabilities	$	187,575	$	16,603



	~~September 30,~~
	~~2019~~
~~Weighted Average Remaining Lease Term (years):~~
~~Operating Leases~~	~~4.46~~
~~Finance Leases~~	~~2.35~~

~~Weighted Average Discount Rate:~~
~~Operating Leases~~	~~4.95~~	%
~~Finance Leases~~	~~6.96~~	%


	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Firm Transportation	$	178,352	$	178,352	$	0	$	0	$	0

Other	6,950		6,950		0		0		0
Total Letters of Credit	185,302		185,302		0		0		0
Surety Bonds:
Employee-Related	2,600		1,500		1,100		0		0
Environmental	12,312		10,717		1,595		0		0
Financial Guarantees	81,670		26,400		55,270		0		0
Other	9,285		8,594		691		0		0
Total Surety Bonds	105,867		47,211		58,656		0		0
Total Commitments	$	291,169	$	232,513	$	58,656	$	0	$	0


Obligations Due	Amount
Less than 1 year	$	242,786
1 - 3 years	429,062
3 - 5 years	369,444
More than 5 years	930,189
Total Purchase Obligations	$	1,971,481


	September 30,			December 31,		Forecasted to
	2020			2019		Settle Through
Natural Gas Commodity Swaps (Bcf)	1,280.9		*	1,460.6		2025
Natural Gas Basis Swaps (Bcf)	1,311.8		*	1,290.4		2025
Interest Rate Swaps	$	575,625		$	160,000	2028



Asset Derivative Instruments					Liability Derivative Instruments
	September 30,		December 31,			September 30,		December 31,
	2019		2018			2019		2018
Commodity Swaps:
Prepaid Expense	$	172,836	$	28,612	Other Accrued Liabilities	$	1,389	$	34,640
Other Assets	254,967		164,310		Other Liabilities	17,440		52,011
Total Asset	$	427,803	$	192,922	Total Liability	$	18,829	$	86,651

Basis Only Swaps:
Prepaid Expense	$	25,420	$	11,628	Other Accrued Liabilities	$	43,437	$	27,021
Other Assets	20,925		48,788		Other Liabilities	98,638		40,210
Total Asset	$	46,345	$	60,416	Total Liability	$	142,075	$	67,231


	Fair Value Measurements at September 30, 2020						Fair Value Measurements at December 31, 2019
Description	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Gas Derivatives	$	0	$	(94,939)	$	0	$	0	$	405,781	$	0
Interest Rate Swaps	$	0	$	(15,609)	$	0	$	0	$	(1,219)	$	0



	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and Cash Equivalents	$	5,484	$	5,484	$	17,198	$	17,198
Long-Term Debt (Excluding Debt Issuance Costs)	$	2,649,802	$	2,505,114	$	2,387,001	$	2,290,537


	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGL and Oil Revenue	$	155,792	$	25,667	$	754	$	182,213	(A)

Purchased Gas Revenue	0		0		31,541		31,541

Gain (Loss) on Commodity Derivative Instruments	79,773		10,518		(259,125)		(168,834)
Other Revenue and Operating Income	16,689		0		4,466		21,155		(B)
Total Revenue and Other Operating Income	$	252,254	$	36,185	$	(222,364)	$	66,075
Total Operating Expense	$	165,587	$	30,439	$	83,479	$	279,505
Earnings (Loss) Before Income Tax	$	86,667	$	5,746	$	(342,485)	$	(250,072)
Segment Assets	$	6,070,356	$	1,125,312	$	933,506	$	8,129,174	(C)
Depreciation, Depletion and Amortization	$	94,617	$	15,763	$	4,084	$	114,464
Capital Expenditures	$	105,988	$	2,310	$	37	$	108,335



	Marcellus Shale		Utica Shale		Coalbed Methane		Other Gas		Total E&P		Midstream		Unallocated			Intercompany Eliminations			Consolidated
Natural Gas, NGLs and Oil Revenue	$	179,142	$	50,042	$	35,621	$	246	$	265,051	$	—	$	—		$	—		$	265,051	(A)
Purchased Gas Revenue	—		—		—		29,192		29,192		—		—			—			29,192
Midstream Revenue	—		—		—		—		—		74,261		—			(55,736		)	18,525
Gain on Commodity Derivative Instruments	38,354		12,628		6,036		156,895		213,913		—		—			—			213,913
Other Operating Income	—		—		—		3,375		3,375		—		—			(59		)	3,316		(B)
Total Revenue and Other Operating Income	$	217,496	$	62,670	$	41,657	$	189,708	$	511,531	$	74,261	$	—		$	(55,795	)	$	529,997
Earnings Before Income Tax	$	41,014	$	18,220	$	8,717	$	83,279	$	151,230	$	41,741	$	(109	)	$	—		$	192,862
Segment Assets									$	7,087,782	$	2,178,073	$	16,668		$	3,735		$	9,286,258	(C)
Depreciation, Depletion and Amortization									$	111,839	$	8,620	$	—		$	—		$	120,459
Capital Expenditures									$	267,689	$	68,448	$	—		$	—		$	336,137


~~(A)~~	Included in Total Natural Gas, NGLs and Oil Revenue are sales of $39,092 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.


~~(B)~~	~~Includes equity in earnings of unconsolidated affiliates of $673 for Total E&P.~~


~~(C)~~	~~Includes investments in unconsolidated equity affiliates of $17,110 for Total E&P.~~


~~(D)~~	~~Included in Total Natural Gas, NGLs and Oil Revenue are sales of $42,901 to NJR Energy Services Company, which comprises over 10% of revenue from contracts with external customers for the period.~~


~~(E)~~	~~Includes equity in earnings of unconsolidated affiliates of $1,241 for Total E&P.~~


~~(F)~~	~~Includes investments in unconsolidated equity affiliates of $19,488 for Total E&P.~~