~~CONSOL ENERGY INC.~~CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	(Unaudited)
(Dollars in thousands, except per share data)	June 30, 2022		December 31, 2021
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	154,449	$	121,751
Derivative Instruments	1,210,715		521,598
Current Portion of Finance Lease Obligations	637		555
Current Portion of Long-Term Debt	322,622		—

Current Portion of Operating Lease Obligations	40,951		22,940
Other Accrued Liabilities	302,599		287,732


Total Current Liabilities	2,031,973		954,576
Non-Current Liabilities:
Long-Term Debt	1,907,074		2,214,121
Finance Lease Obligations	1,342		1,218
Operating Lease Obligations	139,428		33,672
Derivative Instruments	1,899,736		687,354
Deferred Income Taxes	—		328,601
Asset Retirement Obligations	88,463		88,859


Other	90,850		92,077

Total Non-Current Liabilities	4,126,893		3,445,902
TOTAL LIABILITIES	6,158,866		4,400,478
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 191,400,910 Issued and Outstanding at June 30, 2022; 203,531,320 Issued and Outstanding at December 31, 2021	1,918		2,039
Capital in Excess of Par Value	2,665,440		2,834,863
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—		—
(Accumulated Deficit) Retained Earnings	(116,081)		877,894
Accumulated Other Comprehensive Loss	(14,253)		(14,523)



TOTAL STOCKHOLDERS' EQUITY	2,537,024		3,700,273
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	8,695,890	$	8,100,751

(Unaudited)
(Dollars in thousands, except per share data) September 30,
2017 December 31,
2016
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable $ 303,196
$ 241,616
Current Portion of Long-Term Debt 10,971
12,000
Other Accrued Liabilities 540,672
680,348
Current Liabilities of Discontinued Operations 5,353
6,050
Total Current Liabilities 860,192
940,014
Long-Term Debt:
Long-Term Debt 2,500,782
2,722,995
Capital Lease Obligations 31,530
39,074
Total Long-Term Debt 2,532,312
2,762,069
Deferred Credits and Other Liabilities:
Deferred Income Taxes 44,720
—
Postretirement Benefits Other Than Pensions 649,565
659,474
Pneumoconiosis Benefits 106,837
108,073
Mine Closing 198,764
218,631
Gas Well Closing 223,446
223,352
Workers’ Compensation 66,165
67,277
Salary Retirement 100,510
112,543
Other 125,822
151,660
Total Deferred Credits and Other Liabilities 1,515,829
1,541,010
TOTAL LIABILITIES 4,908,333
5,243,093
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 230,090,909 Issued and Outstanding at September 30, 2017; 229,443,008 Issued and Outstanding at December 31, 2016 2,305
2,298
Capital in Excess of Par Value 2,486,071
2,460,864
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding —
—
Retained Earnings 1,825,547
1,727,789
Accumulated Other Comprehensive Loss (382,092 ) (392,556 )
Total CONSOL Energy Inc. Stockholders’ Equity 3,931,831
3,798,395
Noncontrolling Interest 139,404
142,493
TOTAL EQUITY 4,071,235
3,940,888
TOTAL LIABILITIES AND EQUITY $ 8,979,568
$ 9,183,981

The accompanying notes are an integral part of these financial statements.

~~CONSOL ENERGY INC.~~CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF STOCKHOLDERS’ EQUITY


(Dollars in thousands) (Unaudited)	Common Stock		Capital in Excess of Par Value		(Accumulated Deficit) Retained Earnings		Accumulated Other Comprehensive Loss		Total Equity
March 31, 2022	$	1,955	$	2,691,950	$	(110,005)	$	(14,388)	$	2,569,512
Net Income	—		—		33,357		—		33,357
Issuance of Common Stock	1		374		—		—		375
Purchase and Retirement of Common Stock	(38)		(30,606)		(39,350)		—		(69,994)
Shares Withheld for Taxes	—		—		(83)		—		(83)
Amortization of Stock-Based Compensation Awards	—		3,722		—		—		3,722


Other Comprehensive Income	—		—		—		135		135


June 30, 2022	$	1,918	$	2,665,440	$	(116,081)	$	(14,253)	$	2,537,024
(Dollars in thousands) (Unaudited)
March 31, 2021	$	2,207	$	2,959,934	$	1,563,318	$	(15,049)	$	4,510,410
Net Loss	—		—		(354,059)		—		(354,059)
Issuance of Common Stock	—		2		—		—		2
Purchase and Retirement of Common Stock	(17)		(13,030)		(9,644)		—		(22,691)
Shares Withheld for Taxes	—		—		(45)		—		(45)
Amortization of Stock-Based Compensation Awards	1		3,177		—		—		3,178


Other Comprehensive Income	—		—		—		136		136


June 30, 2021	$	2,191	$	2,950,083	$	1,199,570	$	(14,913)	$	4,136,931

(Dollars in thousands)
Common
Stock

Capital in
Excess
of Par
Value

Retained
Earnings

Accumulated
Other
Comprehensive
Loss

Total CONSOL Energy Inc.
Stockholders’
Equity

Non-
Controlling
Interest

Total
Equity
Balance at December 31, 2016 $ 2,298
$ 2,460,864
$ 1,727,789
$ (392,556 ) $ 3,798,395
$ 142,493
$ 3,940,888
(Unaudited)
Net Income —
—
104,104
—
104,104
10,567
114,671
Other Comprehensive Income (Loss) (Net of ($6,121) Tax) —
—
—
10,464
10,464
(34 ) 10,430
Comprehensive Income —
��
104,104
10,464
114,568
10,533
125,101
Issuance of Common Stock 7
852
—
—
859
—
859
Treasury Stock Activity —
—
(6,346 ) —
(6,346 ) (1,009 ) (7,355 )
Amortization of Stock-Based Compensation Awards —
24,355
—
—
24,355
3,790
28,145
Distributions to Noncontrolling Interest —
—
—
—
—
(16,403 ) (16,403 )
Balance at September 30, 2017 $ 2,305
$ 2,486,071
$ 1,825,547
$ (382,092 ) $ 3,931,831
$ 139,404
$ 4,071,235

The accompanying notes are an integral part of these financial statements.

~~CONSOL ENERGY INC.~~CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~

STOCKHOLDERS’ EQUITY

(Dollars in thousands) Nine Months Ended
(Unaudited) September 30,
Cash Flows from Operating Activities: 2017 2016
Net Income (Loss) $ 114,671
$ (537,517 )
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Operating Activities:

Net Loss from Discontinued Operations —
322,747
Depreciation, Depletion and Amortization 414,608
441,919
Impairment of Exploration and Production Properties 137,865
—
Stock-Based Compensation 28,145
23,825
Gain on Sale of Assets (197,343 ) (13,541 )
Loss on Debt Extinguishment 1,233
—
Gain on Commodity Derivative Instruments (80,508 ) (53,872 )
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments (61,717 ) 203,303
Deferred Income Taxes 42,888
(72,866 )
Equity in Earnings of Affiliates (34,810 ) (41,239 )
Return on Equity Investment —
22,268
Changes in Operating Assets:

Accounts and Notes Receivable 18,231
4,555
Inventories 1,974
4,169
Prepaid Expenses 1,869
71,423
Changes in Other Assets 37,357
(14,241 )
Changes in Operating Liabilities:

Accounts Payable 23,700
(10,985 )
Accrued Interest 31,093
35,985
Other Operating Liabilities (13,423 ) (21,370 )
Changes in Other Liabilities (31,221 ) (2,620 )
Other 38,226
11,937
Net Cash Provided by Continuing Operating Activities 472,838
373,880
Net Cash (Used in) Provided by Discontinued Operating Activities (614 ) 14,427
Net Cash Provided by Operating Activities 472,224
388,307
Cash Flows from Investing Activities:

Capital Expenditures (450,620 ) (179,389 )
Proceeds from Sales of Assets 426,878
38,977
Net Distributions from (Investments in) Equity Affiliates 35,620
(4,555 )
Net Cash Provided by (Used in) Continuing Investing Activities 11,878
(144,967 )
Net Cash Provided by Discontinued Investing Activities —
366,251
Net Cash Provided by Investing Activities 11,878
221,284
Cash Flows from Financing Activities:

Payments on Short-Term Borrowings —
(598,000 )
Payments on Miscellaneous Borrowings (8,944 ) (6,222 )
Payments on Long-Term Notes (213,728 ) —
Net (Payments on) Proceeds from Revolver - CNX Coal Resources LP (13,000 ) 23,000
Distributions to Noncontrolling Interest (16,403 ) (16,241 )
Dividends Paid —
(2,294 )
Issuance of Common Stock 859
4
Treasury Stock Activity (7,355 ) (1,669 )
Debt Repurchase and Financing Fees (298 ) (482 )
Net Cash Used in Continuing Financing Activities (258,869 ) (601,904 )
Net Cash Used in Discontinued Financing Activities —
(14 )
Net Cash Used in Financing Activities (258,869 ) (601,918 )
Net Increase in Cash and Cash Equivalents 225,233
7,673
Cash and Cash Equivalents at Beginning of Period 60,475
72,574
Cash and Cash Equivalents at End of Period $ 285,708
$ 80,247


(Dollars in thousands)	Common Stock		Capital in Excess of Par Value		Retained Earnings		Accumulated Other Comprehensive Loss		Total Equity
December 31, 2021	$	2,039	$	2,834,863	$	877,894	$	(14,523)	$	3,700,273
(Unaudited)
Net Loss	—		—		(889,585)		—		(889,585)
Issuance of Common Stock	2		981		—		—		983
Purchase and Retirement of Common Stock	(129)		(103,167)		(117,672)		—		(220,968)
Shares Withheld for Taxes	—		—		(5,665)		—		(5,665)
Amortization of Stock-Based Compensation Awards	6		11,047		—		—		11,053


Other Comprehensive Income	—		—		—		270		270

Cumulative Effect of Adoption of New Accounting Standard	—		(78,284)		18,947		—		(59,337)
June 30, 2022	$	1,918	$	2,665,440	$	(116,081)	$	(14,253)	$	2,537,024
(Dollars in thousands)
December 31, 2020	$	2,208	$	2,959,357	$	1,476,056	$	(15,184)	$	4,422,437
(Unaudited)
Net Loss	—		—		(256,034)		—		(256,034)
Issuance of Common Stock	7		4,794		—		—		4,801
Purchase and Retirement of Common Stock	(31)		(24,731)		(15,916)		—		(40,678)
Shares Withheld for Taxes	—		—		(4,536)		—		(4,536)
Amortization of Stock-Based Compensation Awards	7		10,696		—		—		10,703
Equity Component of Convertible Senior Notes, net of Issuance Costs	—		(33)		—		—		(33)

Other Comprehensive Income	—		—		—		271		271


June 30, 2021	$	2,191	$	2,950,083	$	1,199,570	$	(14,913)	$	4,136,931

The accompanying notes are an integral part of these financial statements.

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


(Unaudited)	Six Months Ended
Dollars in Thousands	June 30,
Cash Flows from Operating Activities:	2022		2021
Net Loss	$	(889,585)	$	(256,034)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:

Depreciation, Depletion and Amortization	234,803		251,551
Amortization of Deferred Financing Costs	4,115		12,156


Stock-Based Compensation	11,053		10,703
Gain on Asset Sales and Abandonments, net	(19,634)		(10,060)

Loss on Debt Extinguishment	12,981		—
Loss on Commodity Derivative Instruments	2,379,036		505,445
Gain on Other Derivative Instruments	(7,353)		(4,659)
Net Cash Paid in Settlement of Commodity Derivative Instruments	(800,971)		(7,954)
Deferred Income Taxes	(319,814)		(54,970)
Other	2,323		(704)

Changes in Operating Assets:
Accounts and Notes Receivable	(118,619)		(18,191)
Recoverable Income Taxes	72		88
Supplies Inventories	(8,343)		1,936
Prepaid Expenses	3,407		586
Changes in Other Assets	1,843		(1,084)
Changes in Operating Liabilities:
Accounts Payable	28,508		14,701
Accrued Interest	(1,466)		14,762
Other Operating Liabilities	16,820		720
Changes in Other Liabilities	(814)		(117)



Net Cash Provided by Operating Activities	528,362		458,875
Cash Flows from Investing Activities:
Capital Expenditures	(258,984)		(252,387)

Proceeds from Asset Sales	26,530		11,969



Net Cash Used in Investing Activities	(232,454)		(240,418)
Cash Flows from Financing Activities:

Payments on Long-Term Notes	(26,969)		—
Net Proceeds from (Payments on) CNXM Revolving Credit Facility	3,300		(131,000)
Net Payments on CNX Revolving Credit Facility	(58,350)		(800)


Net Payments on CSG Non-Revolving Credit Facilities	—		(13,113)
Net Payments on Other Debt	(311)		(2,526)



Proceeds from Issuance of Common Stock	983		4,801
Shares Withheld for Taxes	(5,665)		(4,536)
Purchases of Common Stock	(211,967)		(46,678)
Debt Issuance and Financing Fees	(256)		(1,320)


Net Cash Used in Financing Activities	(299,235)		(195,172)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(3,327)		23,285
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	3,565		21,599
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	238	$	44,884

The accompanying notes are an integral part of these financial statements.

911

~~CONSOL ENERGY INC.~~CNX RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 are not necessarily indicative of the results that may be expected for future periods.

The Consolidated Balance Sheet at December 31, ~~2016~~2021 has been derived from the Audited Consolidated Financial Statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the Consolidated Financial Statements and related notes for the year ended December 31, ~~2016~~2021 included in ~~CONSOL Energy Inc.'s~~CNX Resources Corporation's ("CNX," "CNX Resources," the "Company," "we," "us," or "our") Annual Report on Form ~~10-K.~~10-K as filed with the Securities and Exchange Commission (SEC) on February 10, 2022.

Certain amounts in prior periods have been reclassified to conform ~~with~~to the ~~report classifications~~current period presentation.

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of ~~the year ended December 31, 2016, with no effect on previously reported net income or stockholders' equity.~~

~~In March 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update on stock compensation that was intended~~cash, cash equivalents, and restricted cash to ~~simplify and improve~~amounts shown in the ~~accounting and~~ statement of cash ~~flow presentation for income taxes~~flows:


	June 30,
	2022		2021
Cash and Cash Equivalents	$	238	$	39,365
Restricted Cash, Current Portion	—		768
Restricted Cash, Less Current Portion	—		4,751
Total Cash, Cash Equivalents, and Restricted Cash	$	238	$	44,884

Restricted cash at settlement, forfeitures, and net settlements for withholding tax. The guidance is effective for public entities for fiscal years beginning after December 15, 2016. In accordance with this Update, $64 and $4,629June 30, 2021 consisted of ~~additional income tax expense~~cash that the Company was ~~recognized in the Consolidated Statements of Income for the three and nine months ended September 30, 2017, respectively. Also~~contractually obligated to maintain in accordance with ~~this Update,~~ the ~~value~~terms of ~~shares withheld~~the Cardinal States Gathering LLC and CSG Holdings II LLC Credit Agreement, each dated March 13, 2020. In August 2021, CNX repaid in full the outstanding principal on both of these non-revolving credit facilities and terminated the Credit Agreements.

Receivables

As of June 30, 2022 and December 31, 2021, Accounts Receivable - Trade were $447,464 and $330,122, respectively, and Other Receivables were $6,010 and $8,924, respectively.

The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. Management records an allowance for ~~employee tax withholding purposes~~credit losses related to the collectability of ~~$7,355~~third-party customers' receivables using the historical aging of the customer receivable balance. The collectability is determined based on past events, including historical experience, customer credit rating, as well as current market conditions. CNX monitors customer ratings and ~~$1,669~~collectability on an on-going basis. Account balances will be charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

The following represents activity related to the allowance for credit losses for the ~~nine~~six months ended September 30, 2017 and 2016, respectively, were reclassified between Net Cash Provided by Operating Activities and Net Cash Used in Financing Activities of the Consolidated Statements of Cash Flows. As permitted by this Update, the Company has elected to account for forfeitures of stock compensation as they occur. The cumulative effect of the policy election to recognize forfeitures as they occur was nominal.ended:


	June 30,
	2022		2021
Allowance for Credit Losses - Trade, Beginning of Year	$	84	$	84
Provision for Expected Credit Losses	—		—
Allowance for Credit Losses - Trade, End of Period	$	84	$	84

Allowance for Credit Losses - Other Receivables, Beginning of Year	$	3,322	$	3,248
Provision for Expected Credit Losses	(376)		(55)
Write-off of Uncollectible Accounts	(178)		(15)
Allowance for Credit Losses - Other Receivables, End of Period	$	2,768	$	3,178

NOTE 2—EARNINGS PER SHARE:

Basic earnings per share ~~are~~is computed by dividing net income ~~attributable to CONSOL Energy Inc. ("CONSOL Energy"~~ or ~~the "Company") shareholders~~net loss by the weighted average shares outstanding during the reporting period. ~~Dilutive~~Diluted earnings per share ~~are~~is computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include, if dilutive, additional shares from stock options, ~~performance stock options,~~ restricted stock units, ~~and~~ performance share units ~~if dilutive.~~and shares issuable upon conversion of CNX's outstanding 2.25% convertible senior notes due May 2026 (the "Convertible Notes") (See Note 9 – Long-Term Debt). The number of additional shares is calculated by assuming that outstanding stock options ~~and performance share options~~ were exercised, that outstanding restricted stock units and performance share units were released, that the shares that are issuable from the conversion of the Convertible Notes are issued (subject to the considerations discussed further in the paragraph below), and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In periods when CNX recognizes a net loss, the impact of outstanding stock awards and the potential share settlement impact related to CNX's Convertible Notes are excluded from the diluted loss per share calculation as their inclusion would have an anti-dilutive effect.

The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive:


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2022	2021	2022	2021
Anti-Dilutive Options	6,796	3,029,168	2,303,516	3,029,168
Anti-Dilutive Restricted Stock Units	57,050	2,484,443	2,524,803	2,484,443
Anti-Dilutive Performance Share Units	—	1,011,443	2,119,458	1,011,443

	63,846	6,525,054	6,947,777	6,525,054

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Anti-Dilutive Options 5,407,465 2,989,610 2,731,362 6,230,099
Anti-Dilutive Restricted Stock Units 1,102,180 3,455 183,479 645,302
Anti-Dilutive Performance Share Units 1,793,302 1,659,014 — 2,326,120
Anti-Dilutive Performance Stock Options 802,804 802,804 802,804 802,804
9,105,751 5,454,883 3,717,645 10,004,325

The Convertible Notes, if converted by the holder, may be settled in cash, shares of the Company's common stock or a combination thereof, at the Company's election. The Company expects to settle the principal amount of the Convertible Notes in cash. ASU 2020-06 amends the diluted earnings per share calculation for convertible instruments by requiring the use of the if-converted method (See Note 9 – Long-Term Debt for more information). The if-converted method assumes the conversion of convertible instruments occurs at the beginning of the reporting period and diluted weighted average shares outstanding includes the common shares issuable upon conversion of the convertible instruments. The conversion spread has a dilutive impact on diluted earnings per share when the average market price of the Company's common stock for a given period exceeds the initial conversion price of $12.84 per share for the Convertible Notes. In connection with the Convertible Notes' issuance, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls" and "Capped Call Transactions"), which were not included in calculating the number of diluted shares outstanding, as their effect would have been anti-dilutive.

1013

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


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2022	2021	2022	2021
Options	53,180	205	136,604	656,573
Restricted Stock Units	43,241	34,056	959,162	735,813
Performance Share Units	—	—	72,353	291,653
	96,421	34,261	1,168,119	1,684,039

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Options 17,048 — 107,510 —
Restricted Stock Units 14,776 5,920 349,037 574,310
Performance Share Units — — 560,936 —
31,824
5,920 1,017,483 574,310

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

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Numerator:
(Loss) Income from Continuing Operations $ (25,651 ) $ 62,568 $ 114,671 $ (214,770 )
Less: Net Income Attributable to Non-Controlling Interest 790 2,248 10,567 4,541
Net (Loss) Income from Continuing Operations Attributable to CONSOL Energy Shareholders $ (26,441 ) $ 60,320 $ 104,104 $ (219,311 )
Loss from Discontinued Operations — (34,975 ) — (322,747 )
Net (Loss) Income Attributable to CONSOL Energy Shareholders $ (26,441 ) $ 25,345 $ 104,104 $ (542,058 )

Denominator:
Weighted-average shares of common stock outstanding 230,080,797 229,438,612 229,986,428 229,369,309
Effect of dilutive shares — 2,079,973 1,473,392 —
Weighted-average diluted shares of common stock outstanding 230,080,797 231,518,585 231,459,820 229,369,309
(Loss) Earnings per Share:
Basic (Continuing Operations) $ (0.11 ) $ 0.26 $ 0.45 $ (0.96 )
Basic (Discontinued Operations) — (0.15 ) — (1.40 )
Total Basic $ (0.11 )
$ 0.11 $ 0.45 $ (2.36 )

Dilutive (Continuing Operations) $ (0.11 ) $ 0.26 $ 0.45 $ (0.96 )
Dilutive (Discontinued Operations) — (0.15 ) — (1.40 )
Total Dilutive $ (0.11 ) $ 0.11 $ 0.45 $ (2.36 )

~~Changes in Accumulated Other Comprehensive Loss by component, net of tax, were as follows:~~

Long-Term Liabilities
Balance at December 31, 2016 $ (392,556 )
Amounts Reclassified from Accumulated Other Comprehensive Loss 10,430
Add: Other Comprehensive Loss Attributable to Non-Controlling Interest 34
Balance at September 30, 2017 $ (382,092 )

~~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,
2017 2016 2017 2016
Derivative Instruments (Note 13)
Natural Gas Price Swaps and Options $ — $ (19,597 ) $ — $ (52,759 )
Tax Expense — 7,139 — 19,284
Net of Tax $ — $ (12,458 ) $ — $ (33,475 )
Actuarially Determined Long-Term Liability Adjustments* (Note 5 and Note 6)
Amortization of Prior Service Costs $ (749 ) $ (148 ) $ (2,247 ) $ (443 )
Recognized Net Actuarial Loss 6,247 6,332 18,798 17,549
Settlement Loss — 3,651 — 17,347
Total 5,498 9,835 16,551 34,453
Less: Tax Benefit 2,034 3,664 6,121 12,861
Net of Tax $ 3,464 $ 6,171 $ 10,430 $ 21,592


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2022		2021		2022		2021
Net Income (Loss)	$	33,357	$	(354,059)	$	(889,585)	$	(256,034)




Basic Earnings Available to Shareholders	$	33,357	$	(354,059)	$	(889,585)	$	(256,034)

Effect of Dilutive Securities:
Add Back Interest on Convertible Notes (Net of Tax)	$	1,376	$	—	$	—	$	—
Diluted Earnings Available to Shareholders	$	34,733	$	(354,059)	$	(889,585)	$	(256,034)

Weighted-Average Shares of Common Stock Outstanding	194,021,639		219,897,242		196,921,836		219,910,365
Effect of Diluted Shares:*
Options	1,349,984		—		—		—
Restricted Stock Units	1,603,876		—		—		—
Performance Share Units	1,681,326		—		—		—
Convertible Notes	25,751,869		—		—		—
Weighted-Average Diluted Shares of Common Stock Outstanding	224,408,694		219,897,242		196,921,836		219,910,365

Earnings (Loss) per Share:


Basic	$	0.17	$	(1.61)	$	(4.52)	$	(1.16)



Diluted	$	0.15	$	(1.61)	$	(4.52)	$	(1.16)

*~~Excludes amounts~~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 and the potential share settlement impact related to ~~the remeasurement~~CNX's Convertible Notes are antidilutive.

NOTE 3—REVENUE FROM CONTRACTS WITH CUSTOMERS:

Revenues are recognized when control of the ~~Actuarially Determined Long-Term Liabilities~~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 ~~nine months ended September 30, 2016.~~measurement of transaction price.

~~NOTE 2—DISCONTINUED OPERATIONS:~~

~~In August 2016, CONSOL Energy completed~~For natural gas, NGL and oil, and purchased gas revenue, the ~~sale~~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 ~~Miller Creek and Fola Mining Complexes.~~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 ~~transaction,~~Company has not identified a standalone selling price because the ~~buyer acquired~~terms of the ~~Miller Creek and Fola assets and assumed~~variable payments relate specifically to the ~~Miller Creek and Fola mine closing and reclamation liabilities. In order~~Company’s efforts to ~~equalize~~satisfy the ~~value exchange, CONSOL Energy paid $28,271~~performance obligations. A portion of ~~cash at closing,~~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 ~~included property taxes~~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 the properties sold and other closing costs (a portion of which will be held in escrow for purposes of obtaining the surety bonds required for the permits to transfer). This amount was included in Net Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flows for the nine months ended September 30, 2016. CONSOL Energy will also pay a total of $13,700 in remaining installments over the next three years, ending in January 2020. The net loss on the sale of $53,130, excluding the related impairment charge discussed below, was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income. Prior to the closing, the Miller Creek and Fola Mining Complexes were classified as held for sale in discontinued operations and in accordance with the accounting guidance for Property, Plant and Equipment, assets held for sale are required to be measured at the lower of carrying value or fair value less costs to sell. Upon meeting the assets held for sale criteria, the Company determined the carrying value of the Miller Creek and Fola Mining Complexes exceeded the fair value less costs to sell. As a result, an impairment charge of $355,681 was recorded during the nine months ended September 30, 2016. This impairment was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income.

In March 2016, CONSOL Energy completed the sale of its membership interests in CONSOL Buchanan Mining Company, LLC (BMC), which owned and operated the Buchanan Mine located in Mavisdale, Virginia; various assets relating to the Amonate Mining Complex located in Amonate, Virginia; Russell County, Virginia coal reserves and Pangburn Shaner Fallowfield coal reserves located in Southwestern, Pennsylvania to Coronado IV LLC ("Coronado"). Various CONSOL Energy assets were excluded from the sale including coalbed methane, natural gas, NGL and minerals other than coal, current assets of BMC, certain coal seams and certain surface rights and properties. Coronado assumed only specified liabilities and various CONSOL Energy liabilities were excluded and not assumed. The excluded liabilities included BMC’s indebtedness, trade payables and liabilities arising prior to closing,oil as well as the liabilities of the subsidiaries other than BMC which were parties to the sale. In addition, the buyer agreed to pay CONSOL Energy for Buchanan Mine coal sold outside the U.S. and Canada during the five years following closing a royalty of 20% of any excess of the gross sales price per ton over the following amounts: (1) year one, $75.00 per ton; (2) year two, $78.75 per ton; (3) year three, $82.69 per ton; (4) year four, $86.82 per ton; (5) year five, $91.16 per ton. Total royalty income recognized under this agreement was $61 and $6,485 for the three and nine months ended September 30, 2017, respectively, and was included in Miscellaneous Other Incomepresented on the Consolidated Statements of Income. Cash proceeds of $402,799 were received at closing and are included in Net Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flows for the nine months ended September 30, 2016. The net loss on the sale was $38,364 and was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income for the nine months ended September 30, 2016.

~~For all periods presented in~~ the accompanying Consolidated Statements of Income ~~BMC along with~~represent the ~~various other assets~~Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling natural gas, NGL and oil on behalf of royalty owners or working interest owners, the ~~Miller Creek~~Company is acting as an agent and ~~Fola Mining Complexes are classified as discontinued operations.~~

thus reports the revenue on a net basis.

1214

~~The following table details selected financial information for the divested business included within discontinued operations:~~

For the Three Months Ended For the Nine Months Ended

September 30, 2016 September 30, 2016
Coal Sales $ 6,974
$ 102,904
Freight-Outside Coal 305
1,322
Miscellaneous Other Income 2,204
2,237
Loss on Sale of Assets (53,119 ) (91,372 )
Total Revenue and Other Income $ (43,636 ) $ 15,091
Total Costs 11,789
124,865
Loss From Operations Before Income Taxes $ (55,425 ) $ (109,774 )
Impairment on Assets Held for Sale —
355,681
Income Tax Benefit (20,450 ) (142,708 )
Loss From Discontinued Operations, net $ (34,975 ) $ (322,747 )

~~The following table details the major classes of assets~~Included in Other Revenue and ~~liabilities of discontinued operations:~~

September 30,
2017 December 31,
2016
Assets:
Accounts Receivable - Trade $ —
$ 83
Total Current Assets $ —
$ 83
Total Assets of Discontinued Operations $ —
$ 83
Liabilities:
Accounts Payable $ —
$ 36
Other Current Liabilities 5,353
6,014
Total Current Liabilities $ 5,353
$ 6,050
Total Liabilities of Discontinued Operations $ 5,353
$ 6,050

~~NOTE 3—ACQUISITIONS AND DISPOSITIONS:~~

In September 2017, CONSOL Energy closed on the sale of approximately 22,000 acres of surface land in Colorado. CONSOL Energy received net cash proceeds of $23,703 which is included in the cash flows from investing activities. The net gain on the sale was $18,758 and was included in the Gain on Sale of AssetsOperating Income in the Consolidated Statements of ~~Income.~~ Income and in the below table are revenues generated from natural gas gathering 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.

InDisaggregation of Revenue

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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2022		2021		2022		2021
Revenue from Contracts with Customers:
Natural Gas Revenue	$	934,127	$	320,982	$	1,609,401	$	668,358
NGL Revenue	63,774		41,521		128,569		73,384
Oil/Condensate Revenue	5,505		6,946		10,060		8,932
Total Natural Gas, NGL and Oil Revenue	1,003,406		369,449		1,748,030		750,674

Purchased Gas Revenue	46,552		16,706		92,393		50,190

Other Sources of Revenue and Other Operating Income (Loss):
Loss on Commodity Derivative Instruments	(652,643)		(538,859)		(2,379,036)		(505,445)
Other Revenue and Operating Income	23,103		25,494		45,933		50,445
Total Revenue and Other Operating Income (Loss)	$	420,418	$	(127,210)	$	(492,680)	$	345,864

The disaggregated revenue information corresponds with the Company’s segment reporting found in Note 13 – 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 material contract assets or liabilities under ASC 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer.

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 ~~closing~~of a series.

A significant portion of CNX's natural gas, NGL and oil and purchased gas revenue is short-term in ~~July~~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 ~~September 2017, CONSOL Energy executed~~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 natural gas, NGL and oil 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 $38,605 as of June 30, 2022.

The Company expects to recognize net revenue of $18,121 in the next 12 months and $12,750 over the following 12 months, with the remainder recognized thereafter.

For revenue associated with 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, NGL and oil 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 ~~approximately 7,500 net undeveloped acres of~~ the ~~Marcellus Shale in Allegheny~~product. CNX records the differences between the estimate and ~~Westmoreland counties, Pennsylvania. CONSOL Energy~~the actual amounts received ~~total cash proceeds of $36,649 which is included~~ in the ~~cash flows~~month that payment is received from ~~investing activities.~~the purchaser. The ~~net gain on~~Company has existing internal controls for its revenue estimation process and the ~~sale of these assets was $15,251~~related accruals, and ~~was included~~any identified differences between its revenue estimates and the actual revenue received historically have not been significant. For the three and six months ended June 30, 2022 and 2021, revenue recognized in the ~~Gain on Sale of Assets~~current reporting period related to performance obligations satisfied in ~~the Consolidated Statements of Income.~~a prior reporting period was not material.

In June 2017, CONSOL Energy closed on the sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale in Allegheny, Washington, and Westmoreland counties, Pennsylvania. CONSOL Energy received total cash proceeds of $83,500 which is included in cash flows from investing activities. The net gain on the sale of these assets was $58,541 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

In June 2017, the Company finalized the sale of 12 producing wells, 15 drilled but uncompleted wells (DUCs), and approximately 11,000 net developed and undeveloped Marcellus and Utica acres in Doddridge and Wetzel counties in West Virginia that were previously classified as held for sale. CONSOL Energy received total cash proceeds of $129,651 which is included in cash flows from investing activities, as well as undeveloped acreage. The net loss on the sale was $8,591 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

In May 2017, CONSOL Energy finalized the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in Jefferson, Belmont and Guernsey counties, Ohio that were previously classified as held for sale. CONSOL Energy received total cash proceeds of $76,585 which is included in cash flows from investing activities. The net gain on the sale of these assets was $72,346 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

In April 2017, CONSOL Energy finalized the sale of its Knox Energy LLC and Coalfield Pipeline Company subsidiaries that were previously classified as held for sale. At closing, CONSOL Energy received net cash proceeds of $18,944 which is included in cash flows from investing activities. The net gain on the sale of these assets was $606 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

NOTE 4—~~MISCELLANEOUS OTHER INCOME:~~INCOME TAXES:

For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Equity in Earnings of Affiliates - CONE* $ 12,035
$ 14,153
$ 33,969
$ 36,709
Coal Contract Buyout 8,410
—
8,410
6,288
Purchased Coal Sales 3,568
1,908
9,667
2,512
Royalty Income - Non-Operated Coal 3,512
2,011
15,795
6,664
Gathering Revenue 2,575
2,602
8,276
7,998
Rental Income 1,991
8,983
13,666
27,258
Right of Way Issuance 1,888
149
3,660
17,952
Interest Income 1,306
214
9,382
975
Equity in Earnings of Affiliates - Other 390
1,202
841
4,530
Other 5,361
1,171
12,003
3,273
Miscellaneous Other Income $ 41,036
$ 32,393
$ 115,669
$ 114,159

*Includes the Company's ownership interest in both CONE Gathering LLC and CONE Midstream Partners LP. See Note 17- Related Party for more information.

~~NOTE 5—COMPONENTS OF PENSION AND OTHER POST-EMPLOYMENT BENEFIT (OPEB) PLANS NET PERIODIC BENEFIT COSTS:~~

~~Components of Net Periodic Benefit (Credit) Cost are as follows:~~

Pension Benefits Other Post-Employment Benefits
For the Three Months Ended September 30, For the Nine Months Ended September 30, For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016 2017 2016 2017 2016
Service Cost $ 846
$ 482
$ 2,537
$ 1,445
$ —
$ —
$ —
$ —
Interest Cost 6,428
5,895
19,285
19,578
5,986
6,060
17,958
18,181
Expected Return on Plan Assets (10,596 ) (11,195 ) (31,787 ) (34,933 ) —
—
—
—
Amortization of Prior Service Credits (148 ) (148 ) (443 ) (443 ) (601 ) —
(1,804 ) —
Recognized Net Actuarial Loss 2,351
2,743
7,052
6,975
5,778
4,792
17,334
14,376
Settlement Loss —
3,651
—
17,347
—
—
—
—
Net Periodic Benefit (Credit) Cost $ (1,119 ) $ 1,428
$ (3,356 ) $ 9,969
$ 11,163
$ 10,852
$ 33,488
$ 32,557

~~NOTE 6—COMPONENTS OF COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION NET PERIODIC BENEFIT COSTS:~~

~~Components of Net Periodic Benefit Cost are as follows:~~

CWP Workers' Compensation
For the Three Months Ended September 30, For the Nine Months Ended September 30, For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016 2017 2016 2017 2016
Service Cost $ 1,129
$ 1,041
$ 3,388
$ 3,285
$ 1,463
$ 1,904
$ 4,389
$ 5,713
Interest Cost 1,013
1,053
3,038
3,230
592
638
1,776
1,913
Amortization of Actuarial Gain (1,908 ) (1,188 ) (5,724 ) (3,759 ) (153 ) (101 ) (458 ) (303 )
Administrative Fees 151
—
454
—
138
792
413
2,491
State Administrative Fees and Insurance Bond Premiums —
—
—
—
621
—
2,009
—
Curtailment Gain —
—
—
(1,307 ) —
—
—
—
Net Periodic Benefit Cost $ 385
$ 906
$ 1,156
$ 1,449
$ 2,661
$ 3,233
$ 8,129
$ 9,814

~~Income attributable to discontinued operations included in the CWP net periodic cost above was $1,290~~The effective tax rates for the ~~nine~~three and six months ended ~~September~~June 30, ~~2016~~2022 were 28.9% and ~~was included in Loss from Discontinued Operations, net on~~26.0%, respectively. The effective tax rates for the ~~Consolidated Statements of Income.~~

~~On March 31, 2016, CONSOL Energy completed the sale of its membership interests in BMC (See Note 2 - Discontinued Operations). As a result of the sale, certain obligations of the CWP plan~~three and six months ended June 30, 2021 were transferred to the buyer. This transfer triggered a curtailment gain of $1,307 which was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income. The curtailment resulted in a plan remeasurement which increased the plan liabilities by $7,713 at March 31, 2016.

~~NOTE 7—INCOME TAXES:~~

20.6% and 17.6%, respectively. The effective tax rate for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017 was 8,441.0% and 27.7%, respectively. The effective tax rate~~2022 differs from the U.S. federal statutory rate of ~~35%~~21.0% primarily due to the ~~income tax benefit~~impact of certain permanent differences related to the repurchase of the Convertible Notes (see Note 9 – Long-Term Debt for ~~excess percentage depletion.~~

more information), equity compensation and state taxes. The effective tax rate for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016 was 46.7% and 24.7%, respectively. The effective tax rate~~2021 differs from the U.S. federal statutory rate of ~~35%~~21.0% primarily due to ~~charges to record~~the impact of equity compensation and state valuation allowances and the effects of the 2010-2013 Federal tax audit still in progress in 2016, partially offset by a larger anticipated book loss and the income tax benefit for excess percentage depletion.taxes.

The total amount of uncertain tax positions at ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016~~2021 was ~~$8,437 and $9,103, respectively.~~$67,805. If these uncertain tax positions were recognized, ~~there~~approximately $67,805 would ~~be no effect on CONSOL Energy's~~affect CNX's effective tax rate at ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016.~~2021. There was no change to the unrecognized tax benefits during the three and six months ended June 30, 2022.

~~CONSOL Energy~~CNX recognizes accrued interest and penalties related to uncertain tax positions in interest ~~expense.~~expense and income tax expense, respectively. As of ~~September~~June 30, ~~2017~~2022 and December 31, 2016, the Company reported an accrued interest liability relating to uncertain tax positions of $539 and $305, respectively, in Other Liabilities on the Consolidated Balance Sheets. The accrued interest liability includes $234 of accrued interest expense that is reflected in the Company's Consolidated Statements of Income for the nine months ended September 30, 2017.

~~CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of September 30, 2017 and December 31, 2016, CONSOL Energy~~2021, CNX had no accrued liabilities for ~~tax~~interest and penalties related to uncertain tax positions.

~~CONSOL Energy~~

CNX and its subsidiaries file federal income tax returns with the United States and tax returns within various ~~states and Canadian jurisdictions.~~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 ~~2015. The Joint Committee on Taxation concluded its review of the audit of tax years 2010 through 2014 in the third quarter of 2017.~~2018.

NOTE ~~8—INVENTORIES:~~

~~Inventory components consist of the following:~~

September 30,
2017 December 31,
2016
Coal $ 9,905
$ 7,800
Supplies 53,277
57,661
Total Inventories $ 63,182
$ 65,461

Inventories are stated at the lower of cost or net realizable value. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion and amortization, and other related costs. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's E&P and coal operations.

~~NOTE 9—~~5—PROPERTY, PLANT AND EQUIPMENT:


	June 30, 2022		December 31, 2021
Intangible Drilling Cost	$	5,395,180	$	5,247,800
Gas Gathering Equipment	2,512,621		2,483,561
Proved Gas Properties	1,321,653		1,312,706
Gas Wells and Related Equipment	1,260,268		1,202,731
Unproved Gas Properties	735,831		730,400
Surface Land and Other Equipment	193,085		194,655
Other	187,450		190,249
Total Property, Plant and Equipment	11,606,088		11,362,102
Less: Accumulated Depreciation, Depletion and Amortization	4,593,364		4,372,619

Total Property, Plant and Equipment - Net	$	7,012,724	$	6,989,483

September 30,
2017 December 31,
2016
E&P Property, Plant and Equipment
Intangible drilling cost $ 3,663,552
$ 3,583,565
Proved gas properties 1,950,232
2,016,916
Unproved gas properties 1,031,555
1,116,282
Gas gathering equipment 1,131,982
1,138,299
Gas wells and related equipment 825,201
791,996
Other gas assets 190,400
190,406
Gas advance royalties 13,323
13,762
Total E&P Property, Plant and Equipment $ 8,806,245
$ 8,851,226
Less: Accumulated Depreciation, Depletion and Amortization 3,317,180
3,106,296
Total E&P Property, Plant and Equipment - Net $ 5,489,065
$ 5,744,930

PA Mining Operations Property, Plant and Equipment
Coal and other plant and equipment $ 2,352,826
$ 2,307,668
Coal properties and surface lands 460,688
458,398
Airshafts 378,296
371,752
Mine development 326,152
326,152
Coal advance mining royalties 16,136
16,224
Leased coal lands 26,556
26,566
Total PA Mining Operations and Other Property, Plant and Equipment $ 3,560,654
$ 3,506,760
Less: Accumulated Depreciation, Depletion and Amortization 1,890,856
1,768,712
Total PA Mining Operations and Other Property, Plant and Equipment - Net $ 1,669,798
$ 1,738,048

Other Property, Plant and Equipment
Coal and other plant and equipment $ 494,842
$ 532,919
Coal properties and surface lands 476,281
481,126
Airshafts 10,003
10,003
Mine development 17,989
17,988
Coal advance mining royalties 311,538
310,530
Leased coal lands 60,836
60,836
Total Other Property, Plant and Equipment $ 1,371,489
$ 1,413,402
Less: Accumulated Depreciation, Depletion and Amortization 731,390
755,941
Total Other Property, Plant and Equipment - Net $ 640,099
$ 657,461

Total Company Property, Plant and Equipment - Continuing Operations $ 13,738,388
$ 13,771,388
Less - Total Company Accumulated Depreciation, Depletion and Amortization 5,939,426
5,630,949
Total Property, Plant and Equipment of Continuing Operations - Net $ 7,798,962
$ 8,140,439

NOTE 6—GOODWILL AND OTHER INTANGIBLE ASSETS:

~~Impairment of Long-Lived Assets~~

In ~~February~~December 2017, the Company approved a plan to sell subsidiaries Knox Energy LLC and Coalfield Pipeline Company (collectively, “Knox”). Knox met all of the criteria to be classified as held for sale in February 2017. The sale of Knox closed in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions for more information). The disposal of Knox did not represent a strategic shift that would have had a major effect on the Company’s operations and financial results and was, therefore, not classified as a discontinued operation in accordance with ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360). As part of the required evaluation under the held for sale guidance, Knox’s book value was evaluated and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment of $137,865 was included in Impairment of Exploration and Production Properties within the Other Gas segment of the Consolidated Statements of Income in the nine months ended September 30, 2017.

~~Industry Participation Agreements~~

~~CONSOL Energy had two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for the Company's retained interests.~~

CNX Gas ~~Company is party to~~entered into a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 155 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess was obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. As of December 31, 2016, Hess' entire carry obligation has been met.

~~CNX Gas Company was party to a joint development~~purchase agreement with Noble Energy, ~~Inc. (Noble) with respect~~LLC ("Noble") pursuant to ~~approximately 700 thousand net Marcellus Shale oil and gas acres~~which it acquired Noble’s 50% membership interest in ~~West Virginia and Pennsylvania, in which each party owned~~CNX Gathering, LLC (then named CONE Gathering LLC) ("CNX Gathering"), for a ~~50% undivided interest. In October 2016, CNX Gas entered into an Exchange Agreement with Noble Energy, which terminated the joint development agreement related~~cash purchase price of $305,000 (the "Midstream Acquisition").

Prior to the ~~jointly owned gas assets held~~Midstream Acquisition, the Company accounted for its 50% interest in ~~connection~~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 ~~joint venture with Noble and divided such jointly owned gas assets among CNX Gas and Noble Energy. The transactions contemplated by~~Midstream Acquisition, the ~~Exchange Agreement were closed on December 1, 2016 with an effective date of October 1, 2016. As part of the exchange: each party now owns and operates~~Company obtained a ~~100%~~controlling interest in ~~properties~~CNX Gathering and ~~wells in two separate operating areas; each party has independent~~ control ~~and flexibility with respect to the scope and timing of future development~~ over ~~its operating area; and all acreage operated by CONSOL Energy and Noble Energy, Inc. in their respective operating areas will remain fully dedicated to CONE~~CNX Midstream Partners, ~~LP. The exchange~~LP ("CNXM"). Accordingly, the Midstream Acquisition was accounted for as a ~~mineral conveyance, thus no gain~~business combination using the acquisition method of accounting pursuant to ASC Topic 805, Business Combinations, or ~~loss~~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. The fair value assigned to the previously held equity interest in CNX Gathering and CNXM was ~~recorded~~$799,033 and was determined using the income approach, based on a discounted cash flow methodology.

As part of the allocation of purchase price and in connection with the ~~transaction. In~~fair value of consideration transferred at closing on January 3, 2018, CNX recorded $796,359 of goodwill and $128,781 of other intangible assets which are comprised of customer relationships.

The accumulated impairment losses on goodwill was $473,045, resulting in a carrying value of $323,314, at both June ~~2017, Noble Energy announced that it has closed~~30, 2022 and December 31, 2021.

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


	June 30, 2022		December 31, 2021
Other Intangible Assets:
Gross Amortizable Asset - Customer Relationships	$	109,752	$	109,752
Less: Accumulated Amortization - Customer Relationships	29,486		26,209
Total Other Intangible Assets, net	$	80,266	$	83,543

The customer relationship intangible asset is being amortized on a ~~transaction divesting its upstream~~straight-line basis over approximately 17 years. Amortization expense related to other intangible assets ~~in northern West Virginia~~for the three and ~~southern Pennsylvania~~six months ended June 30, 2022 was $1,638 and 3,277, respectively. Amortization expense related to ~~HG Energy II Appalachia, LLC, a portfolio company~~other intangible assets for the three and six months ended June 30, 2021 was $1,638 and $3,276, respectively. The estimated annual amortization expense is expected to approximate $6,552 per year for each of ~~Quantum Energy Partners.~~the next five years.

NOTE ~~10—SHORT-TERM NOTES PAYABLE:~~7—REVOLVING CREDIT FACILITIES:

~~CONSOL Energy's~~ CNX:

On May 5, 2022, CNX amended its Third Amended and Restated Credit Agreement dated October 6, 2021, which provides for a senior secured ~~credit agreement expires on June 18, 2019. The~~revolving credit facility ~~allows for up~~(as amended, the "CNX Credit Agreement"). Revisions were made to ~~$2,000,000 of borrowings, which includes~~replace LIBOR as a ~~$750,000 letters of credit sub-limit. CONSOL Energy can also request an additional $500,000 increase in~~benchmark interest rate with SOFR, or the ~~aggregate borrowing limit amount.~~

~~The facility is~~ secured ~~by substantially all of~~overnight financing rate. Following the ~~assets of CONSOL Energy~~amendment, CNX remains the borrower and certain of its ~~subsidiaries. Fees~~subsidiaries (not including CNXM) as guarantor loan parties on CNX Credit Agreement. The CNX Credit Agreement replaced the prior CNX revolving credit facility and ~~interest rate spreads~~remains subject to semi-annual redetermination. The CNX Credit Agreement has a $2,250,000 borrowing base and $1,300,000 in elected commitments, including borrowings and letters of credit. The CNX Credit Agreement matures on October 6, 2026, provided that if at any time on or after January 30, 2026, if any of the Company’s Convertible Notes are ~~based~~outstanding and (a) availability under the CNX Credit Agreement minus (b) the aggregate principal amount of all such outstanding Convertible Senior Notes is less than 20% of the aggregate commitments under the CNX Credit Agreement (the first such date, the "Springing Maturity Date"), then the CNX Credit Agreement will mature on the ~~percentage of facility utilization, measured quarterly. Availability~~Springing Maturity Date.

In addition to refinancing all outstanding amounts under the prior CNX revolving credit facility, borrowings under the CNX Credit Agreement may be used by CNX for general corporate purposes.

Under the terms of the CNX Credit Agreement, borrowings will bear interest at CNX's option at either:

•the highest of (i) PNC Bank, National Association’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month SOFR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or

•the SOFR rate plus a margin ranging from 1.85% to 2.85%.

The availability under the CNX Credit Agreement, including availability for letters of credit, is generally limited to a borrowing base, which is determined ~~by the lenders syndication agent and approved~~ by the required number of lenders in good faith by calculating a loan value of ~~CONSOL Energy's~~the Company’s proved ~~natural gas~~ reserves.

The current facility contains a number of affirmative and negative covenants that limit the Company's ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. In April 2016, the facility was amended to require that the Company must: (i) prepay outstanding loans under the revolving credit facility to the extent that cash on hand exceeds $150,000 for two consecutive business days; (ii) mortgage 85% of its proved reserves and 80% of its proved developed producing reserves, in each case, which are included in the borrowing base; (iii) maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof; and (iv) enter into control agreements with respect to such applicable accounts. In addition, the Company pledged the equity interest it holds in CONE Gathering, LLC, and CONE Midstream Partners, LP as collateral to secure loans under the credit agreement.

~~The facility~~CNX Credit Agreement also requires that ~~CONSOL Energy~~CNX maintain a ~~minimum interest coverage~~maximum net leverage ratio of no ~~less~~greater than ~~2.50~~3.50 to 1.00, which is calculated as the ratio of ~~Adjusted~~debt less cash on hand to consolidated EBITDA, ~~to cash interest expense of CONSOL Energy and certain of its subsidiaries,~~

measured quarterly. ~~CONSOL Energy~~CNX must also maintain a minimum current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current liabilities, excluding derivative asset/liability position, and convertible note liability until one year prior to maturity, and borrowings under the revolver, measured quarterly. At September 30, 2017, the interest coverage ratio was 5.46 to 1.00 and the current ratio was 3.09 to 1.00. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems and permits CONSOL Energy to separate its E&P and coal businesses if the leverage ratio (which is, essentially, the ratio of debt to EBITDA) of the E&P business immediately after the separation would not be greater than 2.75 to 1.00. The calculation of all of the ratios exclude CNXM. CNX ~~Coal Resources LP ("CNXC").~~was in compliance with all financial covenants as of June 30, 2022.

At ~~September~~June 30, ~~2017,~~2022, the ~~$2,000,000 facility~~CNX Credit Agreement had no$133,650 of borrowings outstanding and ~~$314,260~~$172,965 of letters of credit outstanding, leaving ~~$1,685,740~~$993,385 of unused capacity. At December 31, ~~2016,~~2021, the ~~$2,000,000 facility~~CNX Credit Agreement had no$192,000 of borrowings outstanding and ~~$325,676~~$184,131 of letters of credit outstanding, leaving ~~$1,674,324~~$923,869 of unused capacity.

CNX Midstream Partners LP (CNXM):

On May 5, 2022 CNXM amended its Amended and Restated Credit Agreement dated October 6, 2021, which provides for a $600,000 senior secured revolving credit facility (as amended, the "CNXM Credit Agreement") that matures on October 6, 2026. Revisions were made to replace LIBOR as a benchmark interest rate with SOFR, or the secured overnight financing rate. CNXM remains the borrower and certain of its subsidiaries remain as guarantor loan parties on the Amended and Restated Credit Agreement. The CNXM Credit Agreement replaced the prior CNXM revolving credit facility and is not subject to semi-annual redetermination. CNX is not a guarantor under the CNXM Credit Agreement.

In addition to refinancing all outstanding amounts under the prior CNXM revolving credit facility, borrowings under the CNXM Credit Agreement may be used by CNXM for general corporate purposes.

Interest on outstanding indebtedness under the CNXM Credit Agreement currently accrues, at CNXM's option, at a rate based on either:

•the SOFR rate plus a margin ranging from 2.10% to 3.10%.

In addition, CNXM is obligated to maintain at the end of each fiscal quarter (x) a maximum net leverage ratio of no greater than between 5.00 to 1.00 ranging to no greater than 5.25 to 1.00 in certain circumstances; (y) a maximum secured leverage ratio of no greater than 3.25 to 1.00 and (z) a minimum interest coverage ratio of no less than 2.50 to 1.00; in each case as calculated in accordance with the terms and definitions determining such ratios contained in the CNXM Credit Agreement. CNXM was in compliance with all financial covenants as of June 30, 2022.

At June 30, 2022, the CNXM Credit Agreement had $188,300 of borrowings outstanding and $30 of letters of credit outstanding, leaving $411,670 of unused capacity. At December 31, 2021, the CNXM Credit Agreement had $185,000 of borrowings outstanding and $30 of letters of credit outstanding, leaving $414,970 of unused capacity.

NOTE ~~11—~~8—OTHER ACCRUED LIABILITIES:


	June 30, 2022		December 31, 2021
Royalties	$	184,769	$	152,498
Accrued Interest	34,568		36,035
Deferred Revenue	15,724		18,984
Transportation Charges	14,705		15,808
Accrued Other Taxes	13,553		12,681
Short-Term Incentive Compensation	6,114		19,591
Accrued Payroll & Benefits	5,868		5,747
Litigation Contingency	5,683		1,200
Purchased Gas Payable	1,257		757
Other	10,950		15,435
Current Portion of Long-Term Liabilities:
Asset Retirement Obligations	7,529		7,154
Salary Retirement	1,879		1,842
Total Other Accrued Liabilities	$	302,599	$	287,732

NOTE 9—LONG-TERM DEBT:


	June 30, 2022		December 31, 2021
Senior Notes due March 2027 at 7.25% (Principal of $700,000 plus Unamortized Premium of $5,070 and $5,609, respectively)	$	705,070	$	705,609
Senior Notes due January 2029 at 6.00%, Issued at Par Value	500,000		500,000
CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $4,519 and $4,808, respectively )*	395,481		395,192
Convertible Senior Notes due May 2026 at 2.25% (Principal of $330,654 and $345,000 less Unamortized Discount and Issuance Costs of $7,377 and $91,284, respectively)	323,277		253,716
CNX Midstream Partners LP Revolving Credit Facility*	188,300		185,000
CNX Revolving Credit Facility	133,650		192,000
Less: Unamortized Debt Issuance Costs	16,082		17,396
	2,229,696		2,214,121
Less: Current Portion	322,622		—
Long-Term Debt	$	1,907,074	$	2,214,121

*CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or CNXM's Credit Facility.

In April 2020, CNX issued $345,000 in aggregate principal amount of Convertible Notes in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, including $45,000 aggregate principal amount of Convertible Notes issued pursuant to the exercise in full of the initial purchasers’ option to purchase additional Convertible Notes. The Convertible Notes are senior, unsecured obligations of the Company. The Convertible Notes bear interest at a fixed rate of 2.25% per annum, payable semi-annually in arrears on May 1 and November 1 of each year, commencing on November 1, 2020. Proceeds from the issuance of the Convertible Notes totaled $334,650, net of initial purchaser discounts and issuance costs. The Convertible Notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

The initial conversion rate is 77.8816 shares of CNX's common stock per $1,000 principal amount of Convertible Notes, which represents an initial conversion price of approximately $12.84 per share, subject to adjustment upon the occurrence of specified events.

The Convertible Notes will mature on May 1, 2026, unless earlier repurchased, redeemed or converted. Before February 1, 2026, note holders will have the right to convert their Convertible Notes only upon the occurrence of the following events:

•during any calendar quarter (and only during such calendar quarter) commencing after June 30, 2020, if the Last Reported Sale Price per share of Common Stock exceeds one hundred and thirty percent (130%) of the Conversion

September 30,
2017 December 31,
2016
Debt:
Senior Notes due April 2022 at 5.875% (Principal of $1,730,975 and $1,850,000 plus Unamortized Premium of $3,804 and $4,731, respectively) $ 1,734,779
$ 1,854,731
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $4,977 and $5,656, respectively) 495,023
494,344
Revolving Credit Facility - CNX Coal Resources LP 188,000
201,000
MEDCO Revenue Bonds in Series due September 2025 at 5.75% 102,865
102,865
Senior Notes due April 2020 at 8.25%, Issued at Par Value —
74,470
Senior Notes due March 2021 at 6.375%, Issued at Par Value —
20,611
Advance Royalty Commitments (7.73% Weighted Average Interest Rate) 2,678
2,678
Other Note Maturing in 2018 (Principal of $692 and $1,789, respectively, less Unamortized Discount of $117 at December 31, 2016) 692
1,672
Less: Unamortized Debt Issuance Costs 22,265
27,699
2,501,772
2,724,672
Less: Amounts Due in One Year* 990
1,677
Long-Term Debt $ 2,500,782
$ 2,722,995
Price for each of at least twenty (20) Trading Days (whether or not consecutive) during the thirty (30) consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter;

•during the five (5) consecutive Business Days immediately after any ten (10) consecutive trading day period (such ten (10) consecutive Trading Day period, the "Measurement Period") if the trading Price per $1,000 principal amount of Notes, as determined following a request by a Holder in accordance with the procedures set forth below, for each trading day of the Measurement Period was less than ninety eight percent (98%) of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day;

* Excludes•if CNX calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or

•upon the occurrence of certain specified corporate events as set forth in the indenture governing the Convertible Notes.

From and after February 1, 2026, note holders may convert their Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date.

Upon conversion, the Company may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture governing the Convertible Notes. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the Convertible Notes, that occur prior to the maturity date, the Company will increase the conversion rate, in certain circumstances, for a holder who elects to convert its Convertible Notes in connection with such a corporate event.

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. The Company’s current intent is to settle the principal amount of the Convertible Notes in cash upon conversion.

If certain corporate events that constitute a "Fundamental Change" (as defined in the indenture governing the Convertible Notes) occur, then noteholders may require the Company to repurchase their Convertible Notes at a cash repurchase price equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock.

Pursuant to the terms of the Convertible Notes indenture, the Sale Price per share of Common Stock condition for conversion of the Convertible Notes was satisfied as of June 30, 2022, and, accordingly, holders of Convertible Notes are permitted to convert any of their Convertible Notes, at their option, at any time during the quarter beginning on July 1, 2022 and ending on September 30, 2022, subject to all terms and conditions set forth in the Convertible Notes indenture. Therefore, as of June 30, 2022, the net carrying value of the Convertible Notes was classified as current in the Consolidated Balance Sheet.

On January 1, 2022, the Company adopted Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity using the modified transition approach with the cumulative effect recognized as an adjustment to the opening balance of retained earnings. This guidance is applicable to the Convertible Senior Notes due May 2026 ("Convertible Notes") that were issued in April 2020, for which the embedded conversion option was required to be separately accounted for as a component of stockholders’ equity. Upon adoption on January 1, 2022, long-term debt increased by $82,327 representing the net impact of two adjustments: (1) the $107,260 value of the embedded conversion, which is net of allocated offering costs, previously classified in additional paid-in-capital in stockholders’ equity, and (2) a $24,933 increase to retained earnings for the cumulative effect of adoption primarily related to the non-cash interest expense recorded for the amortization of the portion of the Convertible Notes allocated to stockholders’ equity. In addition, there was a decrease of $22,990 to deferred income taxes, a $5,986 decrease to retained earnings, and a $78,284 decrease in stockholders equity in the Consolidated Balance Sheet. Prospectively, the reported interest expense for the Convertible Notes will no longer include the non-cash interest expense of the equity component as required under prior accounting standards and will be equal to the 2.25% cash coupon rate. Also, as required by the new accounting guidance, the Company will use the if-converted method instead of the treasury stock method for the assumed conversion of the Convertible Notes on a prospective basis when calculating earnings per share.

Prior to the adoption of ASU 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity, the Convertible Notes were separated into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of a similar debt instrument that does not have an associated conversion feature. The fair value was based on market data available for publicly traded, senior, unsecured corporate bonds with similar maturity, which represent Level 2 observable inputs. The carrying amount of the equity component, representing the conversion option, was

determined by deducting the fair value of the liability component from the principal value of the Convertible Notes and was recorded in Capital ~~Lease Obligations~~in Excess of ~~$9,981~~Par Value in the Consolidated Statement of Stockholders Equity and ~~$10,323 at September 30, 2017~~was not remeasured as long as it continued to meet the conditions for equity classification. The excess of the principal amount of the Convertible Notes over the liability component and ~~December 31, 2016, respectively.~~the debt issuance costs was amortized to interest expense over the contractual term of the Convertible Notes using the effective interest method. In accounting for the debt issuance costs of $10,350, the Company allocated the total amount incurred to the liability and equity components using the same proportions as the proceeds of the Convertible Notes. Issuance costs attributable to the liability component were $7,024 and were being amortized to interest expense using the effective interest method over the contractual term of the Convertible Notes. Issuance costs attributable to the equity component were $3,326 and were netted with the equity component in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity.

The net carrying amount of the liability and equity components of the Convertible Notes was as follows:


	June 30, 2022		December 31, 2021
Liability Component:
Principal	$	330,654	$	345,000
Unamortized Discount	—		(85,950)
Unamortized Issuance Costs	(7,377)		(5,334)
Net Carrying Amount	$	323,277	$	253,716

Fair Value	$	501,767	$	453,765
Fair Value Hierarchy	Level 2		Level 2

Equity Component, net of Purchase Discounts and Issuance Costs	$	—	$	78,284

Interest expense related to the Convertible Notes is as follows:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2022		2021		2022		2021
Contractual Interest Expense	$	1,918	$	1,941	$	3,857	$	3,881
Amortization of Debt Discount	—		3,809		—		7,531
Amortization of Issuance Costs	483		256		954		509
Total Interest Expense	$	2,401	$	6,006	$	4,811	$	11,921

In connection with the offering of the Convertible Notes, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls"). The Capped Calls each have an initial strike price of $12.84 per share, subject to certain adjustments, which correspond to the initial conversion price of the Convertible Notes. The Capped Calls have an initial cap price of $18.19 per share, subject to certain adjustments. The Capped Calls cover, subject to anti-dilution adjustments, the aggregate number of shares of the Company’s common stock that initially underlie the Convertible Notes, and are expected generally to reduce potential dilution to the Company’s common stock upon any conversion of Convertible Notes and/or offset any cash payments the Company is 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, based on the cap price of the Capped Call Transactions. The conditions that cause adjustments to the initial strike price of the Capped Calls mirror the conditions that result in corresponding adjustments for the Convertible Notes. For accounting purposes, the Capped Calls are separate transactions, and not part of the terms of the Convertible Notes. As these transactions meet certain accounting criteria, the Capped Calls are recorded in stockholders’ equity and are not accounted for as derivatives. The cost of $35,673 incurred in connection with the Capped Calls was recorded as a reduction to Capital in Excess of Par Value.

During the three ~~and nine~~ months ended ~~September~~June 30, 2017, CONSOL Energy called the remaining $74,470 balance on its 8.25% senior notes due in April 2020 and the remaining $20,611 balance on its 6.375% senior notes due in March 2021. The call price was $101.375 for the 8.25% senior notes due in April 2020 and $102.125 for the 6.375% senior notes due in March 2021.

~~During the nine months ended September 30, 2017, CONSOL Energy~~2022, CNX purchased ~~$119,025~~$14,346 of its outstanding ~~5.875% senior notes due in April 2022.~~

Convertible Notes. As part of ~~these transactions,~~this transaction, a loss of ~~$2,019 and $1,233~~$12,981 was included in Loss on Debt Extinguishment onin the Consolidated Statements of Income ~~for~~during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, respectively.~~2022.

1821

NOTE ~~12—~~10—COMMITMENTS AND CONTINGENT LIABILITIES:

~~CONSOL Energy~~CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, ~~wrongful death,~~royalty accounting, damage to property, ~~exposure to hazardous substances,~~climate change, governmental regulations including environmental violations and remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. ~~CONSOL Energy~~CNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of ~~CONSOL Energy.~~CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of ~~CONSOL Energy;~~CNX; however, such amounts cannot be reasonably estimated.

The ~~amount claimed against~~1992 Coal Industry Retiree Health Benefit Act ("Coal Act"), in Section 9711, requires coal companies that were providing health benefits to United Mine Workers of America ("UMWA") retirees as of February 1993 to continue providing health benefits to such individuals, in substantially the same coverages, for as long as the last signatory operator remains in business. Section 9711 also requires any "related person" to be joint and severally liable for the provision of these health benefits. On May 1, 2020, the court in the Murray Energy Corporation ("Murray") bankruptcy proceedings approved a settlement agreement between Murray and the UMWA that transferred to the UMWA 1992 Benefit Plan the Coal Act liabilities for retirees in Murray’s Section 9711 plan. The retirees transferred by Murray to the 1992 Benefit Plan include approximately 2,159 retirees allegedly traced to the December 2013 sale by CONSOL Energy ~~is disclosed below when an amount is expressly stated~~Inc. to Murray Energy of the following possible last signatory operators: Consolidation Coal Company, McElroy Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Keystone Coal Mining Corp., and Eight-Four Coal Mining Company (the "Sold Subsidiaries"). On May 2, 2020, the Trustees of the UMWA 1992 Benefit Plan sued CNX and CONSOL Energy Inc. ("CONSOL'") in federal court contending that the ~~lawsuit or claim, which is not often~~Sold Subsidiaries were last signatory operators and that CNX and CONSOL are related persons to the ~~case.~~

Sold Subsidiaries and, as such, CNX and CONSOL are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The ~~following lawsuits~~1992 Plan seeks, among other relief, a declaration that CNX and ~~claims include those~~CONSOL are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 Plan; that CNX and CONSOL are liable to post the security required by Section 9712; and, that CNX and CONSOL are liable to pay per beneficiary premiums until the eligible retirees are enrolled in a Section 9711 plan, and other fees, costs and disbursements under the Coal Act. On March 29, 2022, the Court denied the Defendants’ Motions to Dismiss and we are now defending this action on the merits. Further, under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, CONSOL agreed to indemnify CNX for ~~which~~all coal-related liabilities, including this lawsuit. With respect to this matter, although a loss is ~~probable and an accrual has been recognized:~~

Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of force-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on allegations CNX Gas Company failed to either pay royalties due to conflicting claimants or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order certifying four issues for class treatment: (1) allegedly excessive deductions; (2) royalties based on purported improperly low prices; (3) deduction of severance taxes; and (4) Plaintiffs' request for an accounting. On April 13, 2017, CNX filed a Petition for Allowance of Appeal with the Fourth Circuit, and on May 22, 2017 the Petition was denied. The casepossible, it is now back in the trial court for further proceedings. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Addison Litigation: This class action lawsuit was filed on April 28, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due to these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order denying class certification in this matter. CONSOL Energy believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

~~The following royalty, land rights and other lawsuits and claims include those for which a loss is reasonably possible, but~~ not probable, and accordingly anno accrual has ~~not~~ been recognized. ~~These claims are influenced by many factors which prevent~~

On July 22, 2021, CNX received a letter from the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert reports on damages and non-monetary issues being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficientUMWA 1974 Pension Plan requesting information ~~becomes available.~~

Fitzwater Litigation: Three nonunion retired coal miners have sued CONSOL Energy Inc., Fola Coal Company (AMVEST), Consolidation Coal Company and CONSOL of Kentucky Inc. (COK) in West Virginia Federal Court alleging ERISA violations in the termination of retiree health care benefits. The Plaintiffs contend they relied to their detriment on oral statements and promises of "lifetime health benefits" allegedly made by various members of management during Plaintiffs' employment and that they were allegedly denied access to Summary Plan Documents that clearly reservedrelated to the ~~Company~~facts and circumstances surrounding the ~~right~~2013 sale of certain of its coal subsidiaries to ~~modify or terminate~~Murray Energy. The letter indicates that litigation related to potential withdrawal liabilities from the ~~CONSOL~~plan created by the 2019 bankruptcy of Murray Energy ~~Inc. Retiree Health and Welfare Plan. Pursuant to plaintiffs' amended complaint filed on April 24, 2017, plaintiffs~~

request that retiree health benefits be reinstated and seek to represent a class of all nonunion retirees who were associated with AMVEST and COK areas of operation.The Company believes it has meritorious defense and intends to vigorously defendis reasonably foreseeable. At this ~~suit.~~

~~Casey Litigation:This lawsuit against CONSOL Energy Inc., Consolidation Coal Company and CONSOL Buchanan Mining Company~~time, no liability has been ~~filed on August 23,~~assessed. Under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, ~~by the same lawyers, in the same court, and raises the same issues and seeks the same relief as the Fitzwater Litigation. Filed on behalf of two nonunion retired coal miners, plaintiffs seek~~CONSOL agreed to ~~represent a class of~~indemnify CNX for all nonunion retirees that were employed by CONSOL subsidiaries that operated in McDowell and Mercer Counties, West Virginia and Buchanan and Tazewell Counties, Virginia. Like Fitzwater, the Company believes it has meritorious defenses and intends to vigorously defend this suit.coal-related liabilities including any potential withdrawal liabilities.

At ~~September~~June 30, ~~2017, CONSOL Energy~~2022, CNX has provided the following financial guarantees, unconditional purchase obligations, and letters of credit to certain ~~third parties,~~third-parties as described by major category in the following ~~table.~~tables. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these ~~financial guarantees~~unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. ~~CONSOL Energy~~CNX management believes that ~~these guarantees~~the commitments in the following table will expire without being funded, and therefore ~~the commitments~~ will not have a material adverse effect on CNX's financial condition.


	Amount of Commitment Expiration Per Period											Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years			Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:											Letters of Credit:
Employee-Related	$	83,836	$	46,214	$	37,622	$	—	$	—
Environmental	998		998		—		—		—
Firm Transportation											Firm Transportation	$	169,908	$	169,908	$	—	$	—	$	—

Other	229,426		45,590		183,836		—		—		Other	3,087		3,087		—		—		—
Total Letters of Credit	314,260		92,802		221,458		—		—		Total Letters of Credit	172,995		172,995		—		—		—
Surety Bonds:											Surety Bonds:
Employee-Related	109,660		106,980		2,680		—		—		Employee-Related	2,600		2,600		—		—		—
Environmental	482,516		473,289		9,227		—		—		Environmental	12,054		5,884		6,170		—		—
Financial Guarantees											Financial Guarantees	81,270		81,270		—		—		—
Other	17,252		16,136		1,115		1		—		Other	8,791		7,223		1,568		—		—
Total Surety Bonds	609,428		596,405		13,022		1		—		Total Surety Bonds	104,715		96,977		7,738		—		—
Guarantees:
Other	36,314		9,752		15,858		9,875		829
Total Guarantees	36,314		9,752		15,858		9,875		829
Total Commitments	$	960,002	$	698,959	$	250,338	$	9,876	$	829	Total Commitments	$	277,710	$	269,972	$	7,738	$	—	$	—

~~Included in~~Excluded from the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal Company and certain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations to a subsidiary of Murray Energy Corporation (Murray Energy). As partspin-off of the ~~sales agreement,~~Company's coal business in November 2017. Although CONSOL ~~Energy~~ has ~~guaranteed certain equipment lease~~agreed to indemnify CNX to the extent that CNX would be called upon to pay any of these liabilities, there is no assurance that CONSOL will satisfy its obligations ~~and coal sales agreements that were assumed by Murray Energy. In~~to indemnify CNX in the event that ~~Murray Energy would default~~CNX is so called upon (See "Item 1A. Risk Factors" in CNX's 2021 Annual Report on Form 10-K and in our Quarterly Report on Form 10-Q for the obligations defined in the agreements, CONSOL Energy would be required to perform under the guarantees. If CONSOL Energy would be required to perform, the stock purchase agreement provides various recourse actions. At September 30, 2017 and Decemberquarter ended March 31, 2016, the fair value of these guarantees was $1,130 and $1,362, respectively, and is included in Other Accrued Liabilities on the Consolidated Balance Sheets. The fair value of certain of the guarantees was determined using CONSOL Energy’s risk-adjusted interest rate. Significant increases or decreases in the risk-adjusted interest rates may result in a significantly higher or lower fair value measurement. Coal sales agreement guarantees were valued based on an evaluation of coal market pricing compared to contracted sales price and includes an adjustment2022 for nonperformance risk. No other amounts related to financial guarantees and letters of credit are recorded as liabilities in the financial statements. Significant judgment is required in determining the fair value of these guarantees. The guarantees of the leases and sales agreements are classified within Level 3 of the fair value hierarchy.additional information).

As part of the sale of the Buchanan Mine (See Note 2 - Discontinued Operations), CONSOL Energy has guaranteed certain equipment lease obligations that were assumed by Coronado. In the event that Coronado would default on the obligations defined in the agreements, CONSOL Energy would be required to perform under the guarantees.

CONSOL Energy regularly evaluates the likelihood of default for all guarantees based on an expected loss analysis and records the fair value, if any, of its guarantees as an obligation in the consolidated financial statements.

~~CONSOL Energy and~~ CNX ~~Gas Company enter~~enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded onin the Consolidated Balance Sheets. As of ~~September~~June 30, ~~2017,~~2022, the purchase obligations for each of the next five years and beyond ~~were~~are as follows:


Obligations Due	Amount
Less than 1 year	$	253,598
1 - 3 years	446,421
3 - 5 years	385,865
More than 5 years	826,383
Total Purchase Obligations	$	1,912,267

Obligations Due Amount
Less than 1 year $ 188,085
1 - 3 years 268,866
3 - 5 years 243,787
More than 5 years 540,809
Total Purchase Obligations $ 1,241,547

NOTE ~~13—~~11—DERIVATIVE INSTRUMENTS:

~~CONSOL Energy~~CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The change in fair value of the interest rate swap agreements is accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings.

In March 2020, CNX entered into interest rate swaps related to $175,000 of borrowings under the Cardinal States Facility and CSG Holdings Facility. In order to manage exposure to interest rate volatility, each respective entity entered into an interest rate swap for the full outstanding principal amounts inclusive of a put option at 25 basis points. The underlying notional for each swap and put option reduced over time based upon the expected amortization profile for each respective credit facility. In addition, CSG Holdings entered into a call option commencing March 31, 2023. In August 2021, these swaps were terminated in conjunction with the repayment and termination of both the Cardinal States Facility and the CSG Holdings Facility.

In June 2019, CNX entered into an interest rate swap agreement related to $160,000 of borrowings under the CNX Credit Facility which has the economic effect of modifying the variable-interest obligation into a fixed-interest obligation over a three-year period. In March 2020, this swap was terminated and replaced via a new interest rate swap, effective immediately, into a new four-year interest rate swap inclusive of a put option at zero basis points.

In March 2020, CNX entered into a four-year interest rate swap related to an additional $250,000 of borrowings under the CNX Credit Facility, inclusive of a put option at zero basis points, effective April 3, 2020. In December 2020, CNX executed an offsetting $250,000 interest rate swap, effective immediately, which expires in April 2024. Consistent with the previous interest rate swap agreements, the $250,000 interest rate swaps were entered into to manage CNX's exposure to interest rate volatility.

CNX enters into financial derivative instruments (over-the-counter swaps) to manage its exposure to ~~commodity price volatility. These~~ natural gas price fluctuations. Typically, CNX "sells" swaps under which it receives a fixed price from counterparties and ~~NGL~~pays a floating market price. In order to lock in certain margins while balancing its basis hedges, during the first quarter of 2022, CNX purchased, rather than sold, financial swaps for the period April through October of 2022. In order to enhance production flexibility, during the first quarter of 2021, CNX purchased, rather than sold, financial swaps for the period April through October of 2021. Under these purchased financial swaps, CNX pays a fixed price to and receive a floating price from its hedge counterparties. Purchased swaps have the effect of reducing total hedged volumes for the period of the swap. Natural gas commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings.

~~CONSOL Energy~~CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.

None of the Company's counterparty master agreements currently require ~~CONSOL Energy~~CNX to post collateral for any of its positions. However, as stated in the applicable counterparty master agreements, if ~~CONSOL Energy's~~CNX's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, ~~CONSOL Energy~~CNX would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with our counterparties. ~~CONSOL Energy~~CNX recognizes all financial derivative instruments as either assets or liabilities at fair value onin the Consolidated Balance Sheets on a gross basis.

Each of ~~CONSOL Energy's~~the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, ~~CONSOL Energy~~CNX and the applicable counterparty would net settle all open hedge positions.

The total notional amounts of ~~production of CONSOL Energy's~~CNX's derivative instruments ~~at September 30, 2017 and December 31, 2016~~ were as follows:


	June 30,			December 31,		Forecasted to
	2022			2021		Settle Through
Natural Gas Commodity Swaps (Bcf)	1,715.6			1,686.1		2027
Natural Gas Basis Swaps (Bcf)	1,259.5		*	1,233.3		2027
Interest Rate Swaps	$	410,000		$	410,000	2024

*Net of purchased natural gas basis swaps of 9.0 Bcf.

September 30, December 31, Forecasted to
2017 2016 Settle Through
Natural Gas Commodity Swaps (Bcf) 898.4 744.7
2021
Natural Gas Basis Swaps (Bcf) 578.9 482.0
2021
Propane Commodity Swaps (Mbbls) —
126.0
—
24

The gross fair value of ~~CONSOL Energy's~~CNX's derivative instruments ~~at September 30, 2017 and December 31, 2016~~ was as follows:


	June 30,		December 31,
	2022		2021
Current Assets:
Commodity Derivative Instruments:
Commodity Swaps	$	3,974	$	92
Basis Only Swaps	125,654		94,682
Interest Rate Swaps	7,864		228
Total Current Assets	$	137,492	$	95,002

Other Non-Current Assets:
Commodity Derivative Instruments:
Commodity Swaps	$	26,444	$	12,419
Basis Only Swaps	387,508		119,077
Interest Rate Swaps	6,339		498
Total Other Non-Current Assets	$	420,291	$	131,994

Current Liabilities:
Commodity Derivative Instruments:
Commodity Swaps	$	1,152,278	$	505,460
Basis Only Swaps	51,463		13,206
Interest Rate Swaps	6,974		2,932
Total Current Liabilities	$	1,210,715	$	521,598

Non-Current Liabilities:
Commodity Derivative Instruments:
Commodity Swaps	$	1,864,954	$	642,442
Basis Only Swaps	29,121		41,332
Interest Rate Swaps	5,661		3,580
Total Non-Current Liabilities	$	1,899,736	$	687,354

Asset Derivative Instruments Liability Derivative Instruments
September 30, December 31, September 30, December 31,
2017 2016 2017 2016
Commodity Swaps:
Prepaid Expense $ 19,840
$ 16
Other Accrued Liabilities $ 45,097
$ 209,980
Other Assets 40,105
29,596
Other Liabilities 47,109
67,139
Total Asset $ 59,945
$ 29,612
Total Liability $ 92,206
$ 277,119

Basis Only Swaps:
Prepaid Expense $ 25,252
$ 56,916
Other Accrued Liabilities $ 33,077
$ 21,593
Other Assets 14,119
35,603
Other Liabilities 19,963
11,575
Total Asset $ 39,371
$ 92,519
Total Liability $ 53,040
$ 33,168
The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows:


	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2022		2021		2022		2021
Cash (Paid) Received in Settlement of Commodity Derivative Instruments:
Natural Gas:
Commodity Swaps	$	(558,374)	$	(16,492)	$	(830,193)	$	(9,942)

Basis Swaps	27,983		6,133		28,961		1,988
Total Cash Paid in Settlement of Commodity Derivative Instruments	(530,391)		(10,359)		(801,232)		(7,954)

Unrealized (Loss) Gain on Commodity Derivative Instruments:
Natural Gas:
Commodity Swaps	(197,309)		(629,688)		(1,851,422)		(727,147)

Basis Swaps	75,057		101,188		273,618		229,656
Total Unrealized Loss on Commodity Derivative Instruments	(122,252)		(528,500)		(1,577,804)		(497,491)

(Loss) Gain on Commodity Derivative Instruments:
Natural Gas:
Commodity Swaps	(755,683)		(646,180)		(2,681,615)		(737,089)

Basis Swaps	103,040		107,321		302,579		231,644
Total Loss on Commodity Derivative Instruments	$	(652,643)	$	(538,859)	$	(2,379,036)	$	(505,445)

The effect of ~~derivative instruments~~interest rate swaps on ~~CONSOL Energy's~~Interest Expense in the Company's Consolidated Statements of Income was as follows:


	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2022		2021		2022		2021
Cash Paid in Settlement of Interest Rate Swaps	$	(763)	$	(1,240)	$	(1,700)	$	(2,467)
Unrealized Gain on Interest Rate Swaps	2,131		465		7,353		4,659
Gain (Loss) on Interest Rate Swaps	$	1,368	$	(775)	$	5,653	$	2,192

For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Cash Received (Paid) in Settlement of Commodity Derivative Instruments:
  Commodity Swaps:
    Natural Gas $ (312 ) $ 28,175
$ (40,428 ) $ 201,624
    Propane —
22
(1,216 ) (92 )
  Natural Gas Basis Swaps 17,983
10,440
(20,073 ) 1,771
Total Cash Received (Paid) in Settlement of Commodity Derivative Instruments 17,671
38,637
(61,717 ) 203,303

Unrealized Gain (Loss) on Commodity Derivative Instruments:
  Commodity Swaps:
    Natural Gas (18,789 ) 54,676
214,097
(289,722 )
    Propane —
48
1,147
(744 )
  Natural Gas Basis Swaps 20,301
85,234
(73,019 ) 88,276
  Reclassified from Accumulated OCI —
19,597
—
52,759
Total Unrealized Gain (Loss) on Commodity Derivative Instruments 1,512
159,555
142,225
(149,431 )

Gain (Loss) on Commodity Derivative Instruments:
  Commodity Swaps:
    Natural Gas (19,101 ) 82,851
173,669
(88,098 )
    Propane —
70
(69 ) (836 )
  Natural Gas Basis Swaps 38,284
95,674
(93,092 ) 90,047
  Reclassified from Accumulated OCI —
19,597
—
52,759
Total Gain on Commodity Derivative Instruments $ 19,183
$ 198,192
$ 80,508
$ 53,872

~~Changes in Accumulated OCI, net of tax, attributable to cash flow hedges that were de-designated at December 31, 2014 were as follows:~~

For the Three Months Ended For the Nine Months Ended
September 30, 2016
Beginning Balance – Accumulated OCI
$ 22,453
$ 43,470
Less: Gain Reclassified from Accumulated OCI (Net of tax: $7,139, $19,284) 12,458
33,475
Ending Balance – Accumulated OCI
$ 9,995
$ 9,995

The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and normal sales exception and are not subject to derivative instrument accounting.

NOTE ~~14—~~12—FAIR VALUE OF FINANCIAL INSTRUMENTS:

~~CONSOL Energy~~CNX determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, ~~LIBOR-based~~LIBOR and SOFR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use.

The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:

Level ~~One~~1 - Quoted prices for identical instruments in active markets.

Level ~~Two~~2 - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach

models that use significant observable inputs, including NYMEX forward curves, ~~LIBOR-based~~LIBOR and SOFR-based discount rates and basis forward curves.

Level ~~Three~~3 - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Company's third-party guarantees are the credit risk of the third-party and the third-party surety bond markets. A significant increase or decrease in these values, in isolation, would have a directionally similar effect resulting in higher or lower fair value measurement of the Company's Level 3 guarantees.

In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

The financial ~~instruments~~instrument measured at fair value on a recurring basis ~~are~~is summarized below:


	Fair Value Measurements at June 30, 2022						Fair Value Measurements at December 31, 2021
Description	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Gas Derivatives	$	—	$	(2,553,974)	$	—	$	—	$	(976,170)	$	—
Interest Rate Swaps	$	—	$	1,568	$	—	$	—	$	(5,786)	$	—

Fair Value Measurements at September 30, 2017 Fair Value Measurements at December 31, 2016
Description

(Level 1)

(Level 2)

(Level 3)

(Level 1)

(Level 2)

(Level 3)
Gas Derivatives $ —
$ (45,930 ) $ —
$ —
$ (188,156 ) $ —
Murray Energy Guarantees $ —
$ —
$ (1,130 ) $ —
$ —
$ (1,362 )

~~The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:~~

~~Cash and cash equivalents:~~ ~~The carrying amount reported in the Consolidated Balance Sheets for cash and cash equivalents approximates its fair value due to the short-term maturity of these instruments.~~

~~Long-term debt:~~ The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:


	September 30, 2017				December 31, 2016					June 30, 2022				December 31, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value			Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and Cash Equivalents	$	285,708	$	285,708	$	60,475	$	60,475	Cash and Cash Equivalents	$	238	$	238	$	3,565	$	3,565
Long-Term Debt	$	2,524,037	$	2,565,366	$	2,752,371	$	2,717,582

Long-Term Debt (Excluding Debt Issuance Costs)*									Long-Term Debt (Excluding Debt Issuance Costs)*	$	2,245,778	$	2,292,108	$	2,231,517	$	2,483,019

Cash and cash equivalents represent ~~highly- liquid~~highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that is not actively traded is valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

*On January 1, 2022, the Company adopted ASU 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity using the modified transition approach with the cumulative effect recognized as an adjustment to the opening balance of retained earnings (See Note 9 – Long-Term Debt for more information).

NOTE ~~15—~~13—SEGMENT INFORMATION:

~~CONSOL Energy consists of two principal business divisions: Exploration~~The Company reports segment information based on the "management" approach. The management approach designates the internal reporting used by management for making decisions and ~~Production (E&P) and Pennsylvania (PA) Mining Operations. The principal activity~~assessing performance as the source of the ~~E&P division, which includes four~~Company’s reportable segments.

The Company evaluates the performance of its reportable segments based on total revenue and other operating income, and operating expenses directly attributable to that segment. Certain expenses are managed outside the reportable segments and therefore are not allocated. These expenses include, but are not limited to, interest expense and other corporate expenses such as selling, general and administrative costs.

CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas ~~wholesalers. The E&P division's~~wholesalers and the Company has 2 reportable segments ~~are Marcellus~~that conducts those operations: Shale ~~Utica Shale,~~and Coalbed ~~Methane and Other Gas.~~Methane. The Other ~~Gas segment is primarily related to~~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, ~~other corporate expenses, selling, general and administrative activities,~~ as well as various other activities assigned to the E&P division but not allocated to each individual segment. The principal activities of the PA Mining Operations division are mining, preparation and marketing of thermal coal, sold primarily to power generators. It also includes selling, general and administrative activities, as well as various other activities assigned to the PA Mining Operations division.

~~CONSOL Energy’s Other division includes~~ expenses ~~from various corporate and diversified business activities~~ that are ~~not allocated to~~managed outside the E&P or PA Mining Operations divisions. The diversified business activities include CNX Marine Terminal, closed and idle mine activities, water operations, selling, general and administrative activities,reportable segments as ~~well as various other non-operated activities, none of which are individually significant to the Company.~~

Prior to the sale of the Buchanan Mine on March 31, 2016 and the Miller Creek and Fola Complexes on August 1, 2016 (see Note 2 - Discontinued Operations), CONSOL Energy had a Coal division. The Coal division had three reportable segments; PA Operations, Virginia (VA) Operations and Other Coal. The VA Operations segment included the Buchanan Mine and the Other Coal segment was primarily comprised of the assets and operations of the Miller Creek and Fola Complexes, as well as coal terminal operations, closed and idle mine activities, selling, general and administrative activities and various other non-operated activities. PA Operations now constitutes its own division and reportable segment, and the remaining activity in the Other Coal segment became part of CONSOL Energy's diversified business activities in the Other division.

~~In the preparation of the following information, intersegment sales have been recorded at amounts approximating market.~~discussed above. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level for E&P and are not allocated between each individual E&P segment. These assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy, whereby each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

2427

Industry segment results for the three months ended ~~September~~June 30, ~~2017~~:2022 are:


	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	923,269	$	79,583	$	554	$	1,003,406	(A)
Purchased Gas Revenue	—		—		46,552		46,552
Loss on Commodity Derivative Instruments	(489,026)		(41,222)		(122,395)		(652,643)
Other Revenue and Operating Income	17,990		—		5,113		23,103		(B)
Total Revenue and Other Operating Income (Loss)	$	452,233	$	38,361	$	(70,176)	$	420,418
Total Operating Expense	$	189,884	$	31,470	$	109,169	$	330,523
Earnings (Loss) Before Income Tax	$	262,349	$	6,891	$	(222,316)	$	46,924
Segment Assets	$	6,417,552	$	969,944	$	1,308,394	$	8,695,890	(C)
Depreciation, Depletion and Amortization	$	95,910	$	13,037	$	7,233	$	116,180
Capital Expenditures	$	131,279	$	3,526	$	1,863	$	136,668

Marcellus
Shale
Utica Shale Coalbed Methane
Other
Gas

Total
E&P
PA Mining Operations Other
Adjustments and
Eliminations
Consolidated
Sales—Outside $ 133,793
$ 43,375
$ 46,744
$ 10,531
$ 234,443
$ 279,245
$ —
$ —
$ 513,688
(A)
Gain on Commodity Derivative Instruments 11,299
2,517
3,093
2,274
19,183
—
—
—
19,183

Other Outside Sales —
—
—
—
—
—
16,959
—
16,959

Sales—Purchased Gas —
—
—
13,384
13,384
—
—
—
13,384

Freight—Outside —
—
—
—
—
21,803
—
—
21,803

Intersegment Transfers —
—
—
—
—
—
5,994
(5,994 ) —

Total Sales and Freight $ 145,092
$ 45,892
$ 49,837
$ 26,189
$ 267,010
$ 301,048
$ 22,953
$ (5,994 ) $ 585,017

Earnings (Loss) From Continuing Operations Before Income Tax $ 12,123
$ 7,342
$ 5,454
$ (4,693 ) $ 20,226
$ 21,011
$ (34,136 ) $ (5,994 ) $ 1,107
(B)
Segment Assets $ 5,941,092
$ 1,912,656
$ 1,113,540
$ 12,280
$ 8,979,568
(C)
Depreciation, Depletion and Amortization $ 101,585
$ 41,638
$ 5,545
$ —
$ 148,768

Capital Expenditures $ 147,522
$ 27,157
$ 2,615
$ —
$ 177,294

(A) Included in ~~the PA Mining Operations segment~~Total Natural Gas, NGLs and Oil Revenue are sales of ~~$70,159~~$117,460 to ~~Duke~~Direct Energy Business Marketing LLC, which comprises over 10% of ~~sales.~~revenue from contracts with external customers for the period.

(B) Includes midstream revenue of $17,990 and equity in earnings of unconsolidated affiliates of ~~$12,431 and $(6)~~$1,377 for ~~Total E&P~~Shale and Other, respectively.

(C) Includes investments in unconsolidated equity affiliates of ~~$187,382 and $2,772 for Total E&P and Other, respectively.~~$14,978.

Industry segment results for the three months ended ~~September~~June 30, ~~2016~~:2021 are:


	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	332,659	$	36,505	$	285	$	369,449	(D)

Purchased Gas Revenue	—		—		16,706		16,706


Loss on Commodity Derivative Instruments	(9,394)		(962)		(528,503)		(538,859)
Other Revenue and Operating Income	18,679		—		6,815		25,494		(E)
Total Revenue and Other Operating Income (Loss)	$	341,944	$	35,543	$	(504,697)	$	(127,210)
Total Operating Expense	$	191,996	$	28,204	$	60,511	$	280,711
Earnings (Loss) Before Income Tax	$	149,948	$	7,339	$	(603,463)	$	(446,176)
Segment Assets	$	6,095,486	$	1,069,470	$	907,154	$	8,072,110	(F)
Depreciation, Depletion and Amortization	$	104,380	$	14,264	$	3,963	$	122,607
Capital Expenditures	$	127,230	$	1,502	$	226	$	128,958

Marcellus
Shale

Utica
Shale
Coalbed Methane
Other
Gas

Total
E&P
PA Mining Operations Other
Adjustments and
Eliminations
Consolidated
Sales—Outside $ 107,676
$ 40,312
$ 46,917
$ 11,008
$ 205,913
$ 267,685
$ —
$ —
$ 473,598

Gain on Commodity Derivative Instruments 23,548
4,646
8,197
161,801
198,192
—
—
—
198,192

Other Outside Sales —
—
—
—
—
—
4,714
—
4,714

Sales—Purchased Gas —
—
—
12,086
12,086
—
—
—
12,086

Freight—Outside —
—
—
—
—
9,392
—
—
9,392

Intersegment Transfers —
—
—
—
—
—
—
—
—

Total Sales and Freight $ 131,224
$ 44,958
$ 55,114
$ 184,895
$ 416,191
$ 277,077
$ 4,714
$ —
$ 697,982

Earnings (Loss) From Continuing Operations Before Income Tax $ 10,465
$ 4,342
$ 6,989
$ 139,279
$ 161,075
$ 34,741
$ (80,390 ) $ —
$ 115,426
(D)
Segment Assets $ 6,537,210
$ 2,007,767
$ 1,018,406
$ 2,111
$ 9,565,494
(E)
Depreciation, Depletion and Amortization $ 101,257
$ 42,370
$ 8,085
$ —
$ 151,712

Capital Expenditures $ 48,746
$ 12,292
$ 3,094
$ —
$ 64,132

(D)    Included in Total Natural Gas, NGLs and Oil Revenue are sales of $60,162 to Citadel Energy Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.

(E) Includes midstream revenue of $18,679 and equity in earnings of unconsolidated affiliates of $1,553 for Shale and Other, respectively.


~~(D)~~	~~Includes equity in earnings of unconsolidated affiliates of $15,219 and $136 for Total E&P and Other, respectively.~~

~~(E)~~(F) Includes investments in unconsolidated equity affiliates of ~~$253,637 and $3,786 for Total E&P and Other, respectively.~~$16,726.

Industry segment results for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2022 are:


	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	1,604,080	$	142,955	$	995	$	1,748,030	(A)
Purchased Gas Revenue	—		—		92,393		92,393
Loss on Commodity Derivative Instruments	(738,484)		(62,501)		(1,578,051)		(2,379,036)
Other Revenue and Operating Income	35,647		—		10,286		45,933		(B)
Total Revenue and Other Operating Income (Loss)	$	901,243	$	80,454	$	(1,474,377)	$	(492,680)
Total Operating Expense	$	387,313	$	62,050	$	203,630	$	652,993
Earnings (Loss) Before Income Tax	$	513,930	$	18,404	$	(1,733,916)	$	(1,201,582)
Segment Assets	$	6,417,552	$	969,944	$	1,308,394	$	8,695,890	(C)
Depreciation, Depletion and Amortization	$	197,354	$	26,276	$	11,173	$	234,803
Capital Expenditures	$	250,079	$	5,921	$	2,984	$	258,984

Marcellus
Shale
Utica Shale Coalbed Methane
Other
Gas

Total
E&P
PA Mining Operations Other
Adjustments and
Eliminations
Consolidated
Sales—Outside $ 477,392
$ 136,493
$ 157,344
$ 41,282
$ 812,511
$ 899,400
$ —
$ —
$ 1,711,911

(Loss) Gain on Commodity Derivative Instruments (42,911 ) (2,234 ) (12,894 ) 138,547
80,508
—
—
—
80,508

Other Outside Sales —
—
—
—
—
—
45,986
—
45,986

Sales—Purchased Gas —
—
—
32,678
32,678
—
—
—
32,678

Freight—Outside —
—
—
—
—
51,847
—
—
51,847

Intersegment Transfers —
—
—
—
—
—
12,280
(12,280 ) —

Total Sales and Freight $ 434,481
$ 134,259
$ 144,450
$ 212,507
$ 925,697
$ 951,247
$ 58,266
$ (12,280 ) $ 1,922,930

Earnings (Loss) From Continuing Operations Before Income Tax $ 58,504
$ 34,211
$ 9,026
$ 52,396
$ 154,137
$ 131,670
$ (118,894 ) $ (12,280 ) $ 154,633
(F)
Segment Assets $ 5,941,092
$ 1,912,656
$ 1,113,540
$ 12,280
$ 8,979,568
(G)
Depreciation, Depletion and Amortization $ 288,220
$ 125,341
$ 1,047
$ —
$ 414,608

Capital Expenditures $ 390,619
$ 49,045
$ 10,956
$ —
$ 450,620

(A) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $213,299 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.

~~(F)~~(B) Includes midstream revenue of $35,647 and equity in earnings of unconsolidated affiliates of ~~$34,626 and$184~~$2,177 for ~~Total E&P~~Shale and Other, respectively.

~~(G)~~(C) Includes investments in unconsolidated equity affiliates of ~~$187,382 and $2,772 for Total E&P and Other, respectively.~~$14,978.

Industry segment results for the ~~nine~~six months ended ~~September~~June 30, ~~2016:~~2021 are:


	Shale		Coalbed Methane		Other		Consolidated
Natural Gas, NGLs and Oil Revenue	$	674,828	$	75,409	$	437	$	750,674	(D)

Purchased Gas Revenue	—		—		50,190		50,190


Loss on Commodity Derivative Instruments	(7,212)		(740)		(497,493)		(505,445)
Other Revenue and Operating Income	37,745		—		12,700		50,445		(E)
Total Revenue and Other Operating Income (Loss)	$	705,361	$	74,669	$	(434,166)	$	345,864
Total Operating Expense	$	380,707	$	56,759	$	143,050	$	580,516
Earnings (Loss) Before Income Tax	$	324,654	$	17,910	$	(653,335)	$	(310,771)
Segment Assets	$	6,095,486	$	1,069,470	$	907,154	$	8,072,110	(F)
Depreciation, Depletion and Amortization	$	213,886	$	29,747	$	7,918	$	251,551
Capital Expenditures	$	248,348	$	3,644	$	395	$	252,387

Marcellus
Shale

Utica
Shale
Coalbed Methane
Other
Gas

Total
E&P
PA Mining Operations Other
Adjustments and
Eliminations
Consolidated
Sales—Outside $ 287,465
$ 115,610
$ 122,410
$ 29,616
$ 555,101
$ 744,411
$ —
$ —
$ 1,299,512

Gain (Loss) on Commodity Derivative Instruments 120,982
24,674
43,796
(135,580 ) 53,872
—
—
—
53,872

Other Outside Sales —
—
—
—
—
—
20,687
—
20,687

Sales—Purchased Gas —
—
—
28,633
28,633
—
—
—
28,633

Freight—Outside —
—
—
—
—
33,949
—
—
33,949

Intersegment Transfers —
—
424
—
424
—
—
(424 ) —

Total Sales and Freight $ 408,447
$ 140,284
$ 166,630
$ (77,331 ) $ 638,030
$ 778,360
$ 20,687
$ (424 ) $ 1,436,653

Earnings (Loss) From Continuing Operations Before Income Tax $ 43,251
$ 17,521
$ 24,813
$ (241,971 ) $ (156,386 ) $ 80,588
$ (210,346 ) $ (424 ) $ (286,568 ) (H)
Segment Assets $ 6,537,210
$ 2,007,767
$ 1,018,406
$ 2,111
$ 9,565,494
(I)
Depreciation, Depletion and Amortization $ 312,122
$ 125,334
$ 4,463
$ —
$ 441,919

Capital Expenditures $ 134,967
$ 38,295
$ 6,127
$ —
$ 179,389

(D)    Included in Total Natural Gas, NGLs and Oil Revenue are sales of $100,465 to Citadel Energy marketing LLC and $80,189 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.

(E) Includes midstream revenue of $37,745 and equity in earnings of unconsolidated affiliates of $2,504 for Shale and Other, respectively.


~~(H)~~	~~Includes equity in earnings of unconsolidated affiliates of $39,980 and $1,259 for Total E&P and Other, respectively.~~

~~(I)~~(F) Includes investments in unconsolidated equity affiliates of ~~$253,637 and $3,786 for Total E&P and Other, respectively.~~$16,726.

Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Operating Income (Loss) ~~From Continuing Operations Before Income Tax:~~


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2022		2021		2022		2021
Total Segment Revenue from Contracts with External Customers	$	1,067,948	$	404,834	$	1,876,070	$	838,609
Loss on Commodity Derivative Instruments	(652,643)		(538,859)		(2,379,036)		(505,445)
Other Operating Income	5,113		6,815		10,286		12,700
Total Consolidated Revenue and Other Operating Income (Loss)	$	420,418	$	(127,210)	$	(492,680)	$	345,864

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Segment Income (Loss) Before Income Taxes for reportable business segments $ 41,237
$ 195,816
$ 285,807
$ (75,798 )
Segment Income (Loss) Before Income Taxes for all other business segments 9,385
(33,073 ) 11,706
(65,737 )
Interest expense (41,502 ) (47,317 ) (129,367 ) (144,609 )
Eliminations (5,994 ) —
(12,280 ) (424 )
Loss on debt extinguishment (2,019 ) —
(1,233 ) —
Income (Loss) From Continuing Operations Before Income Tax $ 1,107
$ 115,426
$ 154,633
$ (286,568 )

~~Total Assets:~~

September 30,
2017 2016
Segment assets for total reportable business segments $ 7,853,748
$ 8,544,977
Segment assets for all other business segments 738,352
794,917
Items excluded from segment assets:
Cash and other investments 282,036
73,809
Recoverable income taxes 105,432
—
Deferred tax assets —
149,680
Discontinued Operations —
2,111
Total Consolidated Assets $ 8,979,568
$ 9,565,494

NOTE ~~16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:~~

The payment obligations under the $1,734,779, 5.875% per annum senior notes due April 15, 2022, and the $495,023, 8.000% per annum senior notes due April 1, 2023 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally, guaranteed by certain subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, CNX Coal Resources LP (CNXC), a non-guarantor subsidiary, and the remaining guarantor and non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.14—STOCK REPURCHASE:

On ~~September 30, 2016, CNXC acquired~~January 26, 2021, the Company’s Board of Directors approved an ~~additional 5% undivided interest~~increase in the Pennsylvania Mining Complex from CONSOL Energy, increasing their total undivided interest to 25%. To account for the acquisition, CNXC recast its consolidated financial statements to retrospectively reflect the additional 5% interest as if the business was owned for all periods presented. This resulted in corresponding retrospective adjustments between the Other Subsidiary Guarantors and the CNXC Non-Guarantor columns below. See Note 17 - Related Party Transactions for additional information.

~~Income Statement for the Three Months Ended September 30, 2017 (unaudited):~~

Parent
Issuer

CNX Gas
Guarantor

Other
Subsidiary
Guarantors
CNXC Non-Guarantor Elimination Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales $ —
$ 234,443
$ —
$ —
$ —
$ 234,443
Gain on Commodity Derivative Instruments

—
19,183
—
—
—
19,183
Coal Sales —
—
209,434
69,811
—
279,245
Other Outside Sales —
—
16,959
—
—
16,959
Purchased Gas Sales —
13,384
—
—
—
13,384
Freight-Outside Coal —
—
16,352
5,451
—
21,803
Miscellaneous Other Income 8,476
23,656
14,384
2,996
(8,476 ) 41,036
Gain on Sale of Assets —
26,648
18,576
6
—
45,230
Total Revenue and Other Income 8,476
317,314
275,705
78,264
(8,476 ) 671,283
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense —
21,754
—
—
—
21,754
Transportation, Gathering and Compression —
98,768
—
—
—
98,768
Production, Ad Valorem, and Other Fees —
5,919
—
—
—
5,919
Depreciation, Depletion and Amortization —
101,585
—
—
—
101,585
Exploration and Production Related Other Costs —
4,479
—
—
—
4,479
Purchased Gas Costs —
13,142
—
—
—
13,142
Other Corporate Expenses —
26,844
—
—
—
26,844
Selling, General, and Administrative Costs

—
20,328
—
—
—
20,328
Total Exploration and Production Costs —
292,819
—
—
—
292,819
PA Mining Operations Costs
Operating and Other Costs —
—
155,612
52,160
—
207,772
Depreciation, Depletion and Amortization —
—
31,286
10,352
—
41,638
Freight Expense —
—
16,352
5,451
—
21,803
Selling, General, and Administrative Costs —
—
14,381
4,283
—
18,664
Total PA Mining Operations Costs —
—
217,631
72,246
—
289,877
Other Costs
Miscellaneous Operating Expense 17,413
—
18,105
—
—
35,518
Selling, General, and Administrative Costs
—
—
2,896
—
—
2,896
Depreciation, Depletion and Amortization —
—
5,545
—
—
5,545
Loss on Debt Extinguishment 2,019
—
—
—
—
2,019
Interest Expense 36,733
575
1,790
2,404
—
41,502
Total Other Costs 56,165
575
28,336
2,404
—
87,480
Total Costs And Expenses 56,165
293,394
245,967
74,650
—
670,176
(Loss) Earnings from Continuing Operations Before Income Tax (47,689 ) 23,920
29,738
3,614
(8,476 ) 1,107
Income Tax (Benefit) Expense (21,248 ) 9,506
38,500
—
—
26,758
(Loss) Income From Continuing Operations (26,441 ) 14,414
(8,762 ) 3,614
(8,476 ) (25,651 )
Less: Net Income Attributable to Noncontrolling Interest —
—
—
—
790
790
Net (Loss) Income Attributable to CONSOL Energy Shareholders $ (26,441 ) $ 14,414
$ (8,762 ) $ 3,614
$ (9,266 ) $ (26,441 )

~~Balance Sheet at September 30, 2017 (unaudited):~~

Parent
Issuer

CNX Gas
Guarantor

Other
Subsidiary
Guarantors
CNXC
Non-Guarantor Other Subsidiary
Non-Guarantors Elimination Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents $ 281,189
$ 84
$ —
$ 3,574
$ 861
$ —
$ 285,708
Accounts and Notes Receivable:
Trade —
92,763
77,207
23,808
—
—
193,778
Other Receivables 19,422
43,985
13,885
454
—
—
77,746
Inventories 407
10,771
40,056
11,948
—
—
63,182
Recoverable Income Taxes 170,578
(65,146 ) —
—
—
—
105,432
Prepaid Expenses 8,150
48,601
17,621
5,065
�� —
—
79,437
Total Current Assets 479,746
131,058
148,769
44,849
861
—
805,283
Property, Plant and Equipment:
Property, Plant and Equipment 99,839
8,818,525
3,929,854
890,170
—
—
13,738,388
Less-Accumulated Depreciation, Depletion and Amortization 86,137
3,317,180
2,063,392
472,717
—
—
5,939,426
Total Property, Plant and Equipment-Net 13,702
5,501,345
1,866,462
417,453
—
—
7,798,962
Other Assets:
Investment in Affiliates 7,687,545
187,382
53,016
—
—
(7,737,789 ) 190,154
Other 12,062
56,161
97,699
19,247
—
—
185,169
Total Other Assets 7,699,607
243,543
150,715
19,247
—
(7,737,789 ) 375,323
Total Assets $ 8,193,055
$ 5,875,946
$ 2,165,946
$ 481,549
$ 861
$ (7,737,789 ) $ 8,979,568
Liabilities and Equity:
Current Liabilities:
Accounts Payable $ 26,254
$ 183,329
$ 61,990
$ 19,872
$ —
$ 11,751
$ 303,196
Accounts Payable (Recoverable)-Related Parties 1,839,980
705,762
(2,504,854 ) 1,906
(31,043 ) (11,751 ) —
Current Portion of Long-Term Debt 661
6,769
3,456
85
—
—
10,971
Other Accrued Liabilities 101,024
177,155
220,727
41,766
—
—
540,672
Current Liabilities of Discontinued Operations —
—
—
—
5,353
—
5,353
Total Current Liabilities 1,967,919
1,073,015
(2,218,681 ) 63,629
(25,690 ) —
860,192
Long-Term Debt: 2,211,206
22,068
113,432
185,606
—
—
2,532,312
Deferred Credits and Other Liabilities:
Deferred Income Taxes (33,219 ) 77,939
—
—
—
—
44,720
Postretirement Benefits Other Than Pensions —
—
649,565
—
—
—
649,565
Pneumoconiosis Benefits —
—
103,946
2,891
—
—
106,837
Mine Closing —
—
189,398
9,366
—
—
198,764
Gas Well Closing —
194,952
28,365
129
—
—
223,446
Workers’ Compensation —
—
62,902
3,263
—
—
66,165
Salary Retirement 100,510
—
—
—
—
—
100,510
Other 14,808
97,138
13,449
427
—
—
125,822
Total Deferred Credits and Other Liabilities 82,099
370,029
1,047,625
16,076
—
—
1,515,829
Total CONSOL Energy Inc. Stockholders’ Equity 3,931,831
4,410,834
3,223,570
216,238
26,551
(7,877,193 ) 3,931,831
Noncontrolling Interest —
—
—
—
—
139,404
139,404
Total Liabilities and Equity $ 8,193,055
$ 5,875,946
$ 2,165,946
$ 481,549
$ 861
$ (7,737,789 ) $ 8,979,568

~~Income Statement for the Three Months Ended~~ ~~September 30, 2016~~ ~~(unaudited):~~

Parent
Issuer

CNX Gas
Guarantor

Other
Subsidiary
Guarantors
CNXC
Non-Guarantor
Other
Subsidiary
Non-Guarantors

Elimination Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales $ —
$ 205,913
$ —
$ —
$ —
$ —
$ 205,913
Gain on Commodity Derivative Instruments
—
198,192
—
—
—
—
198,192
Coal Sales —
—
200,763
66,922
—
—
267,685
Other Outside Sales —
—
4,714
—
—
—
4,714
Purchased Gas Sales —
12,086
—
—
—
—
12,086
Freight-Outside Coal —
—
6,985
2,407
—
—
9,392
Miscellaneous Other Income 56,836
18,175
13,737
483
—
(56,838 ) 32,393
Gain (Loss) on Sale of Assets —
15,342
(141 ) 2
—
—
15,203
Total Revenue and Other Income 56,836
449,708
226,058
69,814
—
(56,838 ) 745,578
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense —
22,602
—
—
—
—
22,602
Transportation, Gathering and Compression —
94,796
—
—
—
—
94,796
Production, Ad Valorem, and Other Fees —
9,027
—
—
—
—
9,027
Depreciation, Depletion and Amortization —
101,257
—
—
—
—
101,257
Exploration and Production Related Other Costs —
384
—
—
—
—
384
Purchased Gas Costs —
11,940
—
—
—
—
11,940
Other Corporate Expenses —
21,760
—
—
—
—
21,760
Selling, General, and Administrative Costs —
26,198
—
—
—
—
26,198
Total Exploration and Production Costs —
287,964
—
—
—
—
287,964
PA Mining Operations Costs
Operating and Other Costs —
—
137,186
45,531
—
—
182,717
Depreciation, Depletion and Amortization —
—
31,778
10,592
—
—
42,370
Freight Expense —
—
6,985
2,407
—
—
9,392
Selling, General, and Administrative Costs —
—
4,993
2,660
—
—
7,653
Total PA Mining Operations Costs —
—
180,942
61,190
—
—
242,132
Other Costs
Miscellaneous Operating Expense 7,692
—
31,959
—
7
—
39,658
Selling, General, and Administrative Costs —
—
4,996
—
—
—
4,996
Depreciation, Depletion and Amortization 150
—
7,935
—
—
—
8,085
Interest Expense 42,812
669
1,613
2,223
—
—
47,317
Total Other Costs 50,654
669
46,503
2,223
7
—
100,056
Total Costs And Expenses 50,654
288,633
227,445
63,413
7
—
630,152
Earnings (Loss) From Continuing Operations Before Income Tax 6,182
161,075
(1,387 ) 6,401
(7 ) (56,838 ) 115,426
Income Tax (Benefit) Expense (19,163 ) 64,241
7,783
—
(3 ) —
52,858
Income (Loss) From Continuing Operations 25,345
96,834
(9,170 ) 6,401
(4 ) (56,838 ) 62,568
Loss From Discontinued Operations, net —
—
—
—
(34,975 ) —
(34,975 )
Net Income (Loss) 25,345
96,834
(9,170 ) 6,401
(34,979 ) (56,838 ) 27,593
Less: Net Income Attributable to Noncontrolling Interest —
—
—
—
—
2,248
2,248
Net Income (Loss) Attributable to CONSOL Energy Shareholders $ 25,345
$ 96,834
$ (9,170 ) $ 6,401
$ (34,979 ) $ (59,086 ) $ 25,345

~~Balance Sheet at December 31, 2016:~~

Parent
Issuer

CNX Gas
Guarantor

Other
Subsidiary
Guarantors
CNXC Non-Guarantor
Other
Subsidiary
Non-
Guarantors
Elimination Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents $ 49,722
$ 83
$ —
$ 9,785
$ 885
$ —
$ 60,475
Accounts and Notes Receivable:
Trade —
124,509
72,295
23,418
—
—
220,222
Other Receivables 20,097
34,773
14,516
515
—
—
69,901
Inventories —
15,301
38,669
11,491
—
—
65,461
Recoverable Income Taxes 175,877
(59,026 ) —
—
—
—
116,851
Prepaid Expenses 12,828
60,500
16,306
3,512
—
—
93,146
Current Assets of Discontinued Operations —
—
—
—
83
—
83
Total Current Assets 258,524
176,140
141,786
48,721
968
—
626,139
Property, Plant and Equipment:
Property, Plant and Equipment 114,611
8,851,226
3,928,861
876,690
—
—
13,771,388
Less-Accumulated Depreciation, Depletion and Amortization 84,788
3,106,296
1,997,687
442,178
—
—
5,630,949
Total Property, Plant and Equipment-Net 29,823
5,744,930
1,931,174
434,512
—
—
8,140,439
Other Assets:
Deferred Income Taxes 25,904
(21,614 ) —
—
—
—
4,290
Investment in Affiliates 7,974,260
188,376
27,269
—
—
(7,998,941 ) 190,964
Other 19,960
67,096
114,030
21,063
—
—
222,149
Total Other Assets 8,020,124
233,858
141,299
21,063
—
(7,998,941 ) 417,403
Total Assets $ 8,308,471
$ 6,154,928
$ 2,214,259
$ 504,296
$ 968
$ (7,998,941 ) $ 9,183,981
Liabilities and Equity:
Current Liabilities:
Accounts Payable $ 48,666
$ 127,309
$ 36,039
$ 18,797
$ —
$ 10,805
$ 241,616
Accounts Payable (Recoverable)-Related Parties 1,832,908
1,034,138
(2,648,416 ) 1,666
(209,491 ) (10,805 ) —
Current Portion of Long-Term Debt 1,533
6,369
4,010
88
—
—
12,000
Other Accrued Liabilities 75,039
337,374
223,705
44,230
—
—
680,348
Current Liabilities of Discontinued Operations —
—
—
—
6,050
—
6,050
Total Current Liabilities 1,958,146
1,505,190
(2,384,662 ) 64,781
(203,441 ) —
940,014
Long-Term Debt: 2,421,511
26,884
115,685
197,989
—
—
2,762,069
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions —
—
659,474
—
—
—
659,474
Pneumoconiosis Benefits —
—
106,016
2,057
—
—
108,073
Mine Closing —
—
209,384
9,247
—
—
218,631
Gas Well Closing —
195,704
27,549
99
—
—
223,352
Workers’ Compensation —
—
64,187
3,090
—
—
67,277
Salary Retirement 112,543
—
—
—
—
—
112,543
Other 17,876
117,658
15,663
463
—
—
151,660
Total Deferred Credits and Other Liabilities 130,419
313,362
1,082,273
14,956
—
—
1,541,010
Total CONSOL Energy Inc. Stockholders’ Equity 3,798,395
4,309,492
3,400,963
226,570
204,409
(8,141,434 ) 3,798,395
Noncontrolling Interest —
—
—
—
—
142,493
142,493
Total Liabilities and Equity $ 8,308,471
$ 6,154,928
$ 2,214,259
$ 504,296
$ 968
$ (7,998,941 ) $ 9,183,981

~~Income Statement for the Nine Months Ended September 30, 2017 (unaudited):~~

Parent
Issuer CNX Gas
Guarantor Other
Subsidiary
Guarantors CNXC
Non-Guarantor Elimination Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales $ —
$ 812,511
$ —
$ —
$ —
$ 812,511
Gain on Commodity Derivative Instruments —
80,508
—
—
—
80,508
Coal Sales —
—
674,550
224,850
—
899,400
Other Outside Sales —
—
45,986
—
—
45,986
Purchased Gas Sales —
32,678
—
—
—
32,678
Freight-Outside Coal —
—
38,885
12,962
—
51,847
Miscellaneous Other Income 201,808
56,267
54,604
4,798
(201,808 ) 115,669
Gain on Sale of Assets —
164,631
31,306
1,406
—
197,343
Total Revenue and Other Income 201,808
1,146,595
845,331
244,016
(201,808 ) 2,235,942
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense —
64,459
—
—
—
64,459
Transportation, Gathering and Compression —
279,699
—
—
—
279,699
Production, Ad Valorem, and Other Fees —
19,854
—
—
—
19,854
Depreciation, Depletion and Amortization —
288,220
—
—
—
288,220
Exploration and Production Related Other Costs —
33,980
—
—
—
33,980
Purchased Gas Costs —
32,231
—
—
—
32,231
Other Corporate Expenses —
68,172
—
—
—
68,172
Impairment of Exploration and Production Properties —
137,865
—
—
—
137,865
Selling, General, and Administrative Costs —
62,490
—
—
—
62,490
Total Exploration and Production Costs —
986,970
—
—
—
986,970
PA Mining Operations Costs
Operating and Other Costs —
—
456,403
152,275
—
608,678
Depreciation, Depletion and Amortization —
—
94,191
31,150
—
125,341
Freight Expense —
—
38,885
12,962
—
51,847
Selling, General, and Administrative Costs —
—
39,419
11,218
—
50,637
Total PA Mining Operations Costs —
—
628,898
207,605
—
836,503
Other Costs
Miscellaneous Operating Expense 40,961
—
76,046
—
—
117,007
Selling, General, and Administrative Costs —
—
9,182
—
—
9,182
Depreciation, Depletion and Amortization —
—
1,047
—
—
1,047
Loss on Debt Extinguishment 1,233
—
—
—
—
1,233
Interest Expense 114,963
1,794
5,353
7,257
—
129,367
Total Other Costs 157,157
1,794
91,628
7,257
—
257,836
Total Costs And Expenses 157,157
988,764
720,526
214,862
—
2,081,309
Earnings (Loss) From Continuing Operations Before Income Tax 44,651
157,831
124,805
29,154
(201,808 ) 154,633
Income Tax (Benefit) Expense (59,453 ) 62,722
36,693
—
—
39,962
Income (Loss) from Continuing Operations 104,104
95,109
88,112
29,154
(201,808 ) 114,671
Less: Net Income Attributable to Noncontrolling Interest —
—
—
—
10,567
10,567
Net Income (Loss) Attributable to CONSOL Energy Shareholders $ 104,104
$ 95,109
$ 88,112
$ 29,154
$ (212,375 ) $ 104,104

~~Income Statement for the Nine Months Ended September 30, 2016 (unaudited):~~

Parent
Issuer CNX Gas
Guarantor Other
Subsidiary
Guarantors CNXC
Non-Guarantor Other
Subsidiary
Non-Guarantors Elimination Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales $ —
$ 555,526
$ —
$ —
$ —
$ (425 ) $ 555,101
Gain on Commodity Derivative Instruments —
53,872
—
—
—
—
53,872
Coal Sales —
—
558,308
186,103
—
—
744,411
Other Outside Sales —
—
20,687
—
—
—
20,687
Purchased Gas Sales —
28,633
—
—
—
—
28,633
Freight-Outside Coal —
—
25,476
8,473
—
—
33,949
Miscellaneous Other Income (441,368 ) 60,592
51,304
2,264
—
441,367
114,159
Gain (Loss) on Sale of Assets —
10,446
3,105
(10 ) —
—
13,541
Total Revenue and Other Income (441,368 ) 709,069
658,880
196,830
—
440,942
1,564,353
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense —
73,996
—
—
—
—
73,996
Transportation, Gathering and Compression —
279,753
—
—
—
—
279,753
Production, Ad Valorem, and Other Fees —
23,732
—
—
—
—
23,732
Depreciation, Depletion and Amortization —
312,122
—
—
—
—
312,122
Exploration and Production Related Other Costs —
5,036
—
—
—
—
5,036
Purchased Gas Costs —
28,692
—
—
—
—
28,692
Other Corporate Expenses —
65,980
—
—
—
—
65,980
Selling, General, and Administrative Costs —
74,067
—
—
—
—
74,067
Total Exploration and Production Costs —
863,378
—
—
—
—
863,378
PA Mining Operations Costs
Operating and Other Costs —
—
391,211
130,066
—
—
521,277
Depreciation, Depletion and Amortization —
—
94,002
31,332
—
—
125,334
Freight Expense —
—
25,476
8,473
—
—
33,949
Selling, General, and Administrative Costs —
—
13,649
6,558
—
—
20,207
Total PA Mining Operations Costs —
—
524,338
176,429
—
—
700,767
Other Costs
Miscellaneous Operating Expense 30,077
—
96,466
—
37
—
126,580
Selling, General, and Administrative Costs —
—
11,124
—
—
—
11,124
Depreciation, Depletion and Amortization 452
—
4,011
—
—
—
4,463
Interest Expense 131,431
2,077
4,824
6,277
—
—
144,609
Total Other Costs 161,960
2,077
116,425
6,277
37
—
286,776
Total Costs And Expenses 161,960
865,455
640,763
182,706
37
—
1,850,921
(Loss) Earnings From Continuing Operations Before Income Tax (603,328 ) (156,386 ) 18,117
14,124
(37 ) 440,942
(286,568 )
Income Tax (Benefit) Expense (61,270 ) (62,148 ) 51,634
—
(14 ) —
(71,798 )
(Loss) Income From Continuing Operations (542,058 ) (94,238 ) (33,517 ) 14,124
(23 ) 440,942
(214,770 )
Loss From Discontinued Operations, net —
—
—
—
(322,747 ) —
(322,747 )
Net (Loss) Income (542,058 ) (94,238 ) (33,517 ) 14,124
(322,770 ) 440,942
(537,517 )
Less: Net Income Attributable to Noncontrolling Interest —
—
—
—
—
4,541
4,541
Net (Loss) Income Attributable to CONSOL Energy Shareholders $ (542,058 ) $ (94,238 ) $ (33,517 ) $ 14,124
$ (322,770 ) $ 436,401
$ (542,058 )

~~Cash Flow for the Nine Months Ended September 30, 2017 (unaudited):~~

~~Cash Flow for the~~ ~~Nine Months EndedSeptember 30, 2016~~ ~~(unaudited):~~

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors CNXC Non-Guarantor
Other Subsidiary Non-
Guarantors
Elimination Consolidated
Net Cash Provided by (Used in) Continuing Operating Activities

$ 613,513
$ 106,017
$ 32,398
$ 47,324
$ (380,674 ) $ (44,698 ) $ 373,880
Net Cash Provided by Discontinued Operating Activities —
—
—
—
14,427
—
14,427
Net Cash Provided by (Used in) Operating Activities $ 613,513
$ 106,017
$ 32,398
$ 47,324
$ (366,247 ) $ (44,698 ) $ 388,307
Cash Flows from Investing Activities:
Capital Expenditures $ (2,450 ) $ (134,967 ) $ (32,403 ) $ (9,569 ) $ ��
$ —
$ (179,389 )
CNXC Acquisition of 5% Pennsylvania Mining Complex

—
—
—
(21,500 ) —
21,500
—
Proceeds from Sales of Assets —
33,041
5,915
21
—
—
38,977
Net Distributions from (Investments in) Equity Affiliates —
518
(5,073 ) —
—
—
(4,555 )
Net Cash (Used in) Provided by Continuing Investing Activities (2,450 ) (101,408 ) (31,561 ) (31,048 ) —
21,500
(144,967 )
Net Cash Provided by Discontinued Investing Activities —
—
—
—
366,251
—
366,251
Net Cash (Used in) Provided by Investing Activities $ (2,450 ) $ (101,408 ) $ (31,561 ) $ (31,048 ) $ 366,251
$ 21,500
$ 221,284
Cash Flows from Financing Activities:
Payments on Short-Term Borrowings $ (598,000 ) $ —
$ —
$ —
$ —
$ —
$ (598,000 )
Payments on Miscellaneous Borrowings (1,220 ) (4,590 ) (355 ) (57 ) —
—
(6,222 )
Net Proceeds from Revolver - CNX Coal Resources LP —
—
—
23,000
—
—
23,000
Distributions to Noncontrolling Interest —
—
—
(30,486 ) —
14,245
(16,241 )
Pre-Merger Distributions to Parent —
—
—
(8,953 ) —
8,953
—
Dividends Paid (2,294 ) —
—
—
—
—
(2,294 )
Issuance of Common Stock 4
—
—
—
—
—
4
Treasury Stock Activity (1,669 ) —
—
—
—
—
(1,669 )
Debt Repurchase and Financing Fees —
—
(482 ) —
—
—
(482 )
Net Cash (Used in) Provided by Continuing Financing Activities (603,179 ) (4,590 ) (837 ) (16,496 ) —
23,198
(601,904 )
Net Cash Used in Discontinued Financing Activities —
—
—
—
(14 ) —
(14 )
Net Cash (Used in) Provided by Financing Activities $ (603,179 ) $ (4,590 ) $ (837 ) $ (16,496 ) $ (14 ) $ 23,198
$ (601,918 )

~~Statement of Comprehensive Income for the Three Months Ended September 30, 2017 (unaudited):~~

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors CNXC Non-
Guarantor Elimination Consolidated
Net (Loss) Income $ (26,441 ) $ 14,414
$ (8,762 ) $ 3,614
$ (8,476 ) $ (25,651 )
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments 3,464
—
3,503
(39 ) (3,464 ) 3,464
Other Comprehensive Income (Loss): 3,464
—
3,503
(39 ) (3,464 ) 3,464
Comprehensive (Loss) Income (22,977 ) 14,414
(5,259 ) 3,575
(11,940 ) (22,187 )
Less: Comprehensive Income Attributable to Noncontrolling Interest —
—
—
—
779
779
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders $ (22,977 ) $ 14,414
$ (5,259 ) $ 3,575
$ (12,719 ) $ (22,966 )

~~Statement of Comprehensive Income for the Three Months Ended~~ ~~September 30, 2016~~ ~~(unaudited):~~

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors
CNXC Non-
Guarantor

Other Subsidiary Non-
Guarantors
Elimination Consolidated
Net Income (Loss) $ 25,345
$ 96,834
$ (9,170 ) $ 6,401
$ (34,979 ) $ (56,838 ) $ 27,593
Other Comprehensive (Loss) Income:
  Actuarially Determined Long-Term Liability Adjustments 1,305
—
1,327
(22 ) —
(1,305 ) 1,305
  Reclassification of Cash Flow Hedges from OCI to Earnings (12,458 ) (12,458 ) —
—
—
12,458
(12,458 )
Other Comprehensive (Loss) Income: (11,153 ) (12,458 ) 1,327
(22 ) —
11,153
(11,153 )
Comprehensive Income (Loss) 14,192
84,376
(7,843 ) 6,379
(34,979 ) (45,685 ) 16,440
  Less: Comprehensive Income Attributable to Noncontrolling Interest —
—
—
—
—
2,248
2,248
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders $ 14,192
$ 84,376
$ (7,843 ) $ 6,379
$ (34,979 ) $ (47,933 ) $ 14,192

~~Statement of Comprehensive Income for the Nine Months Ended September 30, 2017 (unaudited):~~

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors CNXC Non-
Guarantor Elimination Consolidated
Net Income (Loss) $ 104,104
$ 95,109
$ 88,112
$ 29,154
$ (201,808 ) $ 114,671
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments 10,430
—
10,548
(118 ) (10,430 ) 10,430
Other Comprehensive Income (Loss): 10,430
—
10,548
(118 ) (10,430 ) 10,430
Comprehensive Income (Loss) 114,534
95,109
98,660
29,036
(212,238 ) 125,101
Less: Comprehensive Income Attributable to Noncontrolling Interest —
—
—
—
10,533
10,533
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders $ 114,534
$ 95,109
$ 98,660
$ 29,036
$ (222,771 ) $ 114,568

~~Statement of Comprehensive Income for the~~ ~~Nine Months Ended~~ ~~September 30, 2016 (unaudited):~~

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors CNXC Non-
Guarantor
Other Subsidiary Non-
Guarantors
Elimination Consolidated
Net (Loss) Income $ (542,058 ) $ (94,238 ) $ (33,517 ) $ 14,124
$ (322,770 ) $ 440,942
$ (537,517 )
Other Comprehensive (Loss) Income:
  Actuarially Determined Long-Term Liability Adjustments 6,866
—
6,936
(70 ) —
(6,866 ) 6,866
  Reclassification of Cash Flow Hedges from OCI to Earnings (33,475 ) (33,475 ) —
—
—
33,475
(33,475 )
Other Comprehensive (Loss) Income: (26,609 ) (33,475 ) 6,936
(70 ) —
26,609
(26,609 )
Comprehensive (Loss) Income (568,667 ) (127,713 ) (26,581 ) 14,054
(322,770 ) 467,551
(564,126 )
  Less: Comprehensive Income Attributable to Noncontrolling Interest —
—
—
—
—
4,541
4,541
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders $ (568,667 ) $ (127,713 ) $ (26,581 ) $ 14,054
$ (322,770 ) $ 463,010
$ (568,667 )

~~NOTE 17—RELATED PARTY TRANSACTIONS:~~

~~CONE Gathering LLC and CONE Midstream Partners LP~~

In September 2011, CNX Gas Company, a wholly owned subsidiary of CONSOL Energy, and Noble Energy, Inc. (Noble Energy), an unrelated third-party, formed CONE Gathering LLC (CONE) to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CONSOL Energy accounts for CNX Gas Company's 50% ownership interest in CONE under the equity method of accounting.

In May 2014, CONSOL Energy and Noble Energy (collectively, the "Sponsors") formed CONE Midstream Partners LP (the Partnership), a master limited partnership, to own, operate, develop and acquire natural gas gathering and other midstream energy assets to service each company's production in the Marcellus Shale in Pennsylvania and West Virginia. The Partnership's general partner is CONE Midstream GP LLC (the General Partner), a wholly owned subsidiary of CONE. CONSOL Energy accounts for CNX Gas Company's portionaggregate amount of the ~~earnings in the Partnership under the equity method of accounting.~~

~~In November 2016, the Partnership acquired from CONE an additional 25% ownership interest in CONE Midstream DevCo 1 LP, commonly referred~~previous $750,000 stock repurchase program plan to ~~as the "Anchor Systems." The transaction included a total purchase consideration of $248,000, comprised of $140,000 in cash~~$900,000, and issuance of approximately 5,200,000 common limited partnership units to the Sponsors. Following the acquisition, CONE continues to have a 2% general partner interest in the Partnership, while each Sponsor's limited partner interest increased to 33.5%. At September 30, 2017, CNX Gas Company continues to own a 50% interest in the assets of CONE that were not contributed to the Partnership. In June 2017, Noble Energy announced that it intends to divest its interest in CONE to a portfolio company of Quantum Energy Partners.

Inon October ~~2017,~~25, 2021, the Board of Directors approved an additional increase in the aggregate amount of the ~~General Partner confirmed~~stock repurchase program plan to $1,900,000. As of June 30, 2022 the amount available under the stock repurchase program is $793,696, and ~~approved that, upon~~is not subject to an expiration date. The repurchases may be effected 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 ~~payment~~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 ~~third-quarter distribution, the financial tests required for conversion~~program at any time. The Board of the Partnership’s subordinated units will be met. Accordingly, the subordination period with respect to the Partnership’s subordinated units will expire on November 15, 2017, and all of the 29,163,121 outstanding subordinated units will automatically convert into common units on a one-for-one basis on that day.

~~The following is a summary of the Company's Investment in Affiliates balances included within the Consolidated Balance Sheets associated with CONE and the Partnership, respectively:~~

CONE The Partnership Total
Balance at December 31, 2016 $ 151,075
$ 18,133
$ 169,208
     Equity in Earnings 4,500
29,469
33,969
     Distributions (17,254 ) (18,366 ) (35,620 )
     Asset Transfer (2,527 ) 2,527
—
Balance at September 30, 2017 $ 135,794
$ 31,763
$ 167,557

~~The following transactions were included in Miscellaneous Other Income and Transportation, Gathering and Compression within the Consolidated Statements of Income:~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Miscellaneous Other Income:
     Equity in Earnings of Affiliates - CONE $ 2,350
$ 6,567
$ 4,500
$ 13,713
     Equity in Earnings of Affiliates - the Partnership $ 9,685
$ 7,586
$ 29,469
$ 22,996

Transportation, Gathering and Compression:
     Gathering Services - CONE $ 217
$ 144
$ 702
$ 513
     Gathering Services - the Partnership $ 32,639
$ 30,908
$ 98,388
$ 92,100

At September 30, 2017 and December 31, 2016, CONSOL Energy had a net payable of $9,993 and $5,815, respectively, due to both the Partnership and CONE primarily for accrued but unpaid gathering services.

~~CNX Coal Resources LP~~

~~CNX Coal Resources GP, a wholly owned subsidiary of CONSOL Energy, is the general partner of CNX Coal Resources LP (CNXC).~~

In September 2016, CNXC and its wholly owned subsidiary, CNX Thermal Holdings LLC (CNX Thermal), entered into a Contribution Agreement with CONSOL Energy, CONSOL Pennsylvania Coal Company LLC and Conrhein Coal Company (the Contributing Parties) under which CNX Thermal acquired an additional 5% undivided interest in and to the Pennsylvania Mine Complex, in exchange for (i) cash consideration in the amount of $21,500 and (ii) CNXC's issuance of 3,956,496 Class A Preferred Units representing limited partner interests in CNXC at an issue price of $17.01 per Class A preferred Unit (the "Class A Preferred Unit Issue Price"), or an aggregate $67,300 in equity consideration. The Class A Preferred Unit Issue Price was calculated as the volume-weighted average trading price of CNXC's common units (the "Common Units") over the trailing 15-day trading period ending on September 29, 2016 (or $14.79 per unit), plus a 15% premium.

In October 2017, CONSOL Energy elected to have the 3,956,496 Class A Preferred Units, representing the Company's limited partner interest in CNXC, converted into an equal number of Common Units under the terms of the Second Amended and Restated Agreement of Limited Partnership of CNXC.

In connection with CNXC's Contribution Agreement, in September 2016, the General Partner and CNXC entered into the First Amended and Restated Omnibus Agreement (the "Amended Omnibus Agreement") with CONSOL Energy and certain of its subsidiaries. Under the Amended Omnibus Agreement, CONSOL Energy indemnified CNXC for certain liabilities. The Amended Omnibus Agreement also amended CNXC's obligations to CONSOL Energy with respect to the payment of an annual administrative support fee and reimbursement for the provisions of certain management and operating services provided, in each case to reflect structural changes in how those services are provided to CNXC by CONSOL Energy.

~~Charges for services from CONSOL Energy include the following:~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Operating and Other Costs $ 850
$ 854
$ 2,589
$ 3,390
Selling, General and Administrative Expenses 834
856
2,288
3,090
Total Services from CONSOL Energy $ 1,684
$ 1,710

$ 4,877
$ 6,480

At September 30, 2017 and December 31, 2016, CNXC had a net payable to CONSOL Energy in the amount of $1,906 and $1,666, respectively. This payable includes reimbursements for business expenses, executive fees, stock-based compensation and other items under the omnibus agreement.

~~NOTE 18—RECENT ACCOUNTING PRONOUNCEMENTS:~~

In May 2017, the FASB issued Update 2017-09 - Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, which reduces diversity in practice and cost and complexity when applying the guidance in this Topic to a change to the terms or conditions of a share-based payment award. The amendments in this Update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in the Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and should be applied prospectively to an award modified on or after the adoption date. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on CONSOL Energy's financial statements.

In March 2017, the FASB issued Update 2017-07 - Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which improves the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendments in the Update require that an employer report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented separately from the service cost component and outside a subtotal of income from operations, if one is presented. Because CONSOL Energy does not present an income from operations subtotal, that requirement is not applicable. Additionally, the Company's service cost component is deemed immaterial, and therefore, the other components of net benefit cost will not be presented separately. For public entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of a fiscal year for which financial statements have not been issued. The adoption of this guidance is not expected to have an impact on CONSOL Energy's financial statements.

In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments relate to debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, and beneficial interests in securitization transactions. The Update also states that, in the absence of specific guidance for cash receipts and payments that have aspects of more than one class of cash flows, an entity should classify each separately identifiable source or use within the cash receipts and payments on the basis of their nature in financing, investing, or operating activities. In situations in which cash receipts or payments cannot be separated by source or use, the appropriate classification should depend on the activity that is likely to be the predominant source or use of cash flows for the item. The amendments in the Update will be applied using a retrospective transition method to each period presented and, for public entities, are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.

In May 2014, the FASB issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605 - Revenue Recognition and most industry-specific guidance throughout the Industry Topics of the Codification. The objective of the amendments in this Update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services and should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The following updates to Topic 606 were made during 2016:

In March 2016, the FASB issued Update 2016-08 - Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers.

In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing.

In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers: Narrow Scope Improvements and Practical Expedients, which seeks to address implementation issues in the areas of collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition.

In December 2016, the FASB issued Update 2016-20 - Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which includes amendments related to loan guarantee fees, contract costs, provisions

~~for losses on construction and production-type contracts, scope, disclosures, contract modification, contract asset versus receivable, refund liability and advertising costs.~~

The new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. Management continues to evaluate the impact that these standards will have on CONSOL Energy's financial statements, specifically as it relates to contracts that contain positive electric power price-related adjustments. CONSOL Energy anticipates using the modified retrospective approach to adoption as it relates to ASU 2014-09. CONSOL Energy is currently finalizing a detailed analysis at the individual contract level. The Company's implementation efforts are focused on accounting policy and disclosure updates and does not expect the implementation of the standard to be material.

In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position.The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. CONSOL Energy is currently reviewing all existing leases and agreements that are covered by this standard andDirectors 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 six months ended June 30, 2022, 12,912,070 shares were repurchased and retired at an average price of $17.09 per share for a total cost of $220,968. During the six months ended June 30, 2021, 3,095,241 shares were repurchased and retired at an average price of 13.12 per share for a total cost of $40,678.

NOTE 15—RECENT ACCOUNTING PRONOUNCEMENTS:

See Note 9 – Long-Term Debt for the impact of adoption of ASU 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity.

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 ~~financial~~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 ~~and related disclosures.~~

~~NOTE 19—SUBSEQUENT EVENTS:~~

On October 27, 2017, the Company filed Amendment No. 5 to the Registration Statement on Form 10 with the United States Securities and Exchange Commission (the “SEC”), which includes information about CONSOL Mining and the business and assets that it will own upon completion of the spin-off. The Registration Statement on Form 10 has not yet been declared effective by the SEC, and completion of the spin-off remains subject to various conditions.

On October 30, 2017, the Company’s Board of Directors gave final approval to the previously announced separation (the “Separation and Distribution”) into two publicly-traded companies, a coal company (CONSOL Mining Corporation) and a natural gas exploration and production (E&P) company. The Company’s Board of Directors also declared a pro rata distribution of all of the outstanding shares of CONSOL Mining Corporation common stock to the Company’s stockholders, which is expected to be made on November 28, 2017, (the “Record Date”). Each of the Company’s stockholders as of the Record Date will receive one share of CONSOL Mining Corporation common stock for every eight (8) shares of the Company’s common stock held at the close of business on the Record Date. Stockholders will receive cash in lieu of fractional shares of CONSOL Mining Corporation common stock. The Separation and Distribution is subject to the satisfaction or waiver of certain conditions. Following the Separation and Distribution, CONSOL Energy will not retain any equity interest in CONSOL Mining Corporation. In connection with the Separation and Distribution, CONSOL Energy Inc. will change its name to CNX Resources Corporation, and will retain its ticker symbol “CNX” on the New York Stock Exchange. CONSOL Mining Corporation will assume the name CONSOL Energy Inc., and will trade as an independent company on the New York Stock Exchange under the ticker symbol “CEIX”. CONSOL Energy stockholders will retain their shares of Company common stock, but as a result of various risk factors, including those that may not be in the ~~name change, these shares will represent shares~~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, 2021, which we filed with the SEC on February 10, 2022. CNX ~~Resources Corporation after the time of separation.~~does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.


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

General

~~As previously announced, CONSOL Energy Inc. (the “Company”) plans~~CNX continually monitors factors that could cause actual results of operations to ~~separate into two publicly-traded companies:~~differ from historical results or current expectations. Examples include the conflict between Russia and Ukraine that has had an impact on global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years. The results presented in this Form 10-Q are not necessarily indicative of future operating results.

COVID-19 Pandemic:

Although CNX did not incur significant disruptions to operations during the three or six months ended June 30, 2022 or 2021 as a ~~coal company~~direct result of the COVID-19 pandemic, CNX is unable to predict the full extent of the future impact that the COVID-19 pandemic could have on the Company, including our financial position, operating results, liquidity and aability to obtain financing in future reporting periods, due to numerous uncertainties outside of the Company’s control.

Inflation

Heightened levels of inflation, primarily related to steel, diesel fuel and labor, continue to present risk for CNX and the broader natural gas ~~exploration~~industry. CNX experienced higher capital costs from inflation in the first half of 2022, if inflation continues to increase, and CNX is unable to successfully mitigate the impact, our costs could increase further, having a greater impact on our financial position. Rising interest rates could also increase our borrowing costs on new debt and could affect the fair value of our investments. CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset cost increases from inflation.

Hedging Update:

Total hedged natural gas production ~~(E&P) company (the “spin-off”).~~in the third quarter of 2022 is 118.6(1) Bcf. The annual gas hedge position is shown in the table below:


	2022	2023
Volumes Hedged (Bcf), as of 7/7/22	473.9(1)(2)	417.2

1Net of purchased swaps.

2Includes actual settlements of 265.5 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 ~~connection~~addition, to protect the NYMEX hedge volumes from basis exposure, CNX enters into basis-only financial hedges and physical sales with ~~the proposed spin-off, CONSOL Mining Corporation (“CONSOL Mining”), a subsidiary~~fixed basis at certain sales points. For further information see Item 3 Quantitative and Qualitative Disclosures About Market Risk.

Results of ~~the Company that will hold the coal business at the time~~Operations - Three Months Ended June 30, 2022 Compared with Three Months Ended June 30, 2021

Net Income (Loss)

CNX reported net income of the spin-off, previously filed a Registration Statement on Form 10 with the United States Securities and Exchange Commission (the “SEC”), which includes information about CONSOL Mining and the business and assets that it will own upon completion$33 million, or earnings per diluted share of the spin-off. The Registration Statement on Form 10 has not yet been declared effective by the SEC, and completion of the spin-off remains subject to various conditions. The Company’s board of directors gave final approval to the spin-off on October 30, 2017.

~~CONSOL Energy's E&P Division had earnings before income tax of $20 million~~$0.15, for the three months ended ~~September~~June 30, ~~2017,~~2022, compared to ~~earnings before income tax~~a net loss of ~~$161~~$354 million, or a loss per diluted share of $1.61, for the three months ended ~~September~~June 30, ~~2016.~~ 2021.

Included in the ~~2017~~ earnings ~~before income tax~~for the three months ended June 30, 2022 was an unrealized ~~gain~~loss on commodity derivative instruments of ~~$2 million~~$122 million. Included in the loss for the three months ended June 30, 2021 was an unrealized loss on commodity derivative instruments of $529 million.

Non-GAAP Financial Measures

CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the company. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a ~~gain on sale~~natural gas company’s operating performance. Sales of ~~assets~~Natural Gas, NGL and Oil, including cash settlements excludes the impacts of ~~$27 million~~changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note ~~3 - Acquisitions and Dispositions~~13 – Segment Information in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). ~~Included in the 2016 earnings before income tax was an unrealized gain on commodity derivative instruments~~These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of ~~$160 million~~Natural Gas, NGL and ~~a gain on sale of assets of $15 million.~~

For the third quarter of 2017, CONSOL Energy's average sales price for natural gas, natural gas liquids (NGLs), oil, and condensate was $2.50 per Mcfe. CONSOL Energy's average price for natural gas was $2.18 per Mcf for the quarter and,Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from ~~hedging, was $2.38 per Mcf. The average realized price~~Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all ~~liquids for the third quarter~~companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of ~~2017 was $20.77 per barrel.~~other companies.

~~During the third quarter of 2017, CONSOL's E&P Division sold 101.0 Bcfe, or an increase of 4.8% from the 96.4 Bcfe sold in the year-earlier quarter. Also during the quarter, total~~Non-GAAP Financial Measures Reconciliation


	For the Three Months Ended June 30,
(Dollars in millions)	2022		2021
Total Revenue and Other Operating Income (Loss)	$	420	$	(127)
Add (Deduct):
Purchased Gas Revenue	(46)		(17)
Loss on Commodity Derivative Instruments	122		529
Other Revenue and Operating Income	(23)		(26)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	473	$	359

Total Operating Expense	$	330	$	281
Add (Deduct):
Depreciation, Depletion and Amortization (DD&A) - Corporate	(2)		(3)
Exploration and Production Related Other Costs	(5)		(3)
Purchased Gas Costs	(46)		(15)


Selling, General and Administrative Costs	(30)		(24)
Other Operating Expense	(21)		(15)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	226	$	221

1 Natural Gas, NGL and Oil production costs ~~decreased to $2.26 per Mcfe, compared to the year-earlier quarter~~consists primarily of ~~$2.36 per Mcfe, driven primarily by reductions in~~lease operating expense, ~~non-income based taxes~~production ad valorem and ~~deprecation,~~other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.

~~E&P Division capital expenditures in the third quarter were $148 million.~~

CONSOL Energy's PA Mining Operations division sold 6.3 million tons in the third quarter of 2017, compared to 6.0 million tons during the year-earlier quarter. Total unit costs were $37.32 per ton, compared to $35.79 per ton in the year-earlier quarter. The PA Mining Operations division had earnings before income tax of $21 million.

~~CONSOL Energy 2017 - 2018 Guidance~~

~~E&P DIVISION GUIDANCE~~

CONSOL Energy maintains its E&P Division production guidance for 2017 of approximately 405-415 Bcfe and total E&P capital expenditures in 2017 of approximately $620-$645 million. For full year 2018, the company maintains production guidance of 520-550 Bcfe.

~~Total hedged natural gas production in the fourth quarter of 2017 is 83.1 Bcf. The annual gas hedge position is shown in the table below:~~

2017 2018
Volumes Hedged (Bcf), as of 10/17/17 316.6* 333.3
31

^*~~Includes actual settlements of 258.2 Bcf.~~

CONSOL Energy's hedged gas volumes include a combination of NYMEX financial hedges and index (NYMEX and basis) hedges and contracts. In addition, to protect the NYMEX hedge volumes from basis exposure, CONSOL Energy enters into basis-only financial hedges and physical sales with fixed basis at certain sales points. CONSOL Energy's gas hedge position is shown in the table below:

Selected Natural Gas, NGL and Oil Production Financial Data

~~GAS HEDGES~~

Q4 2017 2017 2018 2019 2020
NYMEX Only Hedges
Volumes (Bcf) 73.5
282.4
316.1
226.3
161.6
Average Prices ($/Mcf) $ 3.16
$ 3.14
$ 3.14
$ 2.99
$ 2.89
Index Hedges and Contracts
Volumes (Bcf) 9.6
34.2
17.2
13.1
11.9
Average Prices ($/Mcf) $ 3.01
$ 3.11
$ 2.62
$ 2.44
$ 2.27
Total Volumes Hedged (Bcf)¹
83.1
316.6
333.3
239.4
173.5

NYMEX + Basis (fully-covered volumes)²

Volumes (Bcf) 81.7
311.3
333.3
239.1
166.2
Average Prices ($/Mcf) $ 2.62
$ 2.59
$ 2.78
$ 2.69
$ 2.59
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf) 1.4
5.3
—
0.3
7.3
Average Prices ($/Mcf) $ 3.16
$ 3.14
$ —
$ 2.99
$ 2.89
Total Volumes Hedged (Bcf)¹
83.1
316.6
333.3
239.4
173.5

¹~~2018 excludes 9.1 Bcf of physical basis sales not matched with NYMEX hedges.~~

²~~Includes physical sales with fixed basis in Q4 2017, 2017, 2018, 2019, and 2020 of 19.1 Bcf, 64.0 Bcf, 97.5 Bcf, 103.9 Bcf, and 65.0 Bcf, respectively.~~

During the third quarter of 2017, CONSOL Energy added additional NYMEX natural gas hedges of 4.3 Bcf, 7.0 Bcf, 21.9 Bcf, and 94.1 Bcf for 2018, 2019, 2020, and 2021, respectively. To help mitigate basis exposure on NYMEX hedges, in the third quarter CONSOL Energy added 1.4 Bcf, 34.4 Bcf, 37.7 Bcf, 41.4 Bcf, and 54.2 Bcf of basis hedges for 2017, 2018, 2019, 2020, and 2021, respectively.

~~PA MINING OPERATIONS DIVISION GUIDANCE~~

CONSOL Energy expects total consolidated PA Mining Operations annual sales to be approximately 26.0-27.0 million tons for 2017. Also, CONSOL Energy reduces total consolidated capital expenditures for PA Mining Operations to $92-$108 million for 2017.

~~Results of Operations -~~ ~~Three Months Ended September 30, 2017 Compared with Three Months Ended September 30, 2016~~

~~Net (Loss) Income Attributable to CONSOL Energy Shareholders~~

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $26 million, or a loss per diluted share of $0.11, for the three months ended September 30, 2017, compared to net income attributable to CONSOL Energy shareholders of $25 million, or earnings of $0.11 per diluted share, for the three months ended September 30, 2016.

For the Three Months Ended September 30,
(Dollars in thousands) 2017 2016 Variance
(Loss) Income from Continuing Operations $ (25,651 ) $ 62,568
$ (88,219 )
Loss from Discontinued Operations, net —
(34,975 ) 34,975
Net (Loss) Income $ (25,651 ) $ 27,593
$ (53,244 )
Less: Net Income Attributable to Noncontrolling Interest 790
2,248
(1,458 )
Net (Loss) Income Attributable to CONSOL Energy Shareholders $ (26,441 ) $ 25,345
$ (51,786 )

CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Pennsylvania (PA) Mining Operations. The E&P division includes four reportable segments: Marcellus, Utica, Coalbed Methane (CBM) and Other Gas.

The E&P division had earnings before income tax of $20 million for the three months ended September 30, 2017, compared to earnings before income tax of $161 million for the three months ended September 30, 2016. Included in the 2017 earnings before income tax was an unrealized gain on commodity derivative instruments of $2 million and gain on sale of assets of $27 million (See Note 3 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). Included in the 2016 earnings before income tax was an unrealized gain on commodity derivative instruments of $160 million and gain on sale of assets of $15 million.

The following table presents a ~~breakout~~summary of ~~net liquid~~our total sales volumes, sales of natural gas, NGL and oil including cash settlements, natural gas, NGL and oil production costs and natural gas, NGL and oil production margin related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP):


	For the Three Months Ended June 30,
	2022				2021				Variance
	in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			142.3				137.9				4.4

Natural Gas, NGL and Oil Revenue	$	1,003	$	7.30	$	369	$	2.68	$	634	$	4.62
Loss on Commodity Derivative Instruments - Cash Settlement - Gas	(530)		(3.98)		(10)		(0.08)		(520)		(3.90)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	473		3.32		359		2.60		114		0.72
Lease Operating Expense	14		0.10		10		0.07		4		0.03
Production, Ad Valorem, and Other Fees	10		0.07		7		0.05		3		0.02
Transportation, Gathering and Compression	88		0.62		84		0.61		4		0.01
Depreciation, Depletion and Amortization (DD&A)	114		0.79		120		0.87		(6)		(0.08)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure	226		1.58		221		1.60		5		(0.02)
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure	$	247	$	1.74	$	138	$	1.00	$	109	$	0.74

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

The 4.4 Bcfe increase in total sales ~~information to assist~~volumes in the ~~understanding of the Company’s natural gas production and sales portfolio.~~

For the Three Months Ended September 30,
in thousands (unless noted) 2017 2016 Variance Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe) 10,308
12,341
(2,033 ) (16.5 )%
Sales Volume (Mbbls) 1,718
2,057
(339 ) (16.5 )%
Gross Price ($/Bbl) $ 19.32
$ 13.14
$ 6.18
47.0 %
Gross Revenue $ 33,220
$ 27,048
$ 6,172
22.8 %

Oil:
Sales Volume (MMcfe) 90
94
(4 ) (4.3 )%
Sales Volume (Mbbls) 15
16
(1 ) (4.3 )%
Gross Price ($/Bbl) $ 41.94
$ 42.06
$ (0.12 ) (0.3 )%
Gross Revenue $ 631
$ 663
$ (32 ) (4.8 )%

Condensate:
Sales Volume (MMcfe) 625
1,205
(580 ) (48.1 )%
Sales Volume (Mbbls) 104
201
(97 ) (48.1 )%
Gross Price ($/Bbl) $ 41.34
$ 37.26
$ 4.08
11.0 %
Gross Revenue $ 4,306
$ 7,483
$ (3,177 ) (42.5 )%

GAS
Sales Volume (MMcf) 90,004
82,752
7,252
8.8 %
Sales Price ($/Mcf) $ 2.18
$ 2.06
$ 0.12
5.8 %
Gross Revenue $ 196,286
$ 170,720
$ 25,566
15.0 %

Hedging Impact ($/Mcf) $ 0.20
$ 0.47
$ (0.27 ) (57.4 )%
Gain on Commodity Derivative Instruments - Cash Settlement $ 17,671
$ 38,637
$ (20,966 ) (54.3 )%

The E&P division's natural gas, NGLs, and oil sales were $234 million for the three months ended September 30, 2017, compared to $206 million for the three months ended September 30, 2016. The increaseperiod-to-period comparison was primarily due to the ~~5.8% increase~~turn-in-line of new wells throughout 2021 and in the ~~average gas sales price per Mcf without the impact~~second quarter of ~~derivative instruments and the 4.8% increase in total E&P sales volumes.~~

~~The E&P division's sales volumes, average sales price (including the effects of derivative instruments), and average costs for all active E&P operations were as follows:~~

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
E&P Sales Volumes (Bcfe) 101.0
96.4
4.6
4.8 %

Average Sales Price (per Mcfe) $ 2.50
$ 2.54
$ (0.04 ) (1.6 )%
Average Costs (per Mcfe) 2.26
2.36
(0.10 ) (4.2 )%
Average Margin $ 0.24
$ 0.18
$ 0.06
33.3 %

~~The decrease in average sales price was the result of the $0.27 per Mcf decrease in the realized gain on commodity derivative instruments related to the Company's hedging program~~2022, offset in part by ~~a $0.12 per Mcf improvement in general market prices in the Appalachian basin during the current period as well as an overall increase in natural gas liquids pricing.~~normal production declines.

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

~~Depreciation, depletion and amortization decreased~~

•Lease operating expense increased on a ~~per-unit~~per unit basis primarily ~~due to a reduction in Marcellus rates~~ as a result of an increase in ~~the Company's Marcellus reserves. See Note 9 - Property, Plant~~repairs and ~~Equipment of the Notes to the Unaudited Consolidated Financial Statements~~maintenance expense, including both routine and water impoundment maintenance, as well as an increase in ~~Item 1 of this Form 10-Q for additional information.~~water disposal costs.

•Production, ad valorem and other fees ~~decreased~~increased on a per unit basis ~~in the period-to-period comparison, primarily the~~as a result of ~~the declining tax basis~~increased realized prices on natural gas and natural gas liquids.

•Transportation, Gathering and Compression increased primarily due to an increase in ~~the Company's shallow oil~~gathering system repairs and ~~gas wells, as well as various asset sales. See Note 3 - Acquisitions~~maintenance expense and ~~Dispositions~~an increase in electrical compression expense.

•Depreciation, depletion and ~~Note 9 - Property, Plant and Equipment of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.~~

~~Lease operating~~amortization expense decreased on a per unit basis ~~in the period-to-period comparison~~ due to a ~~decrease~~lower annual depletion rate primarily resulting from lower cost reserve additions from development during the 2021 period.

Average Realized Price Reconciliation

The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in ~~well tending costs, costs passed~~the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:


	For the Three Months Ended June 30,
in thousands (unless noted)	2022		2021		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	8,845		9,469		(624)		(6.6)	%
Sales Volume (Mbbls)	1,474		1,578		(104)		(6.6)	%
Gross Price ($/Bbl)	$	43.26	$	26.28	$	16.98	64.6	%
Gross NGL Revenue	$	63,774	$	41,521	$	22,253	53.6	%

Oil/Condensate:
Sales Volume (MMcfe)	343		785		(442)		(56.3)	%
Sales Volume (Mbbls)	57		131		(74)		(56.5)	%
Gross Price ($/Bbl)	$	96.24	$	53.11	$	43.13	81.2	%
Gross Oil/Condensate Revenue	$	5,505	$	6,946	$	(1,441)	(20.7)	%

NATURAL GAS
Sales Volume (MMcf)	133,143		127,666		5,477		4.3	%
Sales Price ($/Mcf)	$	7.02	$	2.51	$	4.51	179.7	%
Gross Natural Gas Revenue	$	934,127	$	320,982	$	613,145	191.0	%

Hedging Impact ($/Mcf)	$	(3.98)	$	(0.08)	$	(3.90)	(4,875.0)	%
Loss on Commodity Derivative Instruments - Cash Settlement	$	(530,391)	$	(10,359)	$	(520,032)	5,020.1	%

The increase in gross revenue was primarily the result of the $4.51 per Mcf increase in natural gas prices, when excluding the impact of hedging, the $16.98 per Bbl increase in NGL prices and the 4.4 Bcfe increase in sales volumes. These increases were offset, in-part, by the impact of the change in the realized loss on ~~by our joint-venture partners and environmental costs. The decrease in unit costs was also due~~commodity derivative instruments related to the ~~overall increase in E&P sales volumes.~~Company's hedging program.

SEGMENT ANALYSIS for the three months ended June 30, 2022 compared to the three months ended June 30, 2021:


	For the Three Months Ended								Difference to Three Months Ended
	June 30, 2022								June 30, 2021
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total
Natural Gas, NGLs and Oil Revenue	$	923	$	79	$	1	$	1,003	$	591	$	43	$	—	$	634
Loss on Commodity Derivative Instruments	(489)		(41)		(122)		(652)		(480)		(40)		407		(113)
Purchased Gas Revenue	—		—		46		46		—		—		29		29
Other Revenue and Operating Income	18		—		5		23		(1)		—		(2)		(3)
Total Revenue and Other Operating Income (Loss)	452		38		(70)		420		110		3		434		547
Lease Operating Expense	10		4		—		14		3		1		—		4
Production, Ad Valorem, and Other Fees	8		2		—		10		1		1		1		3
Transportation, Gathering and Compression	76		12		—		88		2		2		—		4
Depreciation, Depletion and Amortization	96		13		7		116		(8)		(1)		2		(7)

Exploration and Production Related Other Costs	—		—		5		5		—		—		2		2
Purchased Gas Costs	—		—		46		46		—		—		31		31
Selling, General and Administrative Costs	—		—		30		30		—		—		6		6
Other Operating Expense	—		—		21		21		—		—		6		6
Total Operating Expense	190		31		109		330		(2)		3		48		49
Other Expense	—		—		5		5		—		—		(1)		(1)
Gain on Asset Sales and Abandonments, net	—		—		(6)		(6)		—		—		1		1
Loss on Debt Extinguishment	—		—		13		13		—		—		13		13
Interest Expense	—		—		31		31		—		—		(8)		(8)
Total Other Expense	—		—		43		43		—		—		5		5
Total Costs and Expenses	190		31		152		373		(2)		3		53		54
Earnings (Loss) Before Income Tax	$	262	$	7	$	(222)	$	47	$	112	$	—	$	381	$	493

SHALE SEGMENT

The ~~PA Mining Operations division~~Shale segment had earnings before income tax of ~~$21~~$262 million for the three months ended ~~September~~June 30, ~~2017,~~2022 compared to earnings before income tax of ~~$35~~$150 million for the three months ended ~~September~~June 30, ~~2016.~~2021.

~~Sales tons, average sales price and average cost of goods sold per ton for the PA Mining Operations division were as follows:~~

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
Company Produced PA Mining Operations Tons Sold (in millions) 6.3
6.0
0.3
5.0 %

Average Sales Price per ton sold $ 44.16
$ 44.30
$ (0.14 ) (0.3 )%
Average Cost of Goods Sold per ton sold 37.32
35.79
1.53
4.3 %
Average Margin $ 6.84
$ 8.51
$ (1.67 ) (19.6 )%

The increase in overall tons sold was primarily related to an increase in export tons in the period-to-period comparison. The PA Mining Operations division priced 2.1 million tons on the export market for the three months ended September 30, 2017, compared to 0.6 million tons for the three months ended September 30, 2016. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily driven by an increase in belt advancement and equipment overhaul related projects, additional operating expenses incurred at the Bailey Mine resulting from permitting issues and adverse geological conditions at the Enlow Fork Mine.

The Other division includes other business activities not assigned to the E&P or PA Mining Operations divisions, as well as any income tax benefit or expense. The Other division had a net loss of $67 million for the three months ended September 30, 2017, compared to a net loss of $134 million for the three months ended September 30, 2016.

Selling, general and administrative (SG&A) costs are charged to the PA Mining Operations division based upon a shared service agreement between CONSOL Energy and CNX Coal Resources LP (CNXC). The shared service agreement calls for CONSOL Energy to provide certain selling, general and administrative services that are paid for monthly, based on an agreed upon fixed fee that is reset at least annually. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. The remaining SG&A costs are allocated between the E&P, PA Mining Operations and Other divisions based primarily on a percentage of total revenue and a percentage of total projected capital expenditures.

SG&A costs are excluded from E&P and PA Mining Operations unit costs. SG&A costs were $42 million for the three months ended September 30, 2017, compared to $39 million for the three months ended September 30, 2016. SG&A costs increased due to the following items:

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Stock-Based Compensation $ 11
$ 8
$ 3
37.5 %
Short-Term Incentive Compensation 6
5
1
20.0 %
Consulting and Professional Services 4
4
—
— %
Rent 2
2
—
— %
Advertising and Promotion —
1
(1 ) (100.0 )%
Employee Wages and Related Expenses 13
15
(2 ) (13.3 )%
Other 6
4
2
50.0 %
Total Company Selling, General and Administrative Costs

$ 42
$ 39
$ 3
7.7 %

Stock-Based Compensation expense increased $3 million in the period-to-period comparison primarily due to additional non-cash amortization recorded in the current period for employees who received awards under the Performance Share Unit (PSU) program.

~~Employee Wages and Related Expenses decreased $2 million in the period-to-period comparison due to reductions in employee headcount in the current period.~~

Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers' compensation, Coal Workers' Pneumoconiosis (CWP) and long-term disability are actuarially calculated for the Company as a whole. In general, the expenses are then allocated to the segments based upon criteria specific to each liability. Total CONSOL Energy continuing operations expense related to actuarial liabilities was $14 million for the three months ended September 30, 2017, compared to $17 million for the three months ended September 30, 2016. See Note 14 - Pension and Other Postretirement Benefits Plans and Note 15 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of the Company's December 31, 2016 Form 10-K, and Note 5 - Components of Pension and OPEB Plans Net Periodic Benefit Costs and Note 6 - Components of CWP and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details.

~~TOTAL E&P DIVISION ANALYSIS for the three months ended September 30, 2017 compared to the three months ended September 30, 2016:~~

The E&P division had earnings before income tax of $20 million for the three months ended September 30, 2017 compared to earnings before income tax of $161 million for the three months ended September 30, 2016. Variances by individual E&P segment are discussed below.

For the Three Months Ended Difference to Three Months Ended
September 30, 2017 September 30, 2016
(in millions) Marcellus Utica CBM
Other
Gas
Total E&P Marcellus Utica CBM
Other
Gas

Total
E&P
Natural Gas, NGLs and Oil Sales $ 134
$ 43
$ 47
$ 10
$ 234
$ 27
$ 3
$ —
$ (2 ) $ 28
Gain on Commodity Derivative Instruments 11
3
3
2
19
(13 ) (2 ) (5 ) (159 ) (179 )
Purchased Gas Sales —
—
—
13
13
—
—
—
1
1
Miscellaneous Other Income —
—
—
21
21
—
—
—
2
2
Gain on Sale of Assets —
—
—
27
27
—
—
—
12
12
Total Revenue and Other Income 145
46
50
73
314
14
1
(5 ) (146 ) (136 )
Lease Operating Expense 8
5
7
2
22
—
1
—
(2 ) (1 )
Production, Ad Valorem, and Other Fees 3
1
2
—
6
(2 ) —
—
(1 ) (3 )
Transportation, Gathering and Compression 67
12
16
4
99
10
(2 ) (2 ) (2 ) 4
Depreciation, Depletion and Amortization 55
21
20
6
102
4
(1 ) (1 ) (1 ) 1
Exploration and Production Related Other Costs —
—
—
4
4
—
—
—
4
4
Purchased Gas Costs —
—
—
13
13
—
—
—
1
1
Other Corporate Expenses —
—
—
27
27
—
—
—
5
5
Selling, General and Administrative Costs

—
—
—
20
20
—
—
—
(6 ) (6 )
Total Exploration and Production Costs 133
39
45
76
293
12
(2 ) (3 ) (2 ) 5
Interest Expense —
—
—
1
1
—
—
—
—
—
Total E&P Division Costs 133
39
45
77
294
12
(2 ) (3 ) (2 ) 5
Earnings (Loss) Before Income Tax $ 12
$ 7
$ 5
$ (4 ) $ 20
$ 2
$ 3
$ (2 ) $ (144 ) $ (141 )

~~MARCELLUS SEGMENT~~

The Marcellus segment had earnings before income tax of $12 million for the three months ended September 30, 2017 compared to earnings before income tax of $10 million for the three months ended September 30, 2016.

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
Marcellus Gas Sales Volumes (Bcf) 52.1
43.0
9.1
21.2 %
NGLs Sales Volumes (Bcfe)* 7.9
8.3
(0.4 ) (4.8 )%
Condensate Sales Volumes (Bcfe)* 0.4
0.5
(0.1 ) (20.0 )%
Total Marcellus Sales Volumes (Bcfe)* 60.4
51.8
8.6
16.6 %

Average Sales Price - Gas (per Mcf) $ 2.03
$ 2.06
$ (0.03 ) (1.5 )%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.22
$ 0.55
$ (0.33 ) (60.0 )%
Average Sales Price - NGLs (per Mcfe)* $ 3.17
$ 1.94
$ 1.23
63.4 %
Average Sales Price - Condensate (per Mcfe)* $ 6.18
$ 5.50
$ 0.68
12.4 %

Total Average Marcellus Sales Price (per Mcfe) $ 2.40
$ 2.53
$ (0.13 ) (5.1 )%
Average Marcellus Lease Operating Expenses (per Mcfe) 0.13
0.15
(0.02 ) (13.3 )%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe) 0.04
0.10
(0.06 ) (60.0 )%
Average Marcellus Transportation, Gathering and Compression costs (per Mcfe) 1.10
1.10
—
— %
Average Marcellus Depreciation, Depletion and Amortization costs (per Mcfe) 0.93
0.98
(0.05 ) (5.1 )%
Total Average Marcellus Costs (per Mcfe) $ 2.20
$ 2.33
$ (0.13 ) (5.6 )%
Average Margin for Marcellus (per Mcfe) $ 0.20
$ 0.20
$ —
— %


	For the Three Months Ended June 30,
	2022		2021		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	122.1		115.0		7.1		6.2	%
NGLs Sales Volumes (Bcfe)*	8.8		9.5		(0.7)		(7.4)	%
Oil/Condensate Sales Volumes (Bcfe)*	0.3		0.7		(0.4)		(57.1)	%
Total Shale Sales Volumes (Bcfe)*	131.2		125.2		6.0		4.8	%

Average Sales Price - Natural Gas (per Mcf)	$	7.00	$	2.47	$	4.53	183.4	%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(4.01)	$	(0.08)	$	(3.93)	(4,912.5)	%
Average Sales Price - NGLs (per Mcfe)*	$	7.21	$	4.38	$	2.83	64.6	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	16.03	$	8.84	$	7.19	81.3	%

Total Average Shale Sales Price (per Mcfe)	$	3.31	$	2.58	$	0.73	28.3	%
Average Shale Lease Operating Expenses (per Mcfe)	0.08		0.06		0.02		33.3	%
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)	0.05		0.05		—		—	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.58		0.59		(0.01)		(1.7)	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.74		0.83		(0.09)		(10.8)	%
Total Average Shale Production Costs (per Mcfe)	$	1.45	$	1.53	$	(0.08)	(5.2)	%
Total Average Shale Production Margin (per Mcfe)	$	1.86	$	1.05	$	0.81	77.1	%

* 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.

The ~~Marcellus~~Shale segment had natural gas, NGLs and ~~oil sales~~oil/condensate revenue of ~~$134~~$923 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$107~~$332 million for the three months ended ~~September~~June 30, ~~2016.~~2021. The ~~$27~~$591 million increase was due primarily ~~due~~ to a ~~16.6%~~183.4% increase in the average sales price for natural gas, a 4.8% increase in total ~~Marcellus~~Shale sales volumes, ~~partially offset by~~and a ~~1.5% decrease~~64.6% increase in the average ~~gas~~ sales ~~price.~~price of NGLs. The increase in ~~sales~~total Shale volumes was primarily due to ~~additional~~the turn-in-line of new wells ~~being turned~~throughout 2021 and the first half of 2022, offset in ~~line in the current period.~~part by normal production declines.

The ~~decrease~~increase in ~~the~~ total average ~~Marcellus~~Shale sales price was primarily due to a ~~$0.33~~$4.53 per Mcf increase in average gas sales price and a $2.83 per Mcfe increase in the average NGL sales price. These increases were offset in part by a $3.93 per Mcf change in the realized loss on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 104.6 Bcf of the Company's produced Shale gas sales volumes for the three months ended June 30, 2022 at an average loss of $4.68 per Mcf hedged. For the three months ended June 30, 2021, these financial hedges represented approximately 99.1 Bcf at an average loss of $0.09 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $190 million for the three months ended June 30, 2022 compared to $192 million for the three months ended June 30, 2021. The decrease in total dollars and decrease in unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $10 million for the three months ended June 30, 2022 compared to $7 million for the three months ended June 30, 2021. The increases in total dollars and unit costs were primarily related to an increase in repairs and maintenance expense, including both routine and water impoundment maintenance, as well as an increase in water disposal costs.

•Shale production, ad valorem and other fees were $8 million for the three months ended June 30, 2022 compared to $7 million for the three months ended June 30, 2021. The increases in total dollars was primarily due to increased realized prices on natural gas and natural gas liquids.

•Shale transportation, gathering and compression costs were $76 million for the three months ended June 30, 2022 compared to $74 million for the three months ended June 30, 2021. The increase in total dollars was primarily related to an increase in total volumes as well as an increase in gathering systems repairs and maintenance expense.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $96 million for the three months ended June 30, 2022 compared to $104 million for the three months ended June 30, 2021. These amounts included depletion on a units of production basis of $0.62 per Mcfe and $0.72 per Mcfe, respectively. The decrease in the ~~gain~~units of production depreciation, depletion and amortization rate in the current period is primarily the result of a lower annual depletion rate related to low-cost reserve additions from development in the 2021 period. 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 $18 million for the three months ended June 30, 2022 compared to $19 million for the three months ended June 30, 2021. The decrease in the period-to-period comparison was primarily due to lower third-party gathering volumes due to normal production declines.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $7 million for both the three months ended June 30, 2022 and June 30, 2021.


	For the Three Months Ended June 30,
	2022		2021		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	11.0		12.6		(1.6)		(12.7)	%

Average Sales Price - Gas (per Mcf)	$	7.23	$	2.91	$	4.32	148.5	%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(3.75)	$	(0.08)	$	(3.67)	(4,587.5)	%

Total Average CBM Sales Price (per Mcf)	$	3.49	$	2.83	$	0.66	23.3	%
Average CBM Lease Operating Expenses (per Mcf)	0.39		0.26		0.13		50.0	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.22		0.05		0.17		340.0	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	1.07		0.79		0.28		35.4	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.18		1.15		0.03		2.6	%
Total Average CBM Production Costs (per Mcf)	$	2.86	$	2.25	$	0.61	27.1	%
Total Average CBM Production Margin (per Mcf)	$	0.63	$	0.58	$	0.05	8.6	%

The CBM segment had natural gas revenue of $79 million for the three months ended June 30, 2022 compared to $36 million for the three months ended June 30, 2021. The increase was due to a 148.5% increase in the average sales price for natural gas in the current period, offset in part by the 12.7% decrease in total CBM sales volumes. The decrease in CBM sales volumes was primarily due to normal production declines.

The total average CBM sales price increased $0.66 per Mcf due to a $4.32 per Mcf increase in average gas sales price, offset in part by a $3.67 per Mcf change in the realized loss on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately ~~49.5~~8.9 Bcf of the Company's produced ~~Marcellus gas~~CBM sales volumes for the three months ended ~~September~~June 30, ~~2017~~2022 at an average ~~gain~~loss of ~~$0.23~~$4.64 per ~~Mcf.~~Mcf hedged. For the three months ended ~~September~~June 30, ~~2016,~~2021, these financial hedges represented approximately ~~44.2~~10.2 Bcf at an average ~~gain~~loss of ~~$0.53~~$0.07 per ~~Mcf.~~Mcf hedged.

Total ~~exploration~~operating costs and ~~production costs~~expenses for the ~~Marcellus~~CBM segment were ~~$133~~$31 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$121~~$28 million for the three months ended ~~September~~June 30, ~~2016.~~2021. The increase in total dollars and ~~decrease~~increase in unit costs for the ~~Marcellus~~CBM segment were due to the following items:

•~~Marcellus~~CBM lease operating expense ~~remained consistent at $8~~was $4 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to $3 million for the three months ended June 30, 2021. The increases in total dollars and ~~September 30, 2016. The decrease in~~ unit costs ~~was driven by the 16.6% increase~~were primarily due to increases in ~~total Marcellus sales volumes.~~repairs and maintenance expense.

•~~Marcellus~~CBM production, ad valorem and other fees were $3$2 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to $5$1 million for the three months ended ~~September~~June 30, ~~2016.~~2021. The ~~decrease~~increases in total dollars ~~was primarily related to a change in production mix by state as a result of the termination of the Marcellus joint venture with Noble Energy. The decrease in~~and unit costs ~~was~~were primarily due to ~~the decreased total dollars described above, as well as the 16.6% increase in total Marcellus sales volumes.~~increased realized prices on natural gas.

•~~Marcellus~~CBM transportation, gathering and compression costs were ~~$67~~$12 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$57~~$10 million for the three months ended ~~September~~June 30, ~~2016.~~2021. The ~~increase~~increases in total dollars ~~was~~and unit costs were primarily ~~related to a change in production mix to higher cost wet gas offset, in part, by a decrease in firm transportation expense~~ due to ~~a decrease~~increases in ~~utilization.~~repairs and maintenance expense and electrical compression expense.

•Depreciation, depletion and amortization costs attributable to the ~~Marcellus~~CBM segment were ~~$55~~$13 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$51~~$14 million for the three months ended ~~September~~June 30, 2016. The period-to-period increase in total dollars was driven by the increased Marcellus production, offset, in part, by a decrease in overall Marcellus rates primarily due to an increase in the Company's Marcellus reserves.2021. These amounts included depletion on a ~~unit~~units of production basis of ~~$0.91~~$0.64 per Mcfe and ~~$0.97~~$0.66 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period was due to a lower annual depletion rate. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to ~~gas well closing.~~asset retirement obligations.

~~UTICA~~OTHER SEGMENT

The Utica segment had earnings before income tax of $7 million for the three months ended September 30, 2017 compared to earnings before income tax of $4 million for the three months ended September 30, 2016.

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
Utica Gas Sales Volumes (Bcf) 17.5
17.7
(0.2 ) (1.1 )%
NGLs Sales Volumes (Bcfe)* 2.4
4.0
(1.6 ) (40.0 )%
Condensate Sales Volumes (Bcfe)* 0.2
0.7
(0.5 ) (71.4 )%
Total Utica Sales Volumes (Bcfe)* 20.1
22.4
(2.3 ) (10.3 )%

Average Sales Price - Gas (per Mcf) $ 1.92
$ 1.40
$ 0.52
37.1 %
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.14
$ 0.26
$ (0.12 ) (46.2 )%
Average Sales Price - NGLs (per Mcfe)* $ 3.39
$ 2.69
$ 0.70
26.0 %
Average Sales Price - Condensate (per Mcfe)* $ 9.06
$ 6.80
$ 2.26
33.2 %

Total Average Utica Sales Price (per Mcfe) $ 2.28
$ 2.00
$ 0.28
14.0 %
Average Utica Lease Operating Expenses (per Mcfe) 0.23
0.20
0.03
15.0 %
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe) 0.05
0.06
(0.01 ) (16.7 )%
Average Utica Transportation, Gathering and Compression Costs (per Mcfe) 0.62
0.62
—
— %
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe) 1.01
0.93
0.08
8.6 %
Total Average Utica Costs (per Mcfe) $ 1.91
$ 1.81
$ 0.10
5.5 %
Average Margin for Utica (per Mcfe) $ 0.37
$ 0.19
$ 0.18
94.7 %

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

The Utica segment had natural gas, NGLs and oil sales of $43 million for the three months ended September 30, 2017 compared to $40 million for the three months ended September 30, 2016. The $3 million increase was primarily duesignificant to the 37.1% increase in average gas sales price, offset, in part, by the 10.3% decrease in total Utica sales volumes. The decrease in total Utica sales volumes primarily related to normal well declines in both Company operated and joint venture operated areas, as well as temporary shut-ins for additional drilling.

The increase in the total average Utica sales price was primarily due to a $0.52 per Mcf increase in average gas sales price, offset, in part, by a $0.12 per Mcf decrease in the gain on commodity derivative instruments in the current period. The notional amounts associated with these financial hedges represented approximately 10.9 Bcf ofCompany. It also includes the Company's produced Utica gas sales volumes for the three months ended September 30, 2017 at an average gain of $0.23 per Mcf. For the three months ended September 30, 2016, these financial hedges represented approximately 8.8 Bcf at an average gain of $0.53 per Mcf.

Total exploration and production costs for the Utica segment were $39 million for the three months ended September 30, 2017 compared to $41 million for the three months ended September 30, 2016. 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 $5 million for the three months ended September 30, 2017 compared to $4 million for the three months ended September 30, 2016. The increase in total dollars was primarily due to increased repairs and maintenance

expense, as well as higher employee costs in the current period. The increase in unit costs was due to the increased total dollars described above, as well as the 10.3% decrease in total Utica sales volumes.

•Utica production, ad valorem, and other fees remained consistent at $1 million for the three months ended September 30, 2017 and September 30, 2016. The decrease in unit costs was due to a nominal decrease in total dollars.

•Utica transportation, gathering and compression costs were $12 million for the three months ended September 30, 2017 compared to $14 million for the three months ended September 30, 2016. The $2 million decrease in total dollars was primarily related to a decrease in liquids processing fees related to the decrease in production (both Company operated and joint venture operated) and a decrease in utilized firm transportation expense in the current period.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $21 million for the three months ended September 30, 2017 compared to $22 million for the three months ended September 30, 2016. These amounts included depletion on a unit of production basis of $1.01 per Mcfe and $0.93 per Mcfe, respectively.

~~COALBED METHANE (CBM) SEGMENT~~

The CBM segment had earnings before income tax of $5 million for the three months ended September 30, 2017 compared to earnings before income tax of $7 million for the three months ended September 30, 2016.

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
CBM Gas Sales Volumes (Bcf) 16.2
17.0
(0.8 ) (4.7 )%

Average Sales Price - Gas (per Mcf) $ 2.88
$ 2.77
$ 0.11
4.0 %
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.19
$ 0.48
$ (0.29 ) (60.4 )%

Total Average CBM Sales Price (per Mcf) $ 3.07
$ 3.25
$ (0.18 ) (5.5 )%
Average CBM Lease Operating Expenses (per Mcf) 0.41
0.41
—
— %
Average CBM Production, Ad Valorem, and Other Fees (per Mcf) 0.11
0.10
0.01
10.0 %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) 0.98
1.06
(0.08 ) (7.5 )%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.23
1.27
(0.04 ) (3.1 )%
Total Average CBM Costs (per Mcf) $ 2.73
$ 2.84
$ (0.11 ) (3.9 )%
Average Margin for CBM (per Mcf) $ 0.34
$ 0.41
$ (0.07 ) (17.1 )%

The CBM segment natural gas sales remained consistent at $47 million for the three months ended September 30, 2017 and September 30, 2016. The decrease in CBM sales volumes was primarily due to normal well declines and less drilling activity.

The total average CBM sales price decreased $0.18 per Mcf, due primarily to a $0.29 per Mcf decrease in the gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 14.2 Bcf of the Company's produced CBM sales volumes for the three months ended September 30, 2017 at an average gain of $0.22 per Mcf. For the three months ended September 30, 2016, these financial hedges represented approximately 15.3 Bcf at an average gain of $0.54 per Mcf.

Total exploration and production costs for the CBM segment were $45 million for the three months ended September 30, 2017 compared to $48 million for the three months ended September 30, 2016. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:

•CBM production, ad valorem, and other fees remained consistent at $2 million for the three months ended September 30, 2017 and September 30, 2016. Unit costs increased in the current period, due primarily to the 4.7% decrease in CBM sales volumes.

•CBM transportation, gathering and compression costs were $16 million for the three months ended September 30, 2017 compared to $18 million for the three months ended September 30, 2016. The $2 million decrease was primarily related to a decrease in power expense related to an effort to minimize the number of compressors needed and a decrease in utilized firm

transportation expense resulting from the decrease in CBM sales volumes. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM sales volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $20 million for the three months ended September 30, 2017 compared to $21 million for the three months ended September 30, 2016. These amounts included depletion on a unit of production basis of $0.77 per Mcf and $0.81 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

~~OTHER GAS SEGMENT~~

The Other Gas segment had a loss before income tax of $4 million for the three months ended September 30, 2017 compared to earnings before income tax of $140 million for the three months ended September 30, 2016.

For the Three Months Ended September 30,
2017 2016 Variance Percent
Change
Other Gas Sales Volumes (Bcf) 4.2
5.1
(0.9 ) (17.6 )%
Oil Sales Volumes (Bcfe)* 0.1
0.1
—
— %
Total Other Sales Volumes (Bcfe)* 4.3
5.2
(0.9 ) (17.3 )%

Average Sales Price - Gas (per Mcf) $ 2.40
$ 2.03
$ 0.37
18.2 %
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.18
$ 0.44
$ (0.26 ) (59.1 )%
Average Sales Price - Oil (per Mcfe)* $ 7.11
$ 7.03
$ 0.08
1.1 %

Total Average Other Sales Price (per Mcfe) $ 2.63
$ 2.55
$ 0.08
3.1 %
Average Other Lease Operating Expenses (per Mcfe) 0.64
0.71
(0.07 ) (9.9 )%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe) 0.11
0.16
(0.05 ) (31.3 )%
Average Other Transportation, Gathering and Compression Costs (per Mcfe) 0.87
1.10
(0.23 ) (20.9 )%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe) 1.06
1.40
(0.34 ) (24.3 )%
Total Average Other Costs (per Mcfe) $ 2.68
$ 3.37
$ (0.69 ) (20.5 )%
Average Margin for Other (per Mcfe) $ (0.05 ) $ (0.82 ) $ 0.77
93.9 %

*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,~~activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, ~~unutilized firm transportation~~as well as various other expenses that are managed outside the Shale and ~~processing fees, other corporate expenses~~CBM segments such as SG&A, interest expense and ~~miscellaneous operational activity not assigned to~~income taxes.

The Other Segment had a ~~specific E&P segment.~~

~~Other Gas sales volumes are primarily related to shallow oil and gas production. Natural gas, NGLs and oil sales related to the Other Gas segment were $10~~loss before income tax of $222 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$12~~a loss before income tax of $603 million for the three months ended ~~September~~June 30, ~~2016.~~2021. The ~~decrease in natural gas, NGLs and oil sales primarily related to the 17.6% decrease~~increase in total ~~Other Gas sales volumes, offset, in part by the $0.37 per Mcf increase in the average gas sales price. Total exploration and production costs related to these other sales were $12 million for~~dollars is discussed below.


	For the Three Months Ended June 30,
	2022	2021	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.1	0.1	—	—	%

Loss on Commodity Derivative Instruments

For the three months ended ~~September~~June 30, ~~2017 compared to $18 million for~~2022, the three months ended September 30, 2016. The decrease was primarily due to a decrease in depreciation, depletion and amortization costs as a result of certain assets becoming fully depreciated in the current period as well as the sale of Knox Energy in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). There was also a decrease in transportation, gathering and compression costs in the current period primarily related to a decrease in power, compression and environmental expense.

~~The~~ Other ~~Gas segment~~Segment recognized an unrealized ~~gain~~loss on commodity derivative instruments of ~~$2 million for~~$122 million. For the three months ended ~~September~~June 30, ~~2017 compared to~~2021, the Other Segment recognized an unrealized ~~gain~~loss on commodity derivative instruments of ~~$160 million for the three months ended September 30, 2016.~~$529 million. The unrealized ~~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. ~~In addition, the Other~~

Purchased Gas ~~segment had a realized gain of $1 million for the three months ended September 30, 2016 related to the cash settlement of commodity hedges.~~

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
Purchased Gas Sales Volumes (in Bcfe) 5.9
5.7
0.2
3.5 %
Average Sales Price (per Mcfe) $ 2.28
$ 2.11
$ 0.17
8.1 %
Average Cost (per Mcfe) $ 2.24
$ 2.09
$ 0.15
7.2 %

~~Miscellaneous other income was $21~~2021. Purchased gas costs were $46 million for the three months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$19 million for the three months ended September 30, 2016. The $2 million increase was due to the following items:~~

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance Percent
Change
Gathering Revenue $ 3
$ 3
$ —
— %
Equity in Earnings of Affiliates 12
15
(3 ) (20.0 )%
Other 6
1
5
500.0 %
Total Miscellaneous Other Income $ 21
$ 19
$ 2
10.5 %

Equity in Earnings of Affiliates decreased $3 million due to an decrease in earnings from CONE Midstream Partners, LP. and CONE Gathering, LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

~~Gain on sale of assets was a gain of $27 million for the three months ended September 30, 2017 compared to a gain of~~ $15 million for the three months ended ~~September~~June 30, ~~2016.~~2021. The ~~$12 million~~period-to-period increase in purchased gas revenue was ~~primarily~~ due to increases in the average sales price and purchased gas sales volumes.


	For the Three Months Ended June 30,
	2022		2021		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	9.1		5.9		3.2		54.2	%
Average Sales Price (per Mcf)	$	5.14	$	2.82	$	2.32	82.3	%
Purchased Gas Average Cost (per Mcf)	$	5.08	$	2.45	$	2.63	107.3	%

Other Operating Income


	For the Three Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Equity Income from Affiliates	$	1	$	2	$	(1)	(50.0)	%
Water Income	1		2		(1)		(50.0)	%
Excess Firm Transportation Income	3		3		—		—	%

Total Other Operating Income	$	5	$	7	$	(2)	(28.6)	%

•Equity income from affiliates primarily represents CNX's share of earnings from a 50% interest in a power plant located within CNX’s CBM field. Power generated from the facility is sold into wholesale electricity markets during times of peak energy consumption. Due to the plant consuming low carbon intensity coal mine methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy Credits.

•Excess firm transportation income represents revenue from the sale of ~~undeveloped acres of~~excess firm transportation capacity to third-parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the ~~Marcellus Shale~~unutilized firm transportation and processing fees in Allegheny and Westmoreland counties, Pennsylvania. See Note 3 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.total other operating expense.

Exploration and ~~production related other costs were $4 million~~Production Related Other Costs


	For the Three Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Seismic Activity	$	3	$	—	$	3	100.0	%
Land Rentals	1		1		—		—	%
Lease Expiration Costs	1		2		(1)		(50.0)	%

Total Exploration and Production Related Other Costs	$	5	$	3	$	2	66.7	%

•Seismic activity expense for the ~~three months ended September 30, 2017 and were nominal for the three months ended September 30, 2016. The $4 million increase is due~~current period primarily relates to the ~~following items:~~acquisition of three-dimensional seismic data.

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Lease Expiration Costs $ 3
$ —
$ 3
100.0 %
Land Rentals 1
—
1
100.0 %
Total Exploration and Other Costs $ 4
$ —
$ 4
100.0 %

•Lease ~~Expiration Costs~~expiration costs relate to leases where the primary term ~~expired. The $3 million increase in~~expired or will expire within the ~~three months ended September 30, 2017 was primarily due to an increases in leases that were allowed to expire because they are no longer in the Company's future drilling plan.~~next 12 months.

Selling, General and Administrative ("SG&A")

SG&A costs include costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.


	For the Three Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Salaries, Wages and Employee Benefits	$	8	$	6	$	2	33.3	%
Contributions and Advertising	2		—		2		100.0	%
Long-Term Equity-Based Compensation (Non-Cash)	4		3		1		33.3	%
Short-Term Incentive Compensation	3		3		—		—	%
Other	13		12		1		8.3	%
Total SG&A	$	30	$	24	$	6	25.0	%

Other corporate expenses were $27 million for the three months ended September 30, 2017 compared to $22 million for the three months ended September 30, 2016. The $5 million increase in the period-to-period comparison was made up of the following items:

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Consulting and Professional Services $ 5
$ 2
$ 3
150.0 %
Unutilized Firm Transportation and Processing Fees 11
10
1
10.0 %
Litigation Expense 2
1
1
100.0 %
Insurance Expense 1
1
—
— %
Idle Rig Fees 6
8
(2 ) (25.0 )%
Other 2
—
2
100.0 %
Total Other Corporate Expenses $ 27
$ 22
$ 5
22.7 %

~~Consulting~~•Salaries, wages and ~~Professional Services~~employee benefits increased ~~$3 million~~ in the period-to-period comparison primarily due to an increase in ~~legal fees~~employee wages and employee benefit expense.

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

Other Operating Expense


	For the Three Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	18	$	14	$	4	28.6	%

Litigation Settlements	2		—		2		100.0	%
Insurance Expense	1		1		—		—	%

Total Other Operating Expense	$	21	$	15	$	6	40.0	%

•Unutilized ~~Firm Transportation~~firm transportation and ~~Processing Fees~~processing fees represent pipeline transportation capacity ~~the E&P segment has~~ obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas ~~liquids. The~~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 ~~the period-to-period comparison was primarily due to the decrease in the utilization of the capacity.~~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.

~~Idle Rig Fees are fees related to the temporary idling of some of the Company's natural gas rigs.~~ The total idle rig expense incurred by the Company has decreased by $2 million for the current quarter as compared to the prior year quarter due to an increase in drilling activity as a direct result of the recovery in natural gas pricing.

~~Other increased $2 million mainly due to increased legal expenses in the current period.~~

~~Selling, general and administrative (SG&A) costs are allocated to the total E&P division based on percentage of total~~ revenue and percentage of total projected capital expenditures. SG&A costs were $20 million for the three months ended September 30, 2017 compared to $26 million for the three months ended September 30, 2016. Refer to the discussion of total company selling, general and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders"ofreceived when this ~~quarterly report for a detailed cost explanation.~~

Interest expense related to the E&P division remained consistent at $1 million for the three months ended September 30, 2017 and September 30, 2016. Interest incurred by the Other Gas segment primarily relates to a capital lease.

~~TOTAL PA MINING OPERATIONS DIVISION ANALYSIS for the three months ended September 30, 2017 compared to the three months ended September 30, 2016:~~

The PA Mining Operations division's principal activities consist of mining, preparation and marketing of thermal coal to power generators. The division also includes selling, general and administrative costs, as well as various other activities assigned to the PA Mining Operations division but notcapacity is released (sold) is included in ~~the cost components on a per unit basis.~~

The PA Mining Operations division had earnings before income tax of $21 million for the three months ended September 30, 2017, compared to earnings before income tax of $35 million for the three months ended September 30, 2016. Variances are discussed below.

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Sales:
Coal Sales $ 279
$ 268
$ 11
Freight Revenue 22
9
13
Miscellaneous Other Income 12
2
10
Total Revenue and Other Income 313
279
34
Operating Costs and Expenses:
Operating Costs 197
176
21
Depreciation, Depletion and Amortization 39
40
(1 )
Total Operating Costs and Expenses 236
216
20
Other Costs and Expenses:
Other Costs 11
7
4
Depreciation, Depletion and Amortization 2
2
—
Total Other Costs and Expenses 13
9
4
Freight Expense 22
9
13
Selling, General and Administrative Costs 19
8
11
Total PA Mining Operations Costs 290
242
48
Interest Expense 2
2
—
Total PA Mining Operations Division Expense 292
244
48
Earnings Before Income Tax $ 21
$ 35
$ (14 )

~~The PA Mining Operations coal revenue and cost components on a per unit basis for these periods were as follows:~~

For the Three Months Ended September 30,
2017 2016 Variance
Percent
Change
Company Produced PA Mining Operations Tons Sold (in millions) 6.3
6.0
0.3
5.0 %
Average Sales Price Per PA Mining Operations Ton Sold $ 44.16
$ 44.30
$ (0.14 ) (0.3 )%

Total Operating Costs Per Ton Sold $ 30.94
$ 29.29
$ 1.65
5.6 %
Total Depreciation, Depletion and Amortization Costs Per Ton Sold 6.38
6.50
(0.12 ) (1.8 )%
Total Costs Per PA Mining Operations Ton Sold $ 37.32
$ 35.79
$ 1.53
4.3 %
Average Margin Per PA Mining Operations Ton Sold $ 6.84
$ 8.51
$ (1.67 ) (19.6 )%

~~Coal Sales~~

PA Mining Operations coal sales were $279 million for the three months ended September 30, 2017, compared to $268 million for the three months ended September 30, 2016. The $11 million increase was attributable to a 0.3 million increase in tons sold, partially offset by a $0.14 lower average sales price per ton sold. The lower average sales price per ton sold in the 2017 period was primarily the result of mild summer weather and lower power prices in domestic thermal markets. The increase in tons sold was primarily related to increased export tons due to an increase in demand.

~~Freight Revenue and Freight Expense~~

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company contractually provides transportation services. Freight revenue is completely offset by freight expense. Freight revenue and freight expense were both $22 million for the three months ended September 30, 2017, compared to $9 million in the three months ended September 30, 2016. The $13 million increase was due to increased shipments where transportation services were contractually provided.

~~Miscellaneous Other Income~~

~~Miscellaneous other income~~ ~~increased$10 million~~ in the period-to-period comparison, primarily a result of a customer contract buyout in the amount of $8 million in the current period. No such transactions occurred in the prior period. The remaining increase was due to an increase in externally purchased coal for blending purposes only during the three months ended September 30, 2017.

~~Operating Costs and Expenses~~

Operating costs and expenses are comprised of costs related to produced tons sold, along with changes in both the volumes and carrying values of coal inventory. Operating costs and expenses include items such as direct operating costs, royalty and production taxes, employee-related expenses and depreciation, depletion, and amortization costs. Total operating costs and expenses for the PA Mining Operations division were $236 million for the three months ended September 30, 2017, or $20 million higher than the $216 million for the three months ended September 30, 2016. Total costs per PA Mining Operations ton sold were $37.32 per ton for the three months ended September 30, 2017, compared to $35.79 per ton for the three months ended September 30, 2016. The increase in the cost of coal sold was primarily driven by an increase in belt advancement and equipment overhaul related projects, additional operating expenses incurred at the Bailey Mine resulting from permitting issues and adverse geological conditions at the Enlow Fork Mine.

~~Other Costs and Expenses~~

Other costs and expenses include items that are assigned to the PA Mining Operations division but are not included in unit costs, such as coal reserve holding costs and purchased coal costs. Total other costs and expenses increased $4 million in the three months ended September 30, 2017 compared to the three months ended September 30, 2016. The increase was primarily attributable to severance costs in the current quarter related to organizational restructuring, an increase in current quarter costs related to externally purchased coal for blending purposes only and a state tax audit settlement in the year earlier quarter. These were offset, in part, by a decrease in discretionary 401(k) contributions in the period-to-period comparison.

~~Selling, General and Administrative Costs~~

Upon execution of the CNXC IPO, CNXC entered into a service agreement with CONSOL Energy that requires CONSOL Energy to provide certain selling, general and administrative services. These services are paid monthly based on an agreed upon fixed fee that is reset at least annually. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. An additional portion of CONSOL Energy's SG&A costs are allocated to the PA Mining Operations division based on a percentage of total revenue and a percentage of total projected capital expenditures.The amount of selling, general and administrative costs related to PA Mining Operations was $19 million for the three months ended September 30, 2017, compared to $8 million for the three months ended September 30, 2016. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net (Loss)Excess Firm Transportation Income ~~Attributable to CONSOL Energy Shareholders"of this quarterly report for a detailed cost explanation.~~

~~Interest Expense~~

Interest expense, net of amounts capitalized, of $2 million for the three months ended September 30, 2017 and 2016 is primarily comprised of interest on the CNXC revolving credit facility that was drawn upon after the CNXC IPO on July 7, 2015.

~~OTHER DIVISION ANALYSIS for the three months ended~~ ~~September 30, 2017~~ ~~compared to the three months ended~~ ~~September 30, 2016~~:

above. The Other division includes various corporate and diversified business activities that are not allocated to the E&P or PA Mining Operations divisions. The diversified business activities include CNX Marine Terminal, closed and idle mine activities, water operations, selling, general and administrative activities, income tax expense, as well as various other non-operated activities.

The Other division had a loss before income tax of $40 million for the three months ended September 30, 2017, compared to a loss before income tax of $81 million for the three months ended September 30, 2016. The Other division also includes total Company income tax expense related to continuing operations of $27 million for the three months ended September 30, 2017, compared to income tax expense of $53 million for the three months ended September 30, 2016.

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Other Outside Sales $ 17
$ 5
$ 12
240.0 %
Miscellaneous Other Income 9
11
(2 ) (18.2 )%
Gain on Sale of Assets 18
—
18
100.0 %
Total Revenue 44
16
28
175.0 %
Miscellaneous Operating Expense 36
40
(4 ) (10.0 )%
Selling, General, and Administrative Costs
3
5
(2 ) (40.0 )%
Depreciation, Depletion and Amortization 5
8
(3 ) (37.5 )%
Loss on Debt Extinguishment 2
—
2
100.00 %
Interest Expense 38
44
(6 ) (13.6 )%
Total Other Costs 84
97
(13 ) (13.4 )%
Loss Before Income Tax (40 ) (81 ) 41
(50.6 )%
Income Tax Expense 27
53
(26 ) (49.1 )%
Net Loss $ (67 ) $ (134 ) $ 67
(50.0 )%

~~Other Outside Sales~~

Other outside sales consists of sales from CNX Marine Terminal, which is located on 200 acres in the port of Baltimore and provides access to international coal markets. CNX Marine Terminal sales were $17 million for the three months ended September 30, 2017, compared to $5 million for the three months ended September 30, 2016. The $12 million increase in the period-to-period comparison was primarily due to ~~an increase~~higher unutilized processing fees and a decrease in ~~throughput tons~~utilization of firm transportation capacity in the current period.

~~Miscellaneous~~

Other ~~Income~~Expense


	For the Three Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Other Income

Right-of-Way Sales	$	—	$	1	$	(1)	(100.0)	%


Total Other Income	$	—	$	1	$	(1)	(100.0)	%

Other Expense

Professional Services	$	1	$	3	$	(2)	(66.7)	%
Bank Fees	3		3		—		—	%

Other Corporate Expense	1		1		—		—	%
Total Other Expense	$	5	$	7	$	(2)	(28.6)	%

Total Other Expense	$	5	$	6	$	(1)	(16.7)	%

Miscellaneous other income was $9 million for the three months ended September 30, 2017, compared to $11 million for the three months ended September 30, 2016. The change is due to the following items:

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Rental Income $ 2
$ 9
$ (7 )
Interest Income 1
—
1
Right of Way Sales 1
—
1
Royalty Income 4
2
2
Other Income 1
—
1
Total Miscellaneous Other Income $ 9
$ 11
$ (2 )

~~Rental Income~~•Professional services decreased ~~$7 million primarily due to a decrease in lease payments received as a result of the sale of certain subleased equipment in the second quarter of 2017.~~

~~Royalty Income related to non-operated coal properties~~ ~~increase~~d ~~$2 million~~ ~~in the period-to period comparison primarily due to an increase in third-party activity in the current period.~~

~~Gain on Sale of Assets~~

~~Gain on sale of assets increased $18 million~~ in the period-to-period comparison primarily due to a decrease in legal fees.

Gain on Asset Sales and Abandonments, net

A gain on asset sales of $6 million related to the sale of ~~approximately 22,000~~various non-core assets (primarily rights-of-way, surface ~~acres~~acreage and other non-core oil and gas interests) was recognized in ~~Colorado during~~ the three months ended ~~September~~June 30, ~~2017.~~2022 compared to a gain of $7 million in the three months ended June 30, 2021.

Loss on Debt Extinguishment

A loss on debt extinguishment of $13 million was recognized in the three months ended June 30, 2022 in connection with the purchase of a portion of the Convertible Notes due May 2026. See Note ~~3 - Acquisitions and Dispositions~~9 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. ~~No such transactions occurred in the prior period.~~

~~Miscellaneous Operating Expense~~

Miscellaneous operating expense related to the Other division was $36 million for the three months ended September 30, 2017, compared to $40 million for the three months ended September 30, 2016. Miscellaneous operating expense decreased in the period-to-period comparison due to the following items:

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Lease Rental Expense $ 1
$ 8
$ (7 )
Pension Settlement —
4
(4 )
Bank Fees 4
5
(1 )
UMWA Expenses 2
3
(1 )
Workers' Compensation 1
2
(1 )
UMWA OPEB Expense 11
11
—
CNX Marine Terminal 5
5
—
Closed and Idle Mines 2
2
—
Coal Reserve Holding Costs 2
1
1
Severance Payments 1
—
1
Pension Expense (2 ) (3 ) 1
Transaction Fees 6
—
6
Other 3
2
1
Miscellaneous Operating Expense $ 36

$ 40
$ (4 )

~~Lease Rental Expense decreased $7 million primarily due to the sale of certain subleased equipment in the second quarter of 2017.~~

Pension Settlement expense is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Settlement accounting was triggered in the three months ended September 30, 2016, primarily as a result of the sale of the Buchanan Mine in the first quarter of 2016 and the sale of the Fola and Miller Creek mining complexes in the third quarter of 2016. See Note 5 - Components of Pension and OPEB Plans Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail. Settlement accounting was not triggered in the current period.

~~Transaction Fees of $6 million are costs primarily associated with the separation of the E&P and PA Mining Operations divisions.~~

Other includes expenses related to the Company's water operations as well as miscellaneous corporate activity. The increase was due to various transactions that occurred throughout both periods, none of which were individually material.

~~Selling, General and Administrative Costs~~

Selling, general and administrative costs allocated to the Other division decreased $2 million in the period-to-period comparison. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders"~~of this quarterly report for more information.~~

~~Deprecation, Depletion and Amortization~~

~~Depreciation, depletion and amortization decreased $3 million in the period-to-period comparison due to changes in the asset retirement obligations at two of the Company's closed mine locations.~~

~~Loss on Debt Extinguishment~~

Loss on debt extinguishment of $2 million was recognized in the three months ended September 30, 2017 due to the redemption of the 8.25% senior notes due in April 2020 and the 6.375% senior notes due in March 2021. See Note 11 - Long-Term Debt in the Notes to the Audited Financial Statements in the Company's December 31, 2016 Form 10-K for additional information.

Interest Expense

~~Interest~~


	For the Three Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Total Interest Expense	$	31	$	39	$	(8)	(20.5)	%

The $8 million decrease in total interest expense was partially due to the Company adopting Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity on January 1, 2022. As part of ~~$38 million was recognized in~~the adoption, total interest expense no longer includes a non-cash interest expense component related to the Convertible Notes due May 2026. During the three months ended ~~September~~June 30, ~~2017, compared to $44~~2021, total interest expense included $4 million ~~in the three months ended September 30, 2016. The decrease of $6 million~~that was ~~primarily due~~amortized as additional non-cash interest expense related to the ~~Company's revolving credit facility having no outstanding borrowings during~~equity component of the ~~three months ended September 30, 2017, compared to $354 million of outstanding borrowings at September 30, 2016.~~Convertible Notes due May 2026. The decrease was also due to the ~~redemption~~purchase of the ~~2020 and 2021 senior notes~~$400 million 6.500% CNXM Senior Notes due March 2026 during the ~~three months~~year ended ~~September 30, 2017.~~

~~Income Taxes~~

~~The effective income tax rate for continuing operations when excluding noncontrolling interest was 8,441.0% for~~December 31, 2021 offset, in part, by the ~~three months~~$400 million of 4.750% CNXM Senior Notes due 2030 that were issued during the year ended September 30, 2017, compared to 46.7% for the three months ended September 30, 2016. The effective rates for the three months ended September 30, 2017 and 2016 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. The effective tax rate is different from the U.S. federal statutory rate of 35% primarily due to the income tax benefit for excess percentage depletion.December 31, 2021. See Note ~~7 - Income Taxes of~~9 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Income Taxes


	For the Three Months Ended June 30,
(in millions)	2022			2021			Variance			Percent Change
Total Company Income (Loss) Before Income Tax	$	47		$	(446)		$	493		110.5	%
Income Tax Expense (Benefit)	$	14		$	(92)		$	106		115.2	%
Effective Income Tax Rate	28.9		%	20.6		%	8.3		%

The effective income tax rate was 28.9% for the three months ended June 30, 2022 compared to 20.6% for the three months ended June 30, 2021. The effective rate for the three months ended June 30, 2022 differs from the U.S. federal statutory rate of 21% primarily due to the impact of the partial repurchase of the Convertible Notes, equity compensation and state income taxes. The effective rate for the three months ended June 30, 2021 differs from the U.S. federal statutory rate of 21% primarily due to the impact of 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).

For the Three Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Total Company Earnings Before Income Tax Excluding Noncontrolling Interest $ —
$ 113
$ (113 ) (100.0 )%
Income Tax Expense $ 27
$ 53
$ (26 ) (49.1 )%
Effective Income Tax Rate 8,441.0 % 46.7 % 8,394.3 %

Results of Operations - ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2022 Compared with ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2021

Net ~~Income (Loss) Attributable to CONSOL Energy Shareholders~~Loss

~~CONSOL Energy~~CNX reported ~~net income attributable to CONSOL Energy shareholders of $104 million, or earnings of $0.45 per diluted share, for the nine months ended September 30, 2017, compared to~~ a net loss ~~attributable to CONSOL Energy shareholders~~ of ~~$542~~$890 million, or a loss per diluted share of ~~$2.36,~~$4.52, for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~

For the Nine Months Ended September 30,
(Dollars in thousands) 2017 2016 Variance
Income (Loss) from Continuing Operations $ 114,671
$ (214,770 ) $ 329,441
Loss from Discontinued Operations, net —
(322,747 ) 322,747
Net Income (Loss) $ 114,671
$ (537,517 ) $ 652,188
Less: Net Income Attributable to Noncontrolling Interest 10,567
4,541
6,026
Net Income (Loss) Attributable to CONSOL Energy Shareholders $ 104,104
$ (542,058 ) $ 646,162

~~The E&P division had earnings before income tax of $154 million for the nine months ended September 30, 2017,~~2022, compared to a net loss ~~before income tax~~ of ~~$156~~$256 million, or a loss per diluted share of $1.16, for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~ 2021.

Included in the ~~2017 earnings before income tax~~loss for the six months ended June 30, 2022 was an unrealized ~~gain~~loss on commodity derivative instruments of ~~$142 million~~$1,578 million. Included in the loss for the six months ended June 30, 2021 was an unrealized loss on commodity derivative instruments of $497 million.

Non-GAAP Financial Measures

CNX's management uses certain non-GAAP financial measures for planning, forecasting and ~~gain on sale~~evaluating business and financial performance, and believes that they are useful for investors in analyzing the company. Although these are not measures of ~~assets~~performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of ~~$165 million~~Natural Gas, NGL and Oil, including cash settlements excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note ~~3 - Acquisitions and Dispositions~~13 – Segment Information in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). ~~Included~~These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in ~~the 2016 net loss before income tax was an unrealized loss on commodity derivative instruments~~accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of ~~$149 million~~other companies.

Non-GAAP Financial Measures Reconciliation


	For the Six Months Ended June 30,
(Dollars in millions)	2022		2021
Total Revenue and Other Operating (Loss) Income	$	(493)	$	346
Add (Deduct):
Purchased Gas Revenue	(92)		(50)
Loss on Commodity Derivative Instruments	1,578		497
Other Revenue and Operating Income	(46)		(50)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	947	$	743

Total Operating Expense	$	653	$	581
Add (Deduct):
Depreciation, Depletion and Amortization (DD&A) - Corporate	(7)		(6)
Exploration and Production Related Other Costs	(6)		(5)
Purchased Gas Costs	(91)		(47)


Selling, General and Administrative Costs	(62)		(52)
Other Operating Expense	(32)		(31)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	455	$	440

1 Natural Gas, NGL and ~~gain on sale~~Oil production costs consists primarily of ~~assets of $10 million.~~lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.

Selected Natural Gas, NGL and Oil Production Financial Data

The following table presents a ~~breakout~~summary of ~~net liquid~~our total sales volumes, sales of natural gas, NGL and oil including cash settlements, natural gas, NGL and oil production costs and natural gas, ~~sales information~~NGL and oil production margin related to ~~assist~~our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP):


	For the Six Months Ended June 30,
	2022				2021				Variance
	in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*			293.2				278.5				14.7

Natural Gas, NGL and Oil Revenue	$	1,748	$	6.14	$	751	$	2.70	$	997	$	3.44
Loss on Commodity Derivative Instruments - Cash Settlement - Gas	(801)		(2.91)		(8)		(0.03)		(793)		(2.88)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	947		3.23		743		2.67		204		0.56
Lease Operating Expense	30		0.10		20		0.07		10		0.03
Production, Ad Valorem, and Other Fees	20		0.07		13		0.05		7		0.02
Transportation, Gathering and Compression	177		0.60		161		0.58		16		0.02
Depreciation, Depletion and Amortization (DD&A)	228		0.78		246		0.88		(18)		(0.10)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure	455		1.55		440		1.58		15		(0.03)
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure	$	492	$	1.68	$	303	$	1.09	$	189	$	0.59

The 14.7 Bcfe increase in volumes in the ~~understanding of the Company’s natural gas production and sales portfolio.~~

For the Nine Months Ended September 30,
in thousands (unless noted) 2017 2016 Variance Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe) 26,527
31,020
(4,493 ) (14.5 )%
Sales Volume (Mbbls) 4,421
5,170
(749 ) (14.5 )%
Gross Price ($/Bbl) $ 21.30
$ 12.78
$ 8.52
66.7 %
Gross Revenue $ 94,139
$ 66,161
$ 27,978
42.3 %

Oil:
Sales Volume (MMcfe) 307
308
(1 ) (0.3 )%
Sales Volume (Mbbls) 51
51
—
(0.3 )%
Gross Price ($/Bbl) $ 45.30
$ 35.34
$ 9.96
28.2 %
Gross Revenue $ 2,321
$ 1,818
$ 503
27.7 %

Condensate:
Sales Volume (MMcfe) 2,070
4,263
(2,193 ) (51.4 )%
Sales Volume (Mbbls) 345
711
(366 ) (51.4 )%
Gross Price ($/Bbl) $ 36.24
$ 26.94
$ 9.30
34.5 %
Gross Revenue $ 12,495
$ 19,147
$ (6,652 ) (34.7 )%

GAS
Sales Volume (MMcf) 259,368
257,534
1,834
0.7 %
Sales Price ($/Mcf) $ 2.71
$ 1.82
$ 0.89
48.9 %
Gross Revenue $ 703,556
$ 468,399
$ 235,157
50.2 %

Hedging Impact ($/Mcf) $ (0.24 ) $ 0.79
$ (1.03 ) (130.4 )%
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement $ (61,717 ) $ 203,303
$ (265,020 ) (130.4 )%

The E&P division's natural gas, NGLs, and oil sales were $813 million for the nine months ended September 30, 2017, compared to $555 million for the nine months ended September 30, 2016. The increaseperiod-to-period comparison was primarily due to the ~~48.9% increase in~~turn-in-line of new wells throughout 2021 and the ~~average gas sales price per Mcf without the impact~~first half of ~~derivative instruments,~~2022. The increases were offset in part by ~~the 1.6% decrease in total E&P sales volumes.~~normal production declines.

~~The E&P division's sales volumes, average sales price (including the effects of derivative instruments), and average costs for all active E&P operations were as follows:~~

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
E&P Sales Volumes (Bcfe) 288.3
293.1
(4.8 ) (1.6 )%

Average Sales Price (per Mcfe) $ 2.60
$ 2.59
$ 0.01
0.4 %
Average Costs (per Mcfe) 2.25
2.35
(0.10 ) (4.3 )%
Average Margin $ 0.35
$ 0.24
$ 0.11
45.8 %

The increase in average sales price was primarily the result of a $0.89 Mcf improvement in general market prices in the Appalachian basin during the current period, as well as an overall increase in natural gas liquids pricing. The increase was offset, in part, by a $1.03 per Mcf decrease in the realized (loss) gain on commodity derivative instruments related to the Company's hedging program.

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

~~Depreciation, depletion and amortization decreased~~•Lease operating expense increased on a ~~per-unit~~per unit basis ~~primarily due to a reduction in Marcellus rates~~ as a result of an increase in ~~the Company's Marcellus reserves. See Note 9 - Property, Plant~~repairs and ~~Equipment~~maintenance expense and an increase in water disposal costs.

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

•Transportation, Gathering and Compression increased primarily due to ~~the Unaudited Consolidated Financial Statements~~an increase in ~~Item 1 of this Form 10-Q for additional information.~~gathering system repairs and maintenance expense and an increase in electrical compression expense.

~~Lease operating~~•Depreciation, depletion and amortization expense decreased on a per unit basis ~~in the period-to-period comparison~~ due to a ~~decrease in well tending costs~~lower annual depletion rate primarily resulting from low cost reserve additions from development during the 2021 period.

Average Realized Price Reconciliation

The following table presents a breakout of liquids and ~~salt water disposal costs, as well as a decrease in both Company operated~~natural gas sales information and ~~joint venture operated repairs and maintenance costs.~~

~~Transportation, gathering and compression expense increased on a per unit basis~~settled derivative information to assist in the ~~period-to-period comparison primarily due to an~~understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:


	For the Six Months Ended June 30,
in thousands (unless noted)	2022		2021		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	17,351		15,937		1,414		8.9	%
Sales Volume (Mbbls)	2,892		2,656		236		8.9	%
Gross Price ($/Bbl)	$	44.46	$	27.60	$	16.86	61.1	%
Gross NGL Revenue	$	128,570	$	73,384	$	55,186	75.2	%

Oil/Condensate:
Sales Volume (MMcfe)	698		1,091		(393)		(36.0)	%
Sales Volume (Mbbls)	116		182		(66)		(36.3)	%
Gross Price ($/Bbl)	$	86.46	$	49.11	$	37.35	76.1	%
Gross Oil/Condensate Revenue	$	10,060	$	8,932	$	1,128	12.6	%

NATURAL GAS
Sales Volume (MMcf)	275,144		261,515		13,629		5.2	%
Sales Price ($/Mcf)	$	5.85	$	2.56	$	3.29	128.5	%
Gross Natural Gas Revenue	$	1,609,401	$	668,358	$	941,043	140.8	%

Hedging Impact ($/Mcf)	$	(2.91)	$	(0.03)	$	(2.88)	(9,600.0)	%
Loss on Commodity Derivative Instruments - Cash Settlement	$	(801,233)	$	(7,954)	$	(793,279)	(9,973.3)	%

The increase in ~~wet~~gross revenue was primarily the result of the $3.29 per Mcf increase in natural gas ~~processing costs~~prices, when excluding the impact of hedging, the $16.86 per Bbl increase in NGL prices and the 14.7 Bcfe increase in sales volumes. These increases were offset, in-part, by the impact of the change in the realized loss on commodity derivative instruments related to ~~an increase in wet gas mix, as well as an increase in~~ the ~~CONE gathering rate offset, in part, by a decrease in firm transportation rates. See Note 17 - Related Party Transactions of~~Company's hedging program.

SEGMENT ANALYSIS for the ~~Notes~~six months ended June 30, 2022 compared to the ~~Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.~~six months ended June 30, 2021:


	For the Six Months Ended								Difference to Six Months Ended
	June 30, 2022								June 30, 2021
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total



Natural Gas, NGLs and Oil Revenue	$	1,604	$	143	$	1	$	1,748	$	929	$	68	$	—	$	997
Loss on Commodity Derivative Instruments	(738)		(63)		(1,578)		(2,379)		(731)		(62)		(1,081)		(1,874)
Purchased Gas Revenue	—		—		92		92		—		—		42		42
Other Revenue and Operating Income	35		—		11		46		(3)		—		(1)		(4)

Total Revenue and Other Operating Income (Loss)	901		80		(1,474)		(493)		195		6		(1,040)		(839)
Lease Operating Expense	22		8		—		30		9		2		(1)		10
Production, Ad Valorem, and Other Fees	15		5		—		20		4		3		—		7
Transportation, Gathering and Compression	153		23		1		177		10		5		1		16
Depreciation, Depletion and Amortization	197		26		12		235		(17)		(4)		4		(17)


Exploration and Production Related Other Costs	—		—		6		6		—		—		1		1
Purchased Gas Costs	—		—		91		91		—		—		44		44
Selling, General and Administrative Costs	—		—		62		62		—		—		10		10
Other Operating Expense	—		—		32		32		—		—		1		1
Total Operating Expense	387		62		204		653		6		6		60		72
Other Expense	—		—		5		5		—		—		(5)		(5)
Gain on Asset Sales and Abandonments, net	—		—		(20)		(20)		—		—		(10)		(10)
Loss on Debt Extinguishment	—		—		13		13		—		—		13		13
Interest Expense	—		—		58		58		—		—		(18)		(18)
Total Other Expense	—		—		56		56		—		—		(20)		(20)
Total Costs and Expenses	387		62		260		709		6		6		40		52
Earnings (Loss) Before Income Tax	$	514	$	18	$	(1,734)	$	(1,202)	$	189	$	—	$	(1,080)	$	(891)

SHALE SEGMENT

The ~~PA Mining Operations division~~Shale segment had earnings before income tax of ~~$132~~$514 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2022 compared to earnings before income tax of ~~$80~~$325 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021.

~~Sales tons, average sales price and average cost of goods sold per ton for the PA Mining Operations division were as follows:~~

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
Company Produced PA Mining Operations Tons Sold (in millions) 19.9
17.5
2.4
13.7 %

Average Sales Price per ton sold $ 45.26
$ 42.60
$ 2.66
6.2 %
Average Cost of Goods Sold per ton sold 35.51
34.53
0.98
2.8 %
Average Margin $ 9.75
$ 8.07
$ 1.68
20.8 %

The increase in overall tons sold was primarily due to increased demand from the Company's domestic power plant customers, in part due to higher natural gas prices. The higher average sales price per ton sold in the 2017 period was primarily the result of a tighter supply-demand balance in the international thermal and crossover metallurgical coal markets that the PA Mining Operations complex serves.

The PA Mining Operations division priced 5.9 million tons on the export market for the nine months ended September 30, 2017, compared to 4.2 million tons for the nine months ended September 30, 2016. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily driven by: an increase in production tons to meet market demand; the timing of certain belt and maintenance projects; additional operating expenses incurred at the Bailey Mine resulting from permitting issues; and adverse geological conditions at the Enlow Fork Mine.

The Other division includes other business activities not assigned to the E&P or PA Mining Operations divisions, as well as any income tax benefit or expense. The Other division had a net loss of $171 million for the nine months ended September 30, 2017, compared to a net loss of $139 million for the nine months ended September 30, 2016.

SG&A costs are excluded from E&P and PA Mining Operations unit costs. SG&A costs were $122 million for the nine months ended September 30, 2017, compared to $105 million for the nine months ended September 30, 2016. SG&A costs increased due to the following items:

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Short-Term Incentive Compensation $ 18
$ 12
$ 6
50.0 %
Stock-Based Compensation 28
24
4
16.7 %
Consulting and Professional Services 14
11
3
27.3 %
Employee Wages and Related Expenses 41
41
—
— %
Rent 6
6
—
— %
Advertising and Promotion 1
4
(3 ) (75.0 )%
Other 14
7
7
100.0 %
Total Company Selling, General and Administrative Costs

$ 122
$ 105
$ 17
16.2 %

~~The increase in Short-Term Incentive Compensation was a result of higher anticipated payouts in the current period, primarily related to the PA Mining Operations division.~~

~~Stock-Based Compensation expense increased~~ ~~$4 million~~ ~~in the period-to-period comparison primarily due to additional non-cash amortization recorded in the current period for employees who received awards under the Performance Share Unit (PSU) program.~~

~~The increase in Consulting and Professional Services was primarily due to an increase in legal fees in the period-to-period comparison.~~

The increase in Other was primarily due to a credit of $5 million related to the portion of Total Company SG&A that was allocated to discontinued operations in the nine months ended September 30, 2016. No such transactions occurred in the current period.

Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers' compensation, Coal Workers' Pneumoconiosis (CWP) and long-term disability are actuarially calculated for the Company as a whole. In general, the expenses are then allocated to the segments based upon criteria specific to each liability. Total CONSOL Energy continuing operations expense related to actuarial liabilities was $41 million for the nine months ended September 30, 2017, compared to $57 million for the nine months ended September 30, 2016. See Note 14 - Pension and Other Postretirement Benefits Plans and Note 15 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of the Company's December 31, 2016 Form 10-K, and Note 5 - Components of Pension and OPEB Plans Net Periodic Benefit Costs and Note 6 - Components of CWP and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details.

~~TOTAL E&P DIVISION ANALYSIS for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016:~~

The E&P division had earnings before income tax of $154 million for the nine months ended September 30, 2017 compared to a loss before income tax of $156 million for the nine months ended September 30, 2016. Variances by individual E&P segment are discussed below.

For the Nine Months Ended Difference to Nine Months Ended
September 30, 2017 September 30, 2016
(in millions) Marcellus Utica CBM
Other
Gas
Total E&P Marcellus Utica CBM
Other
Gas

Total
E&P
Natural Gas, NGLs and Oil Sales $ 477
$ 136
$ 157
$ 43
$ 813
$ 190
$ 21
$ 34
$ 13
$ 258
(Loss) Gain on Commodity Derivative Instruments (43 ) (2 ) (13 ) 138
80
(164 ) (27 ) (57 ) 274
26
Purchased Gas Sales —
—
—
33
33
—
—
—
4
4
Miscellaneous Other Income —
—
—
52
52
—
—
—
(9 ) (9 )
Gain on Sale of Assets —
—
—
165
165
—
—
—
155
155
Total Revenue and Other Income 434
134
144
431
1,143
26
(6 ) (23 ) 437
434
Lease Operating Expense 23
14
19
8
64
(4 ) (3 ) 1
(4 ) (10 )
Production, Ad Valorem, and Other Fees 9
3
6
2
20
(4 ) (1 ) 2
(1 ) (4 )
Transportation, Gathering and Compression 184
33
49
14
280
13
(4 ) (5 ) (4 ) —
Depreciation, Depletion and Amortization 159
50
61
18
288
5
(14 ) (5 ) (9 ) (23 )
Exploration and Production Related Other Costs —
—
—
34
34
—
—
—
29
29
Purchased Gas Costs —
—
—
32
32
—
—
—
3
3
Other Corporate Expenses —
—
—
68
68
—
—
—
2
2
Impairment of Exploration and Production Properties —
—
—
138
138
—
—
—
138
138
Selling, General and Administrative Costs

—
—
—
63
63
—
—
—
(11 ) (11 )
Total Exploration and Production Costs 375
100
135
377
987
10
(22 ) (7 ) 143
124
Interest Expense —
—
—
2
2
—
—
—
—
—
Total E&P Division Costs 375
100
135
379
989
10
(22 ) (7 ) 143
124
Earnings (Loss) Before Income Tax $ 59
$ 34
$ 9
$ 52
$ 154
$ 16
$ 16
$ (16 ) $ 294
$ 310

~~MARCELLUS SEGMENT~~

The Marcellus segment had earnings before income tax of $59 million for the nine months ended September 30, 2017 compared to earnings before income tax of $43 million for the nine months ended September 30, 2016.

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
Marcellus Gas Sales Volumes (Bcf) 156.1
135.3
20.8
15.4 %
NGLs Sales Volumes (Bcfe)* 18.1
18.7
(0.6 ) (3.2 )%
Condensate Sales Volumes (Bcfe)* 1.2
2.0
(0.8 ) (40.0 )%
Total Marcellus Sales Volumes (Bcfe)* 175.4
156.0
19.4
12.4 %

Average Sales Price - Gas (per Mcf) $ 2.62
$ 1.79
$ 0.83
46.4 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ (0.27 ) $ 0.89
$ (1.16 ) (130.3 )%
Average Sales Price - NGLs (per Mcfe)* $ 3.35
$ 1.99
$ 1.36
68.3 %
Average Sales Price - Condensate (per Mcfe)* $ 5.87
$ 4.18
$ 1.69
40.4 %

Total Average Marcellus Sales Price (per Mcfe) $ 2.48
$ 2.62
$ (0.14 ) (5.3 )%
Average Marcellus Lease Operating Expenses (per Mcfe) 0.13
0.17
(0.04 ) (23.5 )%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe) 0.05
0.09
(0.04 ) (44.4 )%
Average Marcellus Transportation, Gathering and Compression costs (per Mcfe) 1.05
1.10
(0.05 ) (4.5 )%
Average Marcellus Depreciation, Depletion and Amortization costs (per Mcfe) 0.92
0.98
(0.06 ) (6.1 )%
Total Average Marcellus Costs (per Mcfe) $ 2.15
$ 2.34
$ (0.19 ) (8.1 )%
Average Margin for Marcellus (per Mcfe) $ 0.33
$ 0.28
$ 0.05
17.9 %


	For the Six Months Ended June 30,
	2022		2021		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	252.6		236.1		16.5		7.0	%
NGLs Sales Volumes (Bcfe)*	17.3		15.9		1.4		8.8	%
Oil/Condensate Sales Volumes (Bcfe)*	0.7		1.1		(0.4)		(36.4)	%
Total Shale Sales Volumes (Bcfe)*	270.6		253.1		17.5		6.9	%

Average Sales Price - Natural Gas (per Mcf)	$	5.80	$	2.51	$	3.29	131.1	%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(2.92)	$	(0.03)	$	(2.89)	(9,633.3)	%
Average Sales Price - NGLs (per Mcfe)*	$	7.41	$	4.60	$	2.81	61.1	%
Average Sales Price - Oil/Condensate (per Mcfe)*	$	14.40	$	8.18	$	6.22	76.0	%

Total Average Shale Sales Price (per Mcfe)	$	3.20	$	2.64	$	0.56	21.2	%
Average Shale Lease Operating Expenses (per Mcfe)	0.08		0.05		0.03		60.0	%
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)	0.05		0.05		—		—	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.57		0.56		0.01		1.8	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.73		0.85		(0.12)		(14.1)	%
Total Average Shale Production Costs (per Mcfe)	$	1.43	$	1.51	$	(0.08)	(5.3)	%
Total Average Shale Production Margin (per Mcfe)	$	1.77	$	1.13	$	0.64	56.6	%

* 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.

The ~~Marcellus~~Shale segment had natural gas, NGLs and ~~oil sales~~oil/condensate revenue of ~~$477~~$1,604 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$287~~$675 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. The ~~$190~~$929 million increase was due primarily to a 131.1% increase in the average sales price for natural gas, a 6.9% increase in total Shale sales volumes, and a 61.1% increase in the average sales price of NGLs. The increase in total Shale volumes was primarily due to the turn-in-line of new wells throughout 2021 and the first half of 2022, offset in part by normal production declines.

The increase in total average Shale sales price was primarily due to a $3.29 per Mcf increase in average natural gas sales price and a $2.81 per Mcfe increase in the average NGL sales price. These increases were offset in part by a $2.89 per Mcf change in the realized loss on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 212.6 Bcf of the Company's produced Shale gas sales volumes for the six months ended June 30, 2022 at an average loss of $3.47 per Mcf hedged. For the six months ended June 30, 2021, these financial hedges represented approximately 209.4 Bcf at an average loss of $0.03 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $387 million for the six months ended June 30, 2022 compared to $381 million for the six months ended June 30, 2021. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $22 million for the six months ended June 30, 2022 compared to $13 million for the six months ended June 30, 2021. The increases in total dollars and unit costs were primarily related to an increase in repairs and maintenance expense and an increase in water disposal costs.

•Shale production, ad valorem and other fees were $15 million for the six months ended June 30, 2022 compared to $11 million for the six months ended June 30, 2021. The increase in total dollars was primarily due to increased realized prices on natural gas and natural gas liquids.

•Shale transportation, gathering and compression costs were $153 million for the six months ended June 30, 2022 compared to $143 million for the six months ended June 30, 2021. The increase in total dollars was primarily related to an increase in total volumes gathered as well as an increase in gathering systems repairs and maintenance expense.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $197 million for the six months ended June 30, 2022 compared to $214 million for the six months ended June 30, 2021. These amounts included depletion on a unit of production basis of $0.63 per Mcfe and $0.74 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a lower annual depletion rate related to low-cost reserve additions from development in the 2021 period. 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 $35 million for the six months ended June 30, 2022 compared to $38 million for the six months ended June 30, 2021. The decrease in the period-to-period comparison was primarily due to lower third-party gathering volumes due to normal production declines.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $18 million for the both the six months ended June 30, 2022 and June 30, 2021.


	For the Six Months Ended June 30,
	2022		2021		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	22.5		25.3		(2.8)		(11.1)	%

Average Sales Price - Natural Gas (per Mcf)	$	6.37	$	2.98	$	3.39	113.8	%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(2.78)	$	(0.03)	$	(2.75)	(9,166.7)	%

Total Average CBM Sales Price (per Mcf)	$	3.58	$	2.95	$	0.63	21.4	%
Average CBM Lease Operating Expenses (per Mcf)	0.36		0.24		0.12		50.0	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.23		0.10		0.13		130.0	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	1.01		0.72		0.29		40.3	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.16		1.18		(0.02)		(1.7)	%
Total Average CBM Production Costs (per Mcf)	$	2.76	$	2.24	$	0.52	23.2	%
Total Average CBM Production Margin (per Mcf)	$	0.82	$	0.71	$	0.11	15.5	%

The CBM segment had natural gas revenue of $143 million for the six months ended June 30, 2022 compared to $75 million for the six months ended June 30, 2021. The $68 million increase was primarily due to a ~~46.4%~~113.8% increase in the average sales price for natural gas in the current period. The natural gas price increases were partially offset by the 11.1% decrease in CBM sales volumes due to normal production declines.

The total average CBM sales price increased $0.63 per Mcf due to a $3.39 per Mcf increase in average natural gas sales price, ~~as well as~~offset in part by a ~~12.4% increase in total Marcellus sales volumes. The increase in sales volumes was primarily due to the termination of the Marcellus Joint Venture with Noble Energy~~$2.75 per Mcf change in the fourth quarter of 2016, which resulted in each party owning and operating a 100% interest in certain wells in two separate operating areas (see Note 9 - Property, Plant and Equipment in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details) as well as additional wells being turned in line in the current period.

~~The decrease in the total average Marcellus sales price was primarily due to a $1.16 per Mcf decrease in the (loss) gain~~realized loss on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately ~~152.2~~18.0 Bcf of the Company's produced ~~Marcellus gas~~CBM sales volumes for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 at an average loss of ~~$0.28~~$3.46 per ~~Mcf.~~Mcf hedged. For the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2021, these financial hedges represented approximately ~~120.5~~21.5 Bcf at an average ~~gain~~loss of ~~$1.00~~$0.03 per ~~Mcf.~~Mcf hedged.

Total ~~exploration~~operating costs and ~~production costs~~expenses for the ~~Marcellus~~CBM segment were ~~$375~~$62 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$365~~$56 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. The ~~increase~~increases in total dollars and ~~decrease in~~ unit costs for the ~~Marcellus~~CBM segment were due to the following items:

•~~Marcellus~~CBM lease operating expense was ~~$23~~$8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$27~~$6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. The ~~decrease~~increases in total dollars ~~was~~and unit costs were primarily due to ~~a reduction of salt water disposal, well tending~~increases in repairs and ~~equipment rental expense in the current period. The decrease in unit costs was due to the decrease in total dollars, as well as the 12.4% increase in total Marcellus sales volumes.~~maintenance expense.

•~~Marcellus~~CBM production, ad valorem and other fees were $9$5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$13~~$2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. The ~~decrease~~increases in total dollars ~~was~~and unit costs were primarily due to ~~a change in production mix by state as a result of the termination of the Marcellus joint venture with Noble Energy, offset, in part, by the~~increased realized prices on natural gas.

~~increase in average gas sales price. The decrease in unit costs was due to the decrease in total dollars described above, as well as 12.4% increase in total Marcellus sales volumes.~~

•~~Marcellus~~CBM transportation, gathering and compression costs were ~~$184~~$23 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$171~~$18 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. The ~~increase~~increases in total dollars was primarily related to an increase in CONE gathering fees due to the 15.4% increase in Marcellus gas sales volumes (See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) offset, in part, by a decrease in firm transportation expense due to a decrease in rates. The decrease inand unit costs ~~was~~were primarily due to ~~the reduction~~increases in ~~firm transportation rates.~~repairs and maintenance expense and electrical compression expense.

•Depreciation, depletion and amortization costs attributable to the ~~Marcellus~~CBM segment were ~~$159~~$26 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$154~~$30 million for the ~~nine~~six months ended ~~September~~June 30, 2016. The period-to-period increase in total dollars was driven primarily by the increase in production. The increase was offset, in part, by a decrease in overall Marcellus rates primarily due to an increase in the Company's Marcellus reserves following the joint venture termination in the fourth quarter of 2016.2021. These amounts included depletion on a unit of production basis of ~~$0.90~~$0.64 per Mcfe and ~~$0.97~~$0.66 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate was due to a lower annual depletion rate. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to ~~gas well closing.~~asset retirement obligations.

~~UTICA~~OTHER SEGMENT

The Utica segment had earnings before income tax of $34 million for the nine months ended September 30, 2017 compared to earnings before income tax of $18 million for the nine months ended September 30, 2016.

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
Utica Gas Sales Volumes (Bcf) 39.8
54.0
(14.2 ) (26.3 )%
NGLs Sales Volumes (Bcfe)* 8.4
12.3
(3.9 ) (31.7 )%
Oil Sales Volumes (Bcfe)* 0.1
—
0.1
100.0 %
Condensate Sales Volumes (Bcfe)* 0.9
2.3
(1.4 ) (60.9 )%
Total Utica Sales Volumes (Bcfe)* 49.2
68.6
(19.4 ) (28.3 )%

Average Sales Price - Gas (per Mcf) $ 2.43
$ 1.40
$ 1.03
73.6 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ (0.06 ) $ 0.46
$ (0.52 ) (113.0 )%
Average Sales Price - NGLs (per Mcfe)* $ 3.96
$ 2.35
$ 1.61
68.5 %
Average Sales Price - Oil (per Mcfe)* $ 7.41
$ —
$ 7.41
100.0 %
Average Sales Price - Condensate (per Mcfe)* $ 6.25
$ 4.77
$ 1.48
31.0 %

Total Average Utica Sales Price (per Mcfe) $ 2.73
$ 2.04
$ 0.69
33.8 %
Average Utica Lease Operating Expenses (per Mcfe) 0.28
0.25
0.03
12.0 %
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe) 0.06
0.05
0.01
20.0 %
Average Utica Transportation, Gathering and Compression Costs (per Mcfe) 0.68
0.54
0.14
25.9 %
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe) 1.02
0.94
0.08
8.5 %
Total Average Utica Costs (per Mcfe) $ 2.04
$ 1.78
$ 0.26
14.6 %
Average Margin for Utica (per Mcfe) $ 0.69
$ 0.26
$ 0.43
165.4 %

The Utica segment had natural gas, NGLs and oil sales of $136 million for the nine months ended September 30, 2017 compared to $115 million for the nine months ended September 30, 2016. The $21 million increase was primarily duesignificant to the 73.6% increase in average gas sales price, offset, in part, by the 28.3% decrease in total Utica sales volumes. The decrease in total Utica sales volumes primarily related to normal well declines in both Company operated and joint venture operated areas, as well as temporary shut-ins for additional drilling and maintenance.

The increase in the total average Utica sales price was primarily due to a $1.03 per Mcf increase in average gas sales price, offset, in part, by a $0.52 per Mcf decrease in the (loss) gain on commodity derivative instruments in the current period. The notional amounts associated with these financial hedges represented approximately 19.3 Bcf ofCompany. It also includes the Company's produced Utica gas sales volumes for the nine months ended September 30, 2017 at an average loss of $0.11 per Mcf. For the nine months ended September 30, 2016, these financial hedges represented approximately 24.6 Bcf at an average gain of $1.00 per Mcf.

Total exploration and production costs for the Utica segment were $100 million for the nine months ended September 30, 2017 compared to $122 million for the nine months ended September 30, 2016. 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 $14 million for the nine months ended September 30, 2017 compared to $17 million for the nine months ended September 30, 2016. The decrease in total dollars was primarily due to a decrease in well tending costs as well as a decrease in both Company operated and joint venture operated repairs and maintenance costs. The increase in unit costs was due to the 28.3% decrease in total Utica sales volumes, offset, in part, by the decrease in total dollars described above.

•Utica production, ad valorem, and other fees were $3 million for the nine months ended September 30, 2017 compared to $4 million for the nine months ended September 30, 2016. The decrease in total dollars was primarily due to an adjustment that was made in the current year related to the Company's proportionate share of ad valorem taxes in our joint venture partners operated area. The increase in unit costs was primarily due to the 28.3% decrease in total Utica sales volumes, offset, in part, by the decrease in total dollars described above.

•Utica transportation, gathering and compression costs were $33 million for the nine months ended September 30, 2017 compared to $37 million for the nine months ended September 30, 2016. The $4 million decrease in total dollars was primarily related to a decrease in utilized firm transportation expense, as well as the shift to lower cost dry Utica. The increase in unit costs was due to an increase in processing rates in our joint venture partners operated area.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $50 million for the nine months ended September 30, 2017 compared to $64 million for the nine months ended September 30, 2016. These amounts included depletion on a unit of production basis of $1.01 per Mcf and $0.93 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

~~COALBED METHANE (CBM) SEGMENT~~

The CBM segment had earnings before income tax of $9 million for the nine months ended September 30, 2017 compared to earnings before income tax of $25 million for the nine months ended September 30, 2016.

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
CBM Gas Sales Volumes (Bcf) 49.4
51.6
(2.2 ) (4.3 )%

Average Sales Price - Gas (per Mcf) $ 3.19
$ 2.38
$ 0.81
34.0 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ (0.26 ) $ 0.85
$ (1.11 ) (130.6 )%

Total Average CBM Sales Price (per Mcf) $ 2.93
$ 3.23
$ (0.30 ) (9.3 )%
Average CBM Lease Operating Expenses (per Mcf) 0.38
0.36
0.02
5.6 %
Average CBM Production, Ad Valorem, and Other Fees (per Mcf) 0.11
0.09
0.02
22.2 %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) 0.99
1.05
(0.06 ) (5.7 )%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.27
1.25
0.02
1.6 %
Total Average CBM Costs (per Mcf) $ 2.75
$ 2.75
$ —
— %
Average Margin for CBM (per Mcf) $ 0.18
$ 0.48
$ (0.30 ) (62.5 )%

The CBM segment had natural gas sales of $157 million in the nine months ended September 30, 2017 compared to $123 million for the nine months ended September 30, 2016. The $34 million increase was primarily due to a 34.0% increase in the

~~average gas sales price per Mcf, offset, in part, by a 4.3% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal well declines and less drilling activity.~~

The total average CBM sales price decreased $0.30 per Mcf due primarily to a $1.11 per Mcf decrease in the (loss) gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 44.8 Bcf of the Company's produced CBM sales volumes for the nine months ended September 30, 2017 at an average loss of $0.28 per Mcf. For the nine months ended September 30, 2016, these financial hedges represented approximately 42.3 Bcf at an average gain of $1.04 per Mcf.

Total exploration and production costs for the CBM segment were $135 million for the nine months ended September 30, 2017 compared to $142 million for the nine months ended September 30, 2016. Unit costs remained consistent in the period-to-period comparison at $2.75 per Mcf. The decrease in total dollars was due to the following items:

•CBM lease operating expense was $19 million for the nine months ended September 30, 2017 compared to $18 million for the nine months ended September 30, 2016. The increase in total dollars was primarily related to an increase in water disposal costs and joint venture partner billings. Unit costs increased in the current period, due to both the increase in total dollars and the decrease in CBM sales volumes.

•CBM production, ad valorem, and other fees were $6 million for the nine months ended September 30, 2017 compared to $4 million for the nine months ended September 30, 2016. The increase in total dollars was primarily related to the increase in average sales price. Unit costs increased in the current period, due to both the increase in total dollars and the decrease in CBM sales volumes.

•CBM transportation, gathering and compression costs were $49 million for the nine months ended September 30, 2017 compared to $54 million for the nine months ended September 30, 2016. The $5 million decrease was primarily related to lower employee-related costs, a decrease in power expense related to an effort to minimize the number of compressors needed and a decrease in utilized firm transportation expense resulting from the decrease in CBM sales volumes. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM sales volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $61 million for the nine months ended September 30, 2017 compared to $66 million for the nine months ended September 30, 2016. These amounts included depletion on a unit of production basis of $0.78 per Mcf and $0.82 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to gas well closing.

~~OTHER GAS SEGMENT~~

The Other Gas segment had earnings before income tax of $52 million for the nine months ended September 30, 2017 compared to a loss before income tax of $242 million for the nine months ended September 30, 2016.

For the Nine Months Ended September 30,
2017 2016 Variance Percent
Change
Other Gas Sales Volumes (Bcf) 14.1
16.6
(2.5 ) (15.1 )%
Oil Sales Volumes (Bcfe)* 0.2
0.3
(0.1 ) (33.3 )%
Total Other Sales Volumes (Bcfe)* 14.3
16.9
(2.6 ) (15.4 )%

Average Sales Price - Gas (per Mcf) $ 2.83
$ 1.68
$ 1.15
68.5 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ (0.26 ) $ 0.84
$ (1.10 ) (131.0 )%
Average Sales Price - Oil (per Mcfe)* $ 7.64
$ 5.99
$ 1.65
27.5 %

Total Average Other Sales Price (per Mcfe) $ 2.63
$ 2.58
$ 0.05
1.9 %
Average Other Lease Operating Expenses (per Mcfe) 0.62
0.65
(0.03 ) (4.6 )%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe) 0.14
0.13
0.01
7.7 %
Average Other Transportation, Gathering and Compression Costs (per Mcfe) 0.93
1.03
(0.10 ) (9.7 )%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe) 1.03
1.62
(0.59 ) (36.4 )%
Total Average Other Costs (per Mcfe) $ 2.72
$ 3.43
$ (0.71 ) (20.7 )%
Average Margin for Other (per Mcfe) $ (0.09 ) $ (0.85 ) $ 0.76
89.4 %

The Other Segment had a ~~specific E&P segment.~~

~~Other Gas sales volumes are primarily related to shallow oil and gas production. Natural gas, NGLs and oil sales related to the Other Gas segment were $43~~loss before income tax of $1,734 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$30~~a loss before income tax of $654 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. The ~~increase~~decrease in ~~natural gas, NGLs and oil sales primarily related to~~total dollars is discussed below.


	For the Six Months Ended June 30,
	2022	2021	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.1	0.1	—	—	%

Loss on Commodity Derivative Instruments

For the ~~$1.15 per Mcf increase in the average gas sales price. Total exploration and production costs related to these other sales were $42 million for the nine~~six months ended ~~September~~June 30, ~~2017 compared to $60 million for~~2022, the nine months ended September 30, 2016. The decrease was primarily due to a decrease in depreciation, depletion and amortization costs as a result of certain assets becoming fully depreciated in the current period, as well as the sale of Knox Energy in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

~~The~~ Other ~~Gas segment~~Segment recognized ~~an unrealized gain on commodity derivative instruments of $142 million for the nine months ended September 30, 2017 compared to~~ an unrealized loss on commodity derivative instruments of ~~$149 million for~~$1,578 million. For the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021, the Other Segment recognized an unrealized loss on commodity derivative instruments of $497 million. The unrealized ~~gain/~~loss or 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. ~~In addition, the Other~~

Purchased Gas segment had a realized loss of $4 million for the nine months ended September 30, 2017 compared to a realized gain of $13 million for the nine months ended September 30, 2016 related to the cash settlement of commodity hedges.

Purchased gas volumes represent volumes of natural gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain ~~customers.~~customers and to balance supply. Purchased gas ~~sales revenues were $33~~revenue was $92 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$29~~$50 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. Purchased gas costs were ~~$32~~$91 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~$29~~$47 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
Purchased Gas Sales Volumes (in Bcfe) 12.8
15.7
(2.9 ) (18.5 )%
Average Sales Price (per Mcfe) $ 2.55
$ 1.82
$ 0.73
40.1 %
Average Cost (per Mcfe) $ 2.52
$ 1.82
$ 0.70
38.5 %

~~Miscellaneous other income was $52 million for the nine months ended September 30, 2017 compared to $61 million for the nine months ended September 30, 2016.~~2021. The ~~$9 million decrease~~period-to-period increase in purchased gas revenue was due to ~~the following items:~~an increase in averages sales price, offset in part by a decrease in purchased gas sales volumes.


	For the Six Months Ended June 30,
	2022		2021		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	15.3		16.7		(1.4)		(8.4)	%
Average Sales Price (per Mcf)	$	6.03	$	3.01	$	3.02	100.3	%
Purchased Gas Average Cost (per Mcf)	$	5.93	$	2.81	$	3.12	111.0	%

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance Percent
Change
Right of Way Sales $ 1
$ 11
$ (10 ) (90.9 )%
Equity in Earnings of Affiliates 35
41
(6 ) (14.6 )%
Gathering Revenue 8
8
—
— %
Other 8
1
7
700.0 %
Total Miscellaneous Other Income $ 52
$ 61
$ (9 ) (14.8 )%
Other Operating Income


	For the Six Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Water Income	$	3	$	4	$	(1)	(25.0)	%
Excess Firm Transportation Income	6		6		—		—	%
Equity Income from Affiliates	2		2		—		—	%

Total Other Operating Income	$	11	$	12	$	(1)	(8.3)	%

~~Right of Way Sales relate to an initiative to generate additional~~

•Excess firm transportation income represents revenue from the ~~Company's~~sale of excess firm transportation capacity to third-parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized ~~surface rights.~~firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The ~~decrease~~revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in ~~the period to period comparison was due to a decrease in sales.~~Total Other Operating Expense.

•Equity ~~in Earnings~~income from affiliates primarily consists of ~~Affiliates decreased $6 million due to a decrease in~~CNX's share of earnings from ~~CONE Midstream Partners, LP and CONE Gathering, LLC. See Note 17 - Related Party Transactions~~a 50% interest in a power plant located within CNX’s CBM field. Power generated from the facility is sold into wholesale electricity markets during times of ~~the Notes~~peak energy consumption. Due to the ~~Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q~~plant consuming low carbon intensity coal mine methane gas, the plant qualifies for ~~additional information.~~Pennsylvania Tier I Renewable Energy Credits.

Gain on sale of assets was a gain of $165 million for the nine months ended September 30, 2017 compared to a gain of $10 million for the nine months ended September 30, 2016. The $155 million increase was primarily due to the sale of approximately 6,300 net undeveloped acres in Ohio and the sale of approximately 11,100 net undeveloped acres in Pennsylvania in the current period. See Note 3 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Exploration and ~~production related other costs were $34 million~~Production Related Other Costs


	For the Six Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Seismic Activity	$	3	$	—	$	3	100.0	%
Land Rentals	$	2	$	1	$	1	100.0	%
Permitting Expense	$	—	$	1	$	(1)	(100.0)	%
Lease Expiration Costs	1		3		(2)		(66.7)	%

Total Exploration and Production Related Other Costs	$	6	$	5	$	1	20.0	%

•Seismic activity expense for the ~~nine months ended September 30, 2017 compared to $5 million for the nine months ended September 30, 2016. The $29 million increase is due~~current period primarily relates to the ~~following items:~~acquisition of three-dimensional seismic data.

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Lease Expiration Costs $ 30
$ 1
$ 29
2,900.0 %
Land Rentals 3
2
1
50.0 %
Permitting Expense 1
—
1
100.0 %
Other —
2
(2 ) (100.0 )%
Total Exploration and Other Costs $ 34
$ 5
$ 29
580.0 %

•Lease ~~Expiration Costs~~expiration costs relate to leases where the primary term ~~expired. The $29 million increase in~~expired or will expire within the ~~nine months ended September 30, 2017 was primarily due to leases in Monroe County~~next 12 months.

Selling, General and ~~Noble County, Ohio that were no longer in the Company's future drilling plans so they were not renewed.~~Administrative ("SG&A")


	For the Six Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Contributions and Advertising	$	4	$	1	$	3	300.0	%
Short-Term Incentive Compensation	7		5		2		40.0	%
Salaries, Wages and Employee Benefits	15		13		2		15.4	%
Long-Term Equity-Based Compensation (Non-Cash)	11		11		—		—	%
Other	25		22		3		13.6	%
Total SG&A	$	62	$	52	$	10	19.2	%

~~Other corporate expenses were $68 million for the nine months ended September 30, 2017 compared to $66 million for the nine months ended September 30, 2016. The $2 million increase~~•Contributions and advertising increased in the period-to-period comparison ~~was made up of~~primarily due to an increase in charitable contributions.

•Short-term incentive compensation increased in the ~~following items:~~period-to-period comparison primarily due to an increase in expected payout.

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

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

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Unutilized Firm Transportation and Processing Fees $ 38
$ 25
$ 13
52.0 %
Litigation Expense 3
3
—
— %
Insurance Expense 2
2
—
— %
Severance Expense 1
1
—
— %
Idle Rig Fees 16
27
(11 ) (40.7 )%
Other 8
8
—
— %
Total Other Corporate Expenses $ 68
$ 66
$ 2
3.0 %
Other Operating Expense


	For the Six Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Litigation Settlements	$	3	$	—	$	3	100.0	%

Insurance Expense	1		1		—		—	%

Unutilized Firm Transportation and Processing Fees	27		28		(1)		(3.6)	%

Other	1		2		(1)		(50.0)	%
Total Other Operating Expense	$	32	$	31	$	1	3.2	%

~~Idle Rig Fees are fees related to the temporary idling of some of the Company's natural gas rigs.~~ The total idle rig expense incurred by the Company has decreased by $11 million for the current period as compared to the prior year period due to an increase in drilling activity as a direct result of the recovery in natural gas pricing.

Impairment of Exploration and Production Properties of $138 million for the nine months ended September 30, 2017 related to an impairment in the carrying value of Knox Energy in the second quarter of 2017 (see Note 9 - Property Plant and Equipment of the Notes to the Audited Consolidated Financial Statements in Item 1 ofrevenue received when this ~~Form 10-Q for additional information). No such impairments occurred in the prior year.~~

Selling, general and administrative (SG&A) costs are allocated to the total E&P division based on percentage of total revenue and percentage of total projected capital expenditures. SG&A costs were $63 million for the nine months ended September 30, 2017 compared to $74 million for the nine months ended September 30, 2016. Refer to the discussion of total company selling, general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders"~~of this quarterly report for a detailed cost explanation.~~

Interest expense related to the E&P division remained consistent at $2 million for the nine months ended September 30, 2017 and September 30, 2016. Interest incurred by the Other Gas segment primarily relates to a capital lease.

~~TOTAL PA MINING OPERATIONS DIVISION ANALYSIS for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016:~~

The PA Mining Operations division had earnings before income tax of $132 million for the nine months ended September 30, 2017, compared to earnings before income tax of $80 million for the nine months ended September 30, 2016. Variances are discussed below.

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Sales:
Coal Sales $ 899
$ 744
$ 155
Freight Revenue 52
34
18
Miscellaneous Other Income 19
10
9
Gain on Sale of Assets 6
—
6
Total Revenue and Other Income 976
788
188
Operating Costs and Expenses:
Operating Costs 588
489
99
Depreciation, Depletion and Amortization 118
114
4
Total Operating Costs and Expenses 706
603
103
Other Costs and Expenses:
Other Costs 21
33
(12 )
Depreciation, Depletion and Amortization 7
11
(4 )
Total Other Costs and Expenses 28
44
(16 )
Freight Expense 52
34
18
Selling, General and Administrative Costs 51
20
31
Total PA Mining Operations Costs 837
701
136
Interest Expense 7
7
—
Total PA Mining Operations Division Expense 844
708
136
Earnings Before Income Tax $ 132
$ 80
$ 52

~~The PA Mining Operations coal revenue and cost components on a per unit basis for these periods were as follows:~~

For the Nine Months Ended September 30,
2017 2016 Variance
Percent
Change
Company Produced PA Mining Operations Tons Sold (in millions) 19.9
17.5
2.4
13.7 %
Average Sales Price Per PA Mining Operations Ton Sold $ 45.26
$ 42.60
$ 2.66
6.2 %

Total Operating Costs Per Ton Sold $ 29.57
$ 28.05
$ 1.52
5.4 %
Total Depreciation, Depletion and Amortization Costs Per Ton Sold 5.94
6.48
(0.54 ) (8.3 )%
Total Costs Per PA Mining Operations Ton Sold $ 35.51
$ 34.53
$ 0.98
2.8 %
Average Margin Per PA Mining Operations Ton Sold $ 9.75
$ 8.07
$ 1.68
20.8 %

~~Coal Sales~~

PA Mining Operations coal sales were $899 million for the nine months ended September 30, 2017, compared to $744 million for the nine months ended September 30, 2016. The $155 million increase was attributable to a 2.4 million increaseExcess Firm Transportation Income in tons sold and a $2.66 per ton higher average sales price. The increase in tons sold was primarily due to increased demand from the Company's domestic power plant customers, in part due to higher natural gas prices, and increased demand in thermal export markets. The

higher average sales price per ton sold in the 2017 period was primarily the result of a tighter supply-demand balance in the international thermal and crossover metallurgical coal markets that the PA Mining Operations complex serves. The API2 index (the benchmark price reference for coal imported into northwest Europe) was up more than 50% in 2017 period compared to the year-ago period and the global coking coal prices were up by an even greater percentage in the period-to-period comparison.

~~Freight Revenue and Freight Expense~~

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on the weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, used by the customers to which the Company contractually provides transportation services. Freight revenue is completely offset by freight expense. Freight revenue and freight expense were both $52 million for the nine months ended September 30, 2017, compared to $34 million in the nine months ended September 30, 2016. The $18 million increase was due to increased shipments where transportation services were contractually provided.

~~Miscellaneous~~Total Other ~~Income~~

Miscellaneous other income increased $9 million in the period-to-period comparison, primarily a result of current year transactions related to: a customer contract buyout in the amount of $8 million and an increase in sales of externally purchased coal for blending purposes only. This increase was partially offset by a coal contract buyout in the amount of $6 million during the nine months ended September 30, 2016.

~~Gain on Sale of Assets~~

~~Gain on sale of assets increased $6 million in the period-to-period comparison primarily due to the sale of certain coal rights during the nine months ended September 30, 2017.~~

Operating ~~Costs and Expenses~~

Operating costs and expenses are comprised of costs related to produced tons sold, along with changes in both the volumes and carrying values of coal inventory. Operating costs and expenses include items such as direct operating costs, royalty and production taxes, employee-related expenses and depreciation, depletion, and amortization costs. Total operating costs and expenses for the PA Mining Operations division were $706 million for the nine months ended September 30, 2017, or $103 million higher than the $603 million for the nine months ended September 30, 2016. Total costs per PA Mining Operations ton sold were $35.51 per ton for the nine months ended September 30, 2017, compared to $34.53 per ton for the nine months ended September 30, 2016. The increase in the cost of coal sold was primarily driven by an increase in production tons to meet market demand, the timing of certain belt and maintenance projects, additional operating expenses incurred at the Bailey Mine resulting from permitting issues and adverse geological conditions at the Enlow Fork Mine. The average cost per ton sold also increased due to additional costs related to an increase in development mining footage, offset, in part, by a 4% improvement in productivity, as measured by tons per employee-hour, during the nine months ended September 30, 2017, compared to the year earlier period.

~~Other Costs and Expenses~~

Other costs and expenses include items that are assigned to the PA Mining Operations division but are not included in unit costs, such as coal reserve holding costs and purchased coal costs. Total other costs and expenses decreased $16 million in the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.Income. The decrease was primarily attributable to prior year costs related to: the temporary idling of one longwall at the PA Mining Operations complex to optimize the production schedule; and discretionary 401(k) contributions. This decrease was partially offset by a current period increase in costs related to externally purchased coal for blending purposes only and current year severance costs related to organizational restructuring.

~~Selling, General and Administrative Costs~~

Upon execution of the CNXC IPO, CNXC entered into a service agreement with CONSOL Energy that requires CONSOL Energy to provide certain selling, general and administrative services. These services are paid monthly based on an agreed upon fixed fee that is reset at least annually. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. An additional portion of CONSOL Energy's SG&A costs are allocated to the PA Mining Operations division based on a percentage of total revenue and a percentage of total projected capital expenditures. The amount of selling, general and administrative costs related to PA Mining Operations was $51 million for the nine months ended September 30, 2017, compared to $20 million for the nine months ended September 30, 2016. Refer

~~to the discussion of total Company selling, general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders"of this quarterly report for a detailed cost explanation.~~

~~Interest Expense~~

Interest expense, net of amounts capitalized, of $7 million for the nine months ended September 30, 2017 and 2016 is primarily comprised of interest on the CNXC revolving credit facility that was drawn upon after the CNXC IPO on July 7, 2015.

~~OTHER DIVISION ANALYSIS for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016~~:

The Other division includes various corporate and diversified business activities that are not allocated to the E&P or PA Mining Operations divisions. The diversified business activities include CNX Marine Terminal, closed and idle mine activities, water operations, selling, general and administrative activities, income tax expense (benefit), as well as various other non-operated activities.

The Other division had a loss before income tax of $131 million for the nine months ended September 30, 2017, compared to a loss before income tax of $211 million for the nine months ended September 30, 2016. The Other division also includes total Company income tax expense related to continuing operations of $40 million for the nine months ended September 30, 2017, compared to an income tax benefit of $72 million for the nine months ended September 30, 2016.

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Percent
Change
Other Outside Sales $ 46
$ 21
$ 25
119.0 %
Miscellaneous Other Income 45
43
2
4.7 %
Gain on Sale of Assets 26
3
23
766.7 %
Total Revenue 117
67
50
74.6 %
Miscellaneous Operating Expense 117
127
(10 ) (7.9 )%
Selling, General, and Administrative Costs
9
11
(2 ) (18.2 )%
Depreciation, Depletion and Amortization 1
4
(3 ) (75.0 )%
Loss on Debt Extinguishment 1
—
1
100.0 %
Interest Expense 120
136
(16 ) (11.8 )%
Total Other Costs 248
278
(30 ) (10.8 )%
Loss Before Income Tax (131 ) (211 ) 80
(37.9 )%
Income Tax Expense (Benefit) 40
(72 ) 112
(155.6 )%
Net Loss $ (171 ) $ (139 ) $ (32 ) 23.0 %

~~Other Outside Sales~~

Other outside sales consists of sales from CNX Marine Terminal, which is located on 200 acres in the port of Baltimore and provides access to international coal markets. CNX Marine Terminal sales were $46 million for the nine months ended September 30, 2017, compared to $21 million for the nine months ended September 30, 2016. The $25 million increase in the period-to-period comparison was primarily due to an increase in ~~throughput rates and tons~~utilization of firm transportation capacity in the current ~~period.~~year due to production increases in 2022 compared to 2021.

Other Expense


	For the Six Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Other Income


Right-of-Way Sales	$	2	$	1	$	1	100.0	%
Other	4		1		3		300.0	%
Total Other Income	$	6	$	2	$	4	200.0	%

Other Expense

Bank Fees	$	5	$	6	$	(1)	(16.7)	%
Professional Services	3		3		—		—	%

Other Corporate Expense	3		3		—		—	%
Total Other Expense	$	11	$	12	$	(1)	(8.3)	%

Total Other Expense	$	5	$	10	$	(5)	(50.0)	%

~~Miscellaneous Other Income~~

~~Miscellaneous~~•Total other income ~~was $45 million for the nine months ended September 30, 2017, compared to $43 million for the nine months ended September 30, 2016. The change is due to the following items:~~

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Royalty Income $ 16
$ 7
$ 9
Interest Income 9
1
8
Equity in Earnings of Affiliates —
1
(1 )
Right of Way Sales 3
6
(3 )
Rental Income 14
27
(13 )
Other Income 3
1
2
Total Miscellaneous Other Income $ 45
$ 43
$ 2

~~Royalty Income related to non-operated coal properties~~ increased $9 million in the period-to period comparison primarily due to an increase in third-party activity and higher coal prices in the current period. Payments were also received in the current period under the terms of the royalty agreement related to the Buchanan Mine sale. See Note 2-Discontinued Operations in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details.

~~Interest Income increased $8 million~~ in the period-to-period comparison primarily due to ~~income tax refunds received in the current period related to prior period income tax filings.~~increased right-of-way sales and various other one-time items.

~~Right of Way Sales relate to an initiative to generate additional revenue from the Company's unutilized surface rights.~~

~~The decrease of $3 million in the period-to-period comparison was due to fewer sales in the current period.~~

~~Rental Income decreased $13 million primarily due to a decrease in lease payments received as a result of the sale of certain subleased equipment in the current period.~~

Gain on ~~Sale~~Asset Sales and Abandonments, net

A gain on asset sales of ~~Assets~~

~~Gain on sale of assets increased $23~~$20 million ~~in the period-to-period comparison primarily due~~related to the sale of ~~Powhatan #4 coal reserves~~various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests) was recognized in the ~~sale of approximately 22,000 surface acres in Colorado during the nine~~six months ended ~~September~~June 30, ~~2017.~~2022 compared to a gain of $10 million in the six months ended June 30, 2021.

Loss on Debt Extinguishment

A loss on debt extinguishment of $13 million was recognized in the six months ended June 30, 2022 in connection with the purchase of a portion of the Convertible Notes due May 2026. See Note ~~3 - Acquisitions and Dispositions~~9 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. ~~No such transactions occurred in the prior period.~~

7349

~~Miscellaneous Operating Expense~~

Miscellaneous operating expense related to the Other division was $117 million for the nine months ended September 30, 2017, compared to $127 million for the nine months ended September 30, 2016. Miscellaneous operating expense decreased in the period-to-period comparison due to the following items:

For the Nine Months Ended September 30,
(in millions) 2017 2016 Variance
Pension Settlement $ —
$ 17
$ (17 )
Lease Rental Expense 11
23
(12 )
Litigation Expense 1
4
(3 )
Workers' Compensation 3
5
(2 )
Closed and Idle Mines 6
7
(1 )
UMWA Expenses 6
7
(1 )
UMWA OPEB Expense 33
33
—
Bank Fees 13
13
—
Severance Payments 1
1
—
Coal Reserve Holding Costs 5
4
1
CNX Marine Terminal 15
13
2
Pension Expense (6 ) (10 ) 4
Transaction Fees 20
—
20
Other 9
10
(1 )
Miscellaneous Operating Expense $ 117
$ 127
$ (10 )

Pension Settlement expense is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. Settlement accounting was triggered in the nine months ended September 30, 2016, primarily as a result of the sale of the Buchanan Mine in the first quarter of 2016 and the sale of the Fola and Miller Creek mining complexes in the third quarter of 2016. See Note 5 - Components of Pension and OPEB Plans Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail. Settlement accounting was not triggered in the current period.

~~Lease Rental Expense decreased $12 million primarily due to the sale of certain subleased equipment in the current period.~~

Pension Expense increased $4 million in the period-to-period comparison due to modifications made to the actuarial calculation of net periodic benefit cost at the beginning of each year. See Note 14 - Pension and Other Postretirement Benefit Plans in the Notes to the Audited Financial Statements in the Company's December 31, 2016 Form 10-K for additional information.

~~Transaction Fees of $20 million are costs primarily associated with the separation of the E&P and PA Mining Operations divisions.~~

~~Selling, General and Administrative Costs~~

Selling, general and administrative costs allocated to the Other division decreased $2 million in the period-to-period comparison. Refer to the discussion of total Company selling, general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders"~~of this quarterly report for more information.~~

~~Deprecation, Depletion and Amortization~~

~~Depreciation, depletion and amortization decreased $3 million in the period-to-period comparison due to changes in the asset retirement obligations at two of the Company's closed mine locations.~~

~~Loss on Debt Extinguishment~~

Loss on debt extinguishment of $1 million was recognized in the nine months ended September 30, 2017 due to the redemption of the 8.25% senior notes due in April 2020, the redemption of the 6.375% senior notes due in March 2021 and the purchase of a portion of the 5.875% senior notes due in April 2022. See Note 11 - Long-Term Debt in the Notes to the Audited Financial Statements in the Company's December 31, 2016 Form 10-K for additional information.

Interest Expense


	For the Six Months Ended June 30,
(in millions)	2022		2021		Variance		Percent Change
Total Interest Expense	$	58	$	76	$	(18)	(23.7)	%

~~Interest~~

The $18 million decrease in total interest expense ~~of $120 million was recognized in the nine months ended September 30, 2017, compared to $136 million in the nine months ended September 30, 2016. The decrease of $16 million~~ was primarily due to the ~~Company's revolving credit facility having no outstanding borrowings~~purchase of the $400 million 6.500% CNXM Senior Notes due March 2026 during the ~~nine months~~year ended ~~September 30, 2017, compared to $354~~December 31, 2021 offset, in part, by the $400 million of ~~outstanding borrowings at September 30, 2016.~~4.750% CNXM Senior Notes due 2030 that were issued during the year ended December 31, 2021. The decrease was also due to the ~~payoff of a portion~~Company adopting Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity on January 1, 2022. As part of the ~~2022 senior notes and~~adoption, total interest expense no longer includes a non-cash interest expense component related to the ~~redemption~~Convertible Notes due May 2026. During the six months ended June 30, 2021, total interest expense included $8 million that was amortized as additional non-cash interest expense related to the equity component of the ~~2020 and 2021 senior notes during the nine months ended September 30, 2017.~~

~~Income Taxes~~

The effective income tax rate for continuing operations when excluding noncontrolling interest was 27.7% for the nine months ended September 30, 2017, compared to 24.7% for the nine months ended September 30, 2016. The effective rates for the nine months ended September 30, 2017 and 2016 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. The effective tax rate differs from the U.S. federal statutory rate of 35% primarilyConvertible Notes due ~~to the income tax benefit for excess percentage depletion.~~May 2026. See Note ~~7 - Income Taxes of~~9 – Long-Term Debt 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) 2017 2016 Variance
Percent
Change
Total Company Earnings (Loss) Before Income Tax Excluding Noncontrolling Interest $ 144
$ (291 ) $ 435
(149.5 )%
Income Tax Expense (Benefit) $ 40
$ (72 ) $ 112
(155.6 )%
Effective Income Tax Rate 27.7 % 24.7 % 3.0 %
Income Taxes


	For the Six Months Ended June 30,
(in millions)	2022			2021			Variance			Percent Change
Total Company Loss Before Income Tax	$	(1,202)		$	(311)		$	(891)		286.5	%
Income Tax Benefit	$	(312)		$	(55)		$	(257)		467.3	%
Effective Income Tax Rate	26.0		%	17.6		%	8.4		%

The effective income tax rate was 26.0% for the six months ended June 30, 2022 compared to 17.6% for the six months ended June 30, 2021. The effective rate for the six months ended June 30, 2022 differs from the U.S. federal statutory rate of 21% primarily due to the impact of the partial repurchase of the Convertible Notes, equity compensation and state income taxes. The effective rate for the six months ended June 30, 2021 differs from the U.S. federal statutory rate of 21% primarily due to the impact of 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.

Liquidity and Capital Resources

~~CONSOL Energy~~

Overview, Sources and Uses

CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On June 18, 2014, CONSOL Energy entered into a five year Credit Agreement for a $2.0 billion senior secured revolving credit facility, which expires on June 18, 2019. In October 2017, the Company's lending group reaffirmed the $2.0 billion borrowing base of the facility. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $2.0 billion of borrowings, which includes a $750 million letters of credit aggregate sub-limit. CONSOL Energy can request an additional $500 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value of CONSOL Energy's proved gas reserves. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries, excluding CNXC. The interest coverage ratio was 5.46 to 1.00 at September 30, 2017. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, extraordinary gains and losses, gains and losses on discontinued operations, and gains and losses on debt extinguishment, and includes cash distributions received from affiliates, plus pro-rata earnings from material acquisitions. The facility also includes a minimum current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio is calculated as the ratio of current assets plus revolver availability, to current liabilities excluding borrowings under the revolver. This calculation also excludes all of CNXC's current assets, current liabilities and revolver availability. The current ratio was 3.09 to 1.00 at September 30, 2017. Affirmative and negative covenants in the facility limit the Company's ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems. The facility permits CONSOL Energy to separate its natural gas and coal businesses if the leverage ratio (which, is essentially the ratio of debt to EBITDA) of the natural gas business immediately after the separation would not be greater than 2.75 to 1.00. At September 30, 2017, the facility had no borrowings outstanding and $314 million of letters of credit outstanding, leaving $1,686 million of unused capacity. From time to time, CONSOL Energy 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. CONSOL Energy sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

In April 2016, the facility was amended to require that the Company must: (i) prepay outstanding loans under the revolving credit facility to the extent that cash on hand exceeds $150 million for two consecutive business days; (ii) mortgage 85% of its proved reserves and 80% of its proved developed producing reserves, in each case, which are included in the borrowing base; (iii) maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof; and (iv) enter into control agreements with respect to such applicable accounts. In addition, the Company pledged the equity interest it holds in CONE Gathering, LLC, and CONE Midstream Partners, LP as collateral to secure loans under the credit agreement.

In October 2017, the facility was amended to allow for the spin-off of CONSOL Mining, a subsidiary of the Company that will hold the coal business. At the time of the spin-off, the Company must be in compliance with a total net leverage ratio less than 3.50 to 1.00 on a pro forma standalone basis, and the lenders’ commitments to the facility will be reduced from $2.0 billion to $1.5 billion. The borrowing base will be unchanged from $2.0 billion. The amendment will be effective upon the consummation of the spin-off.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. These risks include declines in the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact the Company's collection of trade receivables. As a result, CONSOL Energy regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments and security. CONSOL Energy believes that its current group of customers is financially sound and represents no abnormal business risk.

~~CONSOL Energy~~CNX currently believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments, if any, and to provide required letters of ~~credit.~~credit for the current fiscal year. Nevertheless, the ability of ~~CONSOL Energy~~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 ~~and coal industries~~industry and other financial and business factors, including the current COVID-19 pandemic, some of which are beyond ~~CONSOL Energy’s~~CNX’s control.

~~In order~~From time to ~~manage the market risk exposure of volatile natural gas prices~~time, CNX is required to post financial assurances to satisfy contractual and other requirements generated in the future, CONSOL Energy enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various natural gas and NGL swap and option transactions, which exist parallel to the underlying physical transactions. The fair valuenormal course of business. Some of these ~~contracts~~assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

CNX continuously reviews its liquidity and capital resources. If market conditions were to change, for instance due to a significant decline in commodity prices and our revenue were reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be reduced.

As of June 30, 2022, CNX was in compliance with all of its debt covenants. After considering the potential effect of a net liability of $46 million at September 30, 2017 and a net liability of $188 million at December 31, 2016. The Company has not experienced any issues of non-performance by derivative counterparties.significant decline in commodity prices, CNX currently expects to remain in compliance with its debt covenants.

~~CONSOL Energy~~

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

Factors that may Impact our Liquidity

•The Company’s cash on hand and access to additional liquidity. Cash and cash equivalents as of June 30, 2022 and December 31, 2021 were $0.2 million and $3.6 million, respectively.

•Accounts and notes receivable - trade as of June 30, 2022 and December 31, 2021 were $447.5 million and $330.1 million, respectively. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.

•Capital expenditures are expected to range between $550.0 million to $590.0 million for the year ended December 31, 2022. For the six months ended June 30, 2022, CNX had capital expenditures of $259.0 million. Accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring an increase in costs in the future.

•Production volumes are expected to range between 575.0 Bcfe and 605.0 Bcfe for the year ended December 31, 2022. For the six months ended June 30, 2022, CNX had production volumes of 293.2 Bcfe.

•Prices for natural gas and NGLs are volatile, and an extended decline in the prices we receive for our natural gas and NGLs will adversely affect our financial condition and cash flows.

•In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of $2,554 million at June 30, 2022 and a net liability of $976 million at December 31, 2021. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q for further discussion of our commodity risk management.

Cash Flows (in millions)


	For the Six Months Ended June 30,
	2022		2021		Change
Cash Provided by Operating Activities	$	528	$	459	$	69
Cash Used in Investing Activities	$	(232)	$	(240)	$	8
Cash Used in Financing Activities	$	(299)	$	(195)	$	(104)

For the Nine Months Ended September 30,
2017 2016 Change
Cash Provided by Operating Activities $ 472
$ 388
$ 84
Cash Provided by Investing Activities $ 12
$ 221
$ (209 )
Cash Used in Financing Activities $ (259 ) $ (602 ) $ 343

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

•Net ~~income~~loss increased ~~$652~~$634 million in the period-to-period comparison.

•Adjustments to reconcile net ~~income~~loss to cash provided by operating activities primarily consisted of a ~~$292~~$265 million change in deferred income taxes, a $1,081 million net change in commodity derivative instruments, ~~a $338 million change~~and various other changes in discontinued operations (See Note 2 - Discontinued Operations in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for more information), and a $184 million change in gain on the sale of assets. These adjustments were offset, in part, by a $138 million impairment in the carrying value of Knox Energy (See Note 9 - Property, Plant, and Equipment in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for more information) and a $116 million change in deferred income taxes.working capital.

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

•Capital expenditures increased ~~$271 million in the period-to-period comparison due to the following:~~


◦	~~E&P division capital expenditures increased $256 million primarily due to increased expenditures in both the Marcellus and Utica Shale plays resulting from increased drilling activity.~~


◦	PA Mining Operations division capital expenditures increased $11 million primarily due to an increase in refuse expenditures, as well as equipment purchases and various other items that occurred throughout both periods, none of which were individually material.


◦	~~Other capital expenditures increased $4 million primarily due to expenditures related to the Company's water operations.~~

~~Proceeds from the sale of assets increased $388~~$7 million primarily due to ~~the sale of approximately 32,900 net undeveloped acres~~an overall increase in ~~Ohio, Pennsylvania,~~costs related to inflation and ~~West Virginia, the sale of approximately 22,000 acres~~an increase in Colorado and the sale of Knox Energy all in the current period (See Note 3 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).midstream expenditures.

~~Net Distributions~~•Proceeds from ~~(Investments in) Equity Affiliates changed $40~~asset sales increased $15 million ~~in the period-to-period comparison~~ primarily due to ~~distributions~~increased sales of ~~$18 million received from CONE Midstream Partners LP~~non-core surface and ~~distributions of $17 million from CONE Gathering LLC~~oil and gas interests in the ~~nine~~six months ended ~~September~~June 30, 2017. During the nine months ended September 30, 2016, $8 million of contributions were made to CONE Midstream Partners, LP and CONE Gathering LLC and distributions of $3 million were received from Buchanan Generation LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.2022.

Discontinued Operations decreased $366 million primarily as a result of the sale of the Buchanan Mine and certain other metallurgical coal reserves in the three months ended March 31, 2016. See Note 2 - Discontinued Operations of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

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

•In the ~~nine~~six months ended ~~September~~June 30, ~~2017, CONSOL Energy repurchased $117~~2022, CNX paid $27 million to repurchase $14 million of the 2026 Convertible Notes at an average price of 188.0% of the principal.

•In the six months ended June 30, 2022, ~~bonds, $74~~there were $3 million of net proceeds from the ~~2020 bonds and $21~~CNXM Credit Facility compared to $131 million of net payments during the six months ended June 30, 2021.

•In the six months ended June 30, 2022, there were $58 million of net payments on the CNX Credit Facility compared to $1 million of net payments during the six months ended June 30, 2021.

•In the six months ended June 30, 2021, ~~bonds.~~there were $13 million of net payments on the Cardinal States Facility. See Note ~~11 -~~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•During the ~~nine~~six months ended ~~September~~June 30, ~~2017, there were $13~~2022, CNX repurchased $212 million of ~~net payments under~~its common stock on the ~~CNX Coal Resources LP credit facility~~open market compared to ~~$23~~$47 million ~~of net proceeds in~~during the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021.

~~In the nine months ended September 30, 2016, CONSOL Energy made payments on the senior secured credit facility of $598 million. No payments were made in the nine months ended September 30, 2017.~~

The following is a summary of the Company's significant contractual obligations at ~~September~~June 30, ~~2017~~2022 (in thousands):

Payments due by Year

Less Than
1 Year
1-3 Years 3-5 Years
More Than
5 Years
Total
Purchase Order Firm Commitments $ 47,869
$ 12,438
$ 682
$ —
$ 60,989
Gas Firm Transportation and Processing 140,216
256,428
243,105
540,809
1,180,558
Long-Term Debt 990
188,457
1,730,999
603,591
2,524,037
Interest on Long-Term Debt 155,488
309,037
295,373
58,923
818,821
Capital (Finance) Lease Obligations 9,981
20,346
11,184
—
41,511
Interest on Capital (Finance) Lease Obligations 2,482
3,066
467
—
6,015
Operating Lease Obligations 58,986
73,105
48,380
66,176
246,647
Long-Term Liabilities—Employee Related (a) 67,397
131,770
128,972
575,947
904,086
Other Long-Term Liabilities (b) 349,597
79,180
51,668
328,133
808,578
Total Contractual Obligations (c) $ 833,006
$ 1,073,827
$ 2,510,830
$ 2,173,579
$ 6,591,242


	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total


Purchase Order Firm Commitments	$	646	$	—	$	—	$	—	$	646
Gas Firm Transportation and Processing	252,952		446,421		385,865		826,383		1,911,621
Long-Term Debt	323,277		—		1,027,020		895,481		2,245,778
Interest on Long-Term Debt	117,653		235,306		218,780		117,844		689,583
Finance Lease Obligations	637		878		397		67		1,979
Interest on Finance Lease Obligations	67		108		65		16		256
Operating Lease Obligations	40,951		77,688		39,563		22,177		180,379
Interest on Operating Lease Obligations	7,457		9,720		3,434		2,379		22,990
Long-Term Liabilities—Employee Related (a)	2,941		4,355		4,711		32,797		44,804
Other Long-Term Liabilities (b)	249,630		10,000		10,000		68,463		338,093
Total Contractual Obligations (c)	$	996,211	$	784,476	$	1,689,835	$	1,965,607	$	5,436,129

_________________________

~~(a)~~

Employee related long-term liabilities include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Additional contributions to the pension trust are not expected to be significant for the remainder of 2017.


~~(b)~~	~~Other long-term liabilities include mine reclamation and closure 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.

Debt

At ~~September~~June 30, ~~2017, CONSOL Energy~~2022, CNX had total long-term debt ~~and capital lease obligations~~ of ~~$2,565~~$2,246 million, ~~outstanding,~~ including the current portion of long-term debt of ~~$11 million.~~$324 million and excluding unamortized debt issuance costs. This long-term debt consisted of:

•An aggregate principal amount of ~~$1,731~~$700 million of ~~5.875% senior unsecured notes~~7.25% Senior Notes due ~~in April 2022~~March 2027 plus $4$5 million of unamortized bond premium. Interest on the notes is payable March 14 and September 14 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $500 million of 6.00% Senior Notes due January 2029. Interest on the notes is payable January 15 and July 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $5 million of unamortized bond discount. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by ~~most~~certain of ~~CONSOL Energy's~~CNXM's subsidiaries. CNX is not a guarantor of these notes.

•An aggregate principal amount of ~~$500~~$331 million of ~~8.00% senior unsecured notes~~2.25% Convertible Senior Notes due ~~in April 2023~~May 2026, unless earlier redeemed, repurchased, or converted, less $5$7 million of unamortized bond ~~discount.~~discount and issuance costs. Interest on the notes is payable ~~April~~May 1 and ~~October~~November 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of ~~CONSOL Energy’s subsidiaries.~~CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

An aggregate principal amount of $103 million of industrial revenue bonds, which were issued to finance the CNX Marine terminal, bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year. Payment of principal and interest on the notes is guaranteed by CONSOL Energy.

~~Advance royalty commitments of $2 million with an average interest rate of 7.73% per annum.~~

~~An aggregate principal amount of $1 million on a note maturing in March 2018.~~

~~An aggregate principal amount of $41 million of capital leases with a weighted average interest rate of 6.61% per annum.~~

•An aggregate principal amount of $188 million in outstanding borrowings under the ~~revolver for CNXC. CONSOL Energy~~CNXM Credit Facility. Payment of the principal and interest on the CNXM Credit Facility is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of ~~CNXC's revolving credit facility.~~the CNXM Facility.

~~At September 30, 2017, CONSOL Energy had no~~•An aggregate principal amount of $134 million in outstanding borrowings ~~outstanding and approximately $314 million of letters of credit outstanding~~ under the ~~$2.0 billion senior secured revolving credit facility.~~CNX Credit Facility. Payment of the principal and interest on the CNX Credit Facility is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

Total Equity and Dividends

~~CONSOL Energy~~CNX had total equity of ~~$4,071~~$2,537 million at ~~September~~June 30, ~~2017 and $3,941~~2022 compared to $3,700 million at December 31, ~~2016.~~2021. See the Consolidated ~~Statement~~Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

The declaration and payment of dividends by ~~CONSOL Energy~~CNX is subject to the discretion of ~~CONSOL Energy’s~~CNX's Board of Directors, and no assurance can be given that ~~CONSOL Energy~~CNX will pay dividends in the future. ~~CONSOL Energy’s Board of Directors determines whether~~CNX has not paid dividends ~~will be paid quarterly. CONSOL Energy suspended~~on its ~~quarterly dividend following the sale of the Buchanan Mine, in March 2016, to further reflect the Company's increased emphasis on growth.~~common stock since 2016. The determination to pay dividends in the future will depend upon, among other things, general business conditions, ~~CONSOL Energy’s~~CNX's financial results, contractual and legal restrictions regarding the payment of dividends by ~~CONSOL Energy,~~CNX, planned investments by ~~CONSOL Energy~~CNX, and such other factors as the Board of Directors deems relevant. ~~The Company's~~CNX's revolving credit facility limits ~~CONSOL Energy's~~its ability to pay

dividends in excess of an annual rate of ~~$0.50~~$0.10 per share when the Company's net leverage ratio exceeds ~~3.50~~3.00 to 1.00 and is subject to anavailability under CNX's revolving credit facility of at least 20% of the aggregate ~~amount up to a cumulative credit calculation set forth in the facility. The total leverage ratio was 2.93 to 1.00~~commitments and ~~the cumulative credit was approximately $861 million at September 30, 2017. The calculation of this leverage ratio excludes CNXC. The~~there being no borrowing base deficiency. CNX's revolving credit facility does not permit such dividend payments ~~in the~~when an event of ~~default.~~default has occurred and is continuing. The indentures to the ~~2022~~7.25% Senior Notes due March 2027 and ~~2023 notes~~the 6.00% Senior Notes due January 2029 limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2022.

In September 2017, CONSOL Energy’s board of directors approved a one-year share repurchase program of up to $200 million, under which approximately $81 million of the Company's common stock had been repurchased as of October 30, 2017, at an average price of approximately $16.00 per share, through a Rule 10b5-1 plan that will terminate on November 1, 2017. On October 30, 2017, the Board approved an increase in the aggregate amount of the repurchase plan to $450 million. The repurchases will be effected 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 share 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 CONSOL's free cash flow position, leverage ratio, and capital plans.

On October 20, 2017 the Board of Directors of CONE Midstream GP LLC, the general partner of CONE Midstream Partners LP, announced the declaration of a cash distribution of $0.3025 per unit with respect to the third quarter of 2017. The distribution will be made on November 14, 2017 to unitholders of record as of the close of business on November 3, 2017. The distribution, which equates to an annual rate of $1.21 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 2016.

On October 26, 2017, the Board of Directors of CNX Coal Resources LP declared a cash distribution to the Partnership's unitholders for the quarter ended September 30, 2017 of $0.5125 per common and subordinated unit. The cash distribution will be paid on November 15, 2017 to the unitholders of record at the close of business on November 8, 2017.

Off-Balance Sheet Transactions

~~CONSOL Energy~~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 ~~CONSOL Energy’s~~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 of this Form 10-Q. CONSOL Energy participates in various multi-employer benefit plans such as the UMWA Combined Benefit Fund and the UMWA 1992 Benefit Plan which generally accepted accounting principles recognize on a pay-as-you-go basis. These benefit arrangements may result in additional liabilities that are not recognized on the Consolidated Balance Sheet at September 30, 2017. The various multi-employer benefit plans are discussed in Note 16—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2016 Form 10-K. CONSOL Energy alsoStatements. 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 onin the Consolidated Balance Sheet at ~~September~~June 30, ~~2017.~~2022. Management believes these items will expire without being funded. See Note ~~12—~~10 – Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements ~~included~~ in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by ~~CONSOL Energy.~~CNX.

Critical Accounting Policies and Estimates

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements, and income and expenses during the periods reported. Actual results could materially differ from those estimates. The preceding discussion and analysis of our consolidated results of operations and financial condition should be read in conjunction with our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. The 2021 financial statements, as part of our Form 10-K filed with the SEC, includes additional information about us, our operations, our financial condition, our critical accounting policies and accounting estimates, and should be read in conjunction with this Quarterly Report on Form 10-Q. Our significant accounting policies are described in Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX's 2021 Form 10-K

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,”~~"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:

deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

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

~~an extended decline in the prices we receive for our~~•unsuccessful drilling efforts or continued natural gas price decreases requiring write downs of our proved natural gas ~~liquids~~properties, or 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 ~~coal affecting our operating results and cash flows;~~industry

~~foreign currency fluctuations~~

multiples, could ~~adversely affect the competitiveness of our coal and natural gas liquids abroad;~~

~~our customers extending existing contracts or entering into new long-term contracts for coal on favorable terms;~~

~~our reliance on major customers;~~

~~our inability to collect payments from customers if their creditworthiness declines or if they fail to honor their contracts;~~

~~the disruption of rail, barge, gathering, processing and transportation facilities~~cause goodwill and other ~~systems that deliver our natural gas, natural gas liquids~~intangible assets we hold to become impaired and ~~coal~~result in material non-cash charges to ~~market;~~earnings;

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

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

~~coal users switching~~•hedging activities may prevent us from benefiting from price increases and may expose us to other ~~fuels~~risks;

•negative public perception regarding our Company or industry;

•events beyond our control, including a global or domestic health crisis, or political or economic instability or armed conflict in ~~order~~oil and gas producing regions;

•increasing attention to ~~comply~~environmental, social and governance matters;

•dependence on gathering, processing and transportation facilities and other midstream facilities owned by others, and disruption of, capacity constraints in, or proximity to pipeline systems, and any decrease in availability of pipelines or other midstream facilities;

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

•the high-risk nature of drilling, developing and 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;

•the substantial capital expenditures required for, and commensurate risks associated with, ~~various environmental standards related to coal combustion emissions;~~

~~the impact of potential,~~our development and exploration projects, as well as ~~any adopted environmental regulations including any relating to greenhouse gas emissions on our operating costs as well as on the market for natural gas and coal and for our securities;~~midstream system development;

the risks inherent in natural gas and coal operations, including our reliance upon third party contractors, being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial results;

•decreases in the availability of, or increases in the price of, ~~commodities~~required personnel, services, equipment, parts and raw materials in sufficient quantities or ~~capital equipment used in~~at reasonable costs to support our ~~coal mining and natural gas~~ operations;

~~obtaining and renewing governmental permits and approvals for our natural gas and coal operations;~~

~~the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our natural gas and coal operations;~~

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

•failure to successfully estimate the ~~effects~~rate of ~~stringent federal and state employee health and safety regulations, including the ability~~decline of ~~regulators~~existing reserves or to ~~shut down our operations;~~

~~the potential for liabilities arising from environmental contamination~~find or ~~alleged environmental contamination in connection with our past or current gas and coal operations;~~

~~the effects of mine closing, reclamation, gas well closing and certain other liabilities;~~

~~uncertainties in estimating our~~acquire economically recoverable natural gas ~~oil and coal~~reserves to replace our current natural gas reserves;

~~defects may exist in our chain~~•losses incurred as a result of title defects in the properties in which we invest or the loss of certain leasehold or other rights related to our midstream activities;

•the impact of climate change legislation, litigation and ~~we may incur additional~~potential, as well as any adopted, environmental regulations, including those relating to greenhouse gas emissions;

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

•existing and future governmental 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 natural gas gathering pipelines;

•changes in federal or state income tax laws or rates focused on ~~some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;~~natural gas exploration and development;

•the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the ~~Securities~~ Exchange ~~Act of 1934;~~Act;

~~exposure to employee-related long-term liabilities;~~

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

~~joint ventures that we are party to now or in the future may restrict our flexibility, actions taken by our joint ventures may impact our financial position and operational results;~~

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

~~replacing our natural gas and oil reserves, which if not replaced, will cause our natural gas and oil reserves and production to decline;~~

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

•Risks associated with our ~~hedging activities~~Convertible Notes, including the 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 the Convertible Notes could delay or prevent ~~us from benefiting from near-term price increases and may expose us to other risks;~~a beneficial takeover of the Company;

~~changes~~•the potential impact of the capped call transaction undertaken in ~~federal or state income tax laws, particularly in~~tandem with the ~~area~~Convertible Notes issuance, including counterparty risk;

•challenges associated with strategic determinations, including the allocation of ~~percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate;~~

~~failure to appropriately allocate~~ capital and other resources ~~among our~~to strategic ~~opportunities may adversely affect our financial condition;~~opportunities;

~~failure by Murray Energy~~•inability to ~~satisfy liabilities it acquired from us,~~complete acquisitions and divestitures, or failure to ~~perform its obligations under various arrangements, which~~produce anticipated benefits of the transaction;

•there is no guarantee that we ~~guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows;~~

~~information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident;~~

~~operating in a single geographic area;~~

~~certain provisions in our multi-year coal sales contracts may provide limited protection during adverse economic conditions, and may result in economic penalties or permit the customer~~will continue to ~~terminate the contract;~~

~~the majority~~repurchase shares of our common ~~units~~stock under our current or any future share repurchase program at levels undertaken previously or at all;

•we may operate a portion of our business with one or more joint venture partners or in ~~CNX Coal Resources LP~~circumstances where we are not the operator, which may restrict our operational and ~~CONE Midstream Partners LP are subordinated,~~corporate flexibility and we may not ~~receive distributions~~realize the benefits we expect to realize from ~~CNX Coal Resources LP or CONE Midstream Partners LP;~~a joint venture;

with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC, any disruption to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results;

~~uncertainties as to the timing of the separation and whether it will be completed; the possibility that various closing conditions for the separation~~•CONSOL Energy may not be ~~satisfied;~~able to satisfy its indemnification obligations in the ~~impact~~future and such indemnities may not be sufficient to hold us harmless from the full amount of ~~the separation~~liabilities for which CONSOL Energy may be allocated responsibility;

•cyber-incidents could have a material adverse effect on our ~~business: the expected tax treatment~~business, financial condition or results of the separation; the risk that the coal and natural gas exploration and production business will not be separated successfully or such separation may be more difficult, time-consuming or costly than expected, which could result in additional demandsoperations;

•our success depends on ~~our resources, systems, procedures and controls, disruption~~key members of our ~~ongoing~~management and our ability to attract and retain experienced technical and other professional personnel;

•terrorist activities could materially adversely affect our business and ~~diversion~~results of ~~management's attention from other business concerns; competitive responses to the separation;~~operations; and

with respect to the termination of the joint venture with Noble, any disruption to our business, including customer and supplier relationships from this transaction, and the impact of the transaction on our future operating and financial results and liquidity; and

•certain other factors ~~discussed~~addressed in ~~the 2016~~this report and in our 2021 Form 10-K under ~~“Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file~~"Risk Factors".

Although forward-looking statements reflect our good faith beliefs at the ~~Securities~~time they are made, they involve known and ~~Exchange Commission.~~unknown risks, uncertainties and other factors. For more information concerning factors that could cause actual results to differ materially from those conveyed in the 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 2021 Form 10-K 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, ~~CONSOL Energy~~CNX is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding ~~CONSOL Energy's~~CNX's exposure to the risks of changing commodity prices, interest rates and foreign exchange rates.

~~CONSOL Energy~~CNX is exposed to market price risk in the normal course of selling natural gas and ~~to a lesser extent in the sale of coal. CONSOL Energy~~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 and NGLs. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value.~~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. In order to lock in certain margins while balancing its basis hedges, during the first quarter of 2022 CNX purchased, rather than sold, financial swaps for the period April through October of 2022. In order to enhance production flexibility, during the first quarter of 2021, CNX purchased, rather than sold, financial swaps for the period April through October of 2021. Under these purchased financial swaps, CNX will pay a fixed price to and receive a floating price from its hedge counterparties.

~~CONSOL Energy~~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. ~~CONSOL Energy's~~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~~predefined risk parameters.

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

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 ~~CONSOL Energy's 2016~~CNX's 2021 Form 10-K.

CNX's open gas derivative instruments can cause earnings volatility relative to changes in market prices until the derivative contracts are either settled or are monetized prior to settlement. At ~~September~~June 30, ~~2017,~~2022 and December 31, 2021 our open gas derivative instruments were in a net liability ~~position~~positions with a fair ~~value~~values of ~~$46 million.~~$2,554 million and $976 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at ~~September~~June 30, ~~2017~~.2022 and December 31, 2021. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value ~~of the net liability~~ by ~~$275~~$1,004 million and $625 million at ~~September~~June 30, ~~2017.~~2022 and December 31, 2021, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value ~~of the net liability~~ by ~~$271~~$765 million and $607 million at ~~September~~June 30, ~~2017.~~2022 and December 31, 2021, respectively.

~~CONSOL Energy’s~~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. These instruments change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. At ~~September~~June 30, ~~2017, CONSOL Energy~~2022 and December 31, 2021, CNX had ~~$2,358~~$1,910 million and $1,839 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including

unamortized debt issuance costs of ~~$20~~$15 million each. At June 30, 2022 and December 31, 2021, CNX had $322 million and ~~$186~~$377 million, respectively, of debt outstanding under variable-rate ~~instruments, including unamortized debt issuance costs of $2 million. CONSOL Energy’s~~instruments. CNX’s primary exposure to market risk for changes in interest rates relates to ~~our~~CNX's revolving credit facility, under which there were no$134 million of borrowings at ~~September~~June 30, ~~2017~~,2022 and ~~CNXC's~~$192 million at December 31, 2021, and CNXM's revolving credit facility, under which there were $188 million of borrowings at ~~September~~June 30, ~~2017.~~2022 and $185 million at December 31, 2021. A hypothetical 100 basis-point increase in the average rate for ~~CONSOL Energy's and CNXC's revolving credit facilities~~CNX's variable-rate instruments would decrease pre-tax future earnings as of June 30, 2022 and December 31, 2021 by ~~$2 million.~~$3 million and $4 million, respectively, on an annualized basis.

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

Natural Gas Hedging Volumes

As of ~~October 17, 2017, our~~July 7, 2022, the Company's hedged volumes for the periods indicated are as follows:


	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2022 Fixed Price Volumes*
Hedged Bcf	N/A		N/A		125.3		118.0		243.3
Weighted Average Hedge Price per Mcf	N/A		N/A		$	2.34	$	2.41	$	2.37
2023 Fixed Price Volumes
Hedged Bcf	100.0		111.3		112.5		112.5		417.2**
Weighted Average Hedge Price per Mcf	$	2.66	$	2.44	$	2.44	$	2.48	$	2.47
2024 Fixed Price Volumes
Hedged Bcf	94.5		92.1		93.1		93.1		368.4**
Weighted Average Hedge Price per Mcf	$	2.32	$	2.33	$	2.33	$	2.33	$	2.32
2025 Fixed Price Volumes
Hedged Bcf	85.2		91.0		92.0		92.0		354.1**
Weighted Average Hedge Price per Mcf	$	2.39	$	2.44	$	2.44	$	2.44	$	2.41
2026 Fixed Price Volumes
Hedged Bcf	67.2		77.3		78.0		78.0		300.5
Weighted Average Hedge Price per Mcf	$	2.61	$	2.68	$	2.68	$	2.68	$	2.66
2027 Fixed Price Volumes
Hedged Bcf	17.3		17.5		17.6		17.6		70.0
Weighted Average Hedge Price per Mcf	$	3.34	$	3.34	$	3.34	$	3.34	$	3.34

*Excludes purchased swaps. The Company's purchased swaps are as follows:

For the Three Months Ended
March 31, June 30, September 30, December 31, Total Year
2017 Fixed Price Volumes
Hedged Bcf N/A N/A N/A 83.0
83.0
Weighted Average Hedge Price per Mcf N/A N/A N/A $ 2.63
$ 2.63
2018 Fixed Price Volumes
Hedged Bcf 86.8
84.3
85.3
86.0
342.4
Weighted Average Hedge Price per Mcf $ 2.80
$ 2.79
$ 2.79
$ 2.80
$ 2.80
2019 Fixed Price Volumes
Hedged Bcf 59.2
59.8
60.5
60.3
239.4*
Weighted Average Hedge Price per Mcf $ 2.69
$ 2.69
$ 2.69
$ 2.69
$ 2.69
2020 Fixed Price Volumes
Hedged Bcf 46.2
43.1
43.6
43.6
173.5*
Weighted Average Hedge Price per Mcf $ 2.68
$ 2.59
$ 2.59
$ 2.56
$ 2.60
2021 Fixed Price Volumes
Hedged Bcf 31.2
31.5
31.9
31.9
126.5
Weighted Average Hedge Price per Mcf $ 2.34
$ 2.34
$ 2.34
$ 2.33
$ 2.34


	For the Three Months Ended
	September 30,		December 31,
Purchased Basis Swaps	2022		2022		Total Year
Hedged Bcf	$	6.7	2.3		9.0
Weighted Average Fixed Price per Mcf	$	(1.13)	$	(1.13)	$	(1.13)

**Quarterly volumes do not add to annual volumes ~~in as much~~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. ~~CONSOL Energy,~~ CNX, under the supervision and with the participation of its management, including ~~CONSOL Energy’s~~CNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s ~~“disclosure~~"disclosure controls and procedures,”" as such term is defined in Rule 13a-15(e) under the ~~Securities~~ Exchange Act, ~~of 1934, as amended (the “Exchange Act”),~~ as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, ~~CONSOL Energy’s~~CNX’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of ~~September~~June 30, ~~2017~~2022 to ensure that information required to be disclosed by ~~CONSOL Energy~~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 ~~CONSOL Energy~~CNX in such reports is

accumulated and communicated to ~~CONSOL Energy’s~~CNX’s management, including ~~CONSOL Energy’s~~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 through the ~~seventh~~third paragraphs of Note ~~12—~~10 – Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

From time to time, CNX and federal, state, and local regulatory agencies that oversee CNX’s activities enter into agreements regarding notices of noncompliance. CNX is currently not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which the Company is subject to, that would have a material effect on future financial results.

ITEM 1A. RISK FACTORS

~~There~~The financial conditions and operating results of the Company can be ~~no assurance that we will complete our proposed separation into two separate publicly-traded companies: (i)~~affected by a ~~natural gas exploration and production (E&P) company, and (ii) a coal company.~~

~~As previously disclosed, CONSOL Energy intends~~number of factors, whether currently known or unknown, including but not limited to ~~separate into two separate publicly-traded companies: (i) a natural gas exploration and production (E&P) company, and (ii) a coal company (the “spin-off”).~~those described in "Item 1A. Risk Factors" in CNX's 2021 Form 10-K. The Registration Statement on Form 10 relating to the spin-off has not yet been declared effective by the SEC, and completion of the spin-off is subject to various conditions. There can be no assurance that the spin-off will be completed. CONSOL Energy expects that the process of completing the proposed separation will be time-consuming and involve significant costs and expenses, which may be significantly higher than what it currently anticipates and may not yield a benefit if the separation is not completed.

There may be substantial disruption to our business and distraction of our management and employees as a result of the proposed spin-off, and the uncertainty associated with the proposed transaction may otherwise adversely impact our operations and relationships with key stakeholders.

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the proposed spin-off may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to CONSOL Energy.

In addition, the uncertainty surrounding whether or when the spin-off will occur and other aspects of the spin-off, may adversely affect our ability to enter into new customer agreements or extend or expand existing customer relationships if potential and existing customers choose to wait to learn whether the transaction will proceed before committing to new, extended or expanded customer relationships with us. Similarly, suppliers, vendors and other businesses or organizations that we may seek to contract with or expand existing relationships with us may choose to wait to enter into new agreements or arrangements or change existing agreements or arrangements with us. If such uncertainty continues for a protracted period, our ability to secure new, extended or expanded customer relationships may be adversely affected, or we may be compelled to pay higher fees or incur new or higher expenses to operate and maintain our business. We cannot predict whether or when any adverse effects on our business will result from these uncertainties, but such effects, if any,risks described could materially and adversely affect ~~our revenues~~CNX's business, financial condition, cash flows, and results of ~~operations~~operations. CNX may experience additional risks and uncertainties not currently known; or, as a result of developments occurring in the future, ~~periods.~~

~~Furthermore, the uncertainty surrounding the potential spin-off~~conditions that are currently deemed to be immaterial may adversely affect our ability to attract and retain qualified personnel. We operate in an industry that currently experiences a high level of competition among different companies for qualified and experienced personnel. The uncertainty relating to the possibility of the spin-off may increase the risk that we could experience higher than normal rates of attrition or that we experience increased difficulty in attracting qualified personnel or incur higher expenses to do so. High levels of attrition among the management and employee personnel necessary to operate our business or difficulties or increased expense incurred to replace any personnel who leave, could materially adversely affect our business or results of operations.

~~The separation may not achieve some or all of the anticipated benefits.~~

CONSOL Energy may not realize some or all of the anticipated strategic, financial, operational or other benefits from the separation. As independent publicly-traded companies, the two companies will be smaller, less diversified companies with a narrower business focus and may be more vulnerable to changing market conditions, such as changes in natural gas industry, which could result in increased volatility in their cash flows, working capital and financing requirements and couldalso materially and adversely affect ~~the respective~~CNX's business, financial condition, cash flows, and results of operations. ~~Further, there can be~~There have been no ~~assurance that~~material changes to the ~~combined value~~Company’s risk factors since the 2021 Form 10-K was filed.

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

The following table sets forth repurchases of our common stock during the three months ended June 30, 2022:


ISSUER PURCHASES OF EQUITY SECURITIES
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)
April 1, 2022- April 30, 2022	236,981	$	21.33	234,195	$	858,637
May 1, 2022- May 31, 2022	1,496,370	$	19.38	1,495,159	$	829,661
June 1, 2022- June 30, 2022	2,101,320	$	17.12	2,101,320	$	793,696
Total	3,834,671			3,830,674

(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 ~~common stock~~Company's current $1,900 million share repurchase program authorized by the Board of Directors, which is not subject to an expiration date. See Note 14 – Stock Repurchase in the ~~two publicly-traded companies will be equal~~Notes to ~~or greater than what~~ the ~~value~~Unaudited Consolidated Financial Statements in Item 1 of ~~CONSOL Energy’s common stock would have been had the proposed separation not occurred.~~this Form 10-Q for more information.

~~ITEM 4. MINE SAFETY DISCLOSURES~~

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.

8457

ITEM 6.EXHIBITS


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



~~31.1~~10.1			Amendment No. 1, dated as of May 5, 2022, to the Third Amended and Restated Credit Agreement, dated October 6, 2021, by and among CNX Resources Corporation, the guarantors party thereto, the lenders party thereto and PNC Bank, N.A., as administrative agent and collateral agent, filed here within.1
10.2			Amendment No. 1, dated as of May 5, 2022, to the Amended and Restated Credit Agreement, dated October 6, 2021 by and among CNX Midstream Partners LP, the guarantors party thereto, the lenders party thereto and PNC Bank, N.A., as administrative agent and collateral agent, filed here within.
10.3			Change in Control Severance Agreement, dated February 4, 2021, by and between the Company and Alan Shepard, filed here within.
31.1*			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
~~31.2~~	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
~~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
~~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.
95101.SCH*				~~Mine Safety and Health Administration Safety Data.~~ XBRL Taxonomy Extension Schema Document.
101.CAL*			XBRL Taxonomy Extension Calculation Linkbase Document.
~~101~~101.DEF*			XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	~~Interactive Data File (Form 10-Q for the quarterly period ended September 30, 2017 furnished in XBRL).~~		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 31, 2017~~July 28, 2022


CNX RESOURCES CORPORATION

~~CONSOL ENERGY INC.~~		By:	/S/ NICHOLAS J. DEIULIIS

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

		By:	/S/ ALAN K. SHEPARD
			Alan K. Shepard
		~~By:~~	/S~~/ DONALD W. RUSH~~
		~~Donald W. Rush~~
		Chief Financial Officer ~~and Executive Vice President~~ (Duly Authorized Officer and Principal Financial and Accounting Officer)

		By:	/S/ JASON L. MUMFORD
			Jason L. Mumford
		~~By:~~	/S~~/ C. KRISTOPHER HAGEDORN~~
		~~C. Kristopher Hagedorn~~
		Vice President and Controller ~~(Duly Authorized Officer and Principal Accounting Officer)~~

8558



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


Class						Shares outstanding as of July 19, 2022
Common stock, $0.01 par value						189,452,074


			Page
PART I FINANCIAL INFORMATION

~~Class~~ITEM 1.		Unaudited Condensed Consolidated Financial Statements	~~Shares outstanding as of October 16, 2017~~
~~Common stock, $0.01 par value~~	~~230,103,982~~

~~TABLE OF CONTENTS~~

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

~~ITEM 1.~~	~~Condensed Financial Statements~~
	Consolidated Statements of Income for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~2021	45
			Consolidated Statements of Comprehensive Income for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~ 2021	56
			Consolidated Balance Sheets at ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016~~2021	67
			Consolidated ~~Statement~~Statements of Stockholders’ Equity for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017~~2022 and 2021	89
			Consolidated Statements of Cash Flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~2021	911
			Notes to Unaudited Consolidated Financial Statements	1012

ITEM 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations	4230

ITEM 3.			Quantitative and Qualitative Disclosures About Market Risk	8255

ITEM 4.			Controls and Procedures	8356

PART II OTHER INFORMATION

ITEM 1.			Legal Proceedings	8357

ITEM 1A.			Risk Factors	8457

ITEM 4.2.			Unregistered Sales of Equity Securities and Use of Proceeds	~~Mine Safety Disclosures~~57	84

ITEM 6.			Exhibits	8558



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



o☐			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,
Revenues and Other Income:	2017			2016			2017		2016
Natural Gas, NGLs and Oil Sales	$	234,443		$	205,913		$	812,511	$	555,101
Gain on Commodity Derivative Instruments	19,183			198,192			80,508		53,872
Coal Sales	279,245			267,685			899,400		744,411
Other Outside Sales	16,959			4,714			45,986		20,687
Purchased Gas Sales	13,384			12,086			32,678		28,633
Freight-Outside Coal	21,803			9,392			51,847		33,949
Miscellaneous Other Income	41,036			32,393			115,669		114,159
Gain on Sale of Assets	45,230			15,203			197,343		13,541
Total Revenue and Other Income	671,283			745,578			2,235,942		1,564,353
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	21,754			22,602			64,459		73,996
Transportation, Gathering and Compression	98,768			94,796			279,699		279,753
Production, Ad Valorem, and Other Fees	5,919			9,027			19,854		23,732
Depreciation, Depletion and Amortization	101,585			101,257			288,220		312,122
Exploration and Production Related Other Costs	4,479			384			33,980		5,036
Purchased Gas Costs	13,142			11,940			32,231		28,692
Other Corporate Expenses	26,844			21,760			68,172		65,980
Impairment of Exploration and Production Properties	—			—			137,865		—
Selling, General, and Administrative Costs	20,328			26,198			62,490		74,067
Total Exploration and Production Costs	292,819			287,964			986,970		863,378
PA Mining Operations Costs
Operating and Other Costs	207,772			182,717			608,678		521,277
Depreciation, Depletion and Amortization	41,638			42,370			125,341		125,334
Freight Expense	21,803			9,392			51,847		33,949
Selling, General, and Administrative Costs	18,664			7,653			50,637		20,207
Total PA Mining Operations Costs	289,877			242,132			836,503		700,767
Other Costs
Miscellaneous Operating Expense	35,518			39,658			117,007		126,580
Selling, General, and Administrative Costs	2,896			4,996			9,182		11,124
Depreciation, Depletion and Amortization	5,545			8,085			1,047		4,463
Loss on Debt Extinguishment	2,019			—			1,233		—
Interest Expense	41,502			47,317			129,367		144,609
Total Other Costs	87,480			100,056			257,836		286,776
Total Costs And Expenses	670,176			630,152			2,081,309		1,850,921
Earnings (Loss) From Continuing Operations Before Income Tax	1,107			115,426			154,633		(286,568		)
Income Tax Expense (Benefit)	26,758			52,858			39,962		(71,798		)
(Loss) Income From Continuing Operations	(25,651		)	62,568			114,671		(214,770		)
Loss From Discontinued Operations, net	—			(34,975		)	—		(322,747		)
Net (Loss) Income	(25,651		)	27,593			114,671		(537,517		)
Less: Net Income Attributable to Noncontrolling Interest	790			2,248			10,567		4,541
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(26,441	)	$	25,345		$	104,104	$	(542,058	)



	(Unaudited)
(Dollars in thousands)	September 30, 2017		December 31, 2016
ASSETS
Current Assets:
Cash and Cash Equivalents	$	285,708	$	60,475
Accounts and Notes Receivable:
Trade	193,778		220,222
Other Receivables	77,746		69,901
Inventories	63,182		65,461
Recoverable Income Taxes	105,432		116,851
Prepaid Expenses	79,437		93,146
Current Assets of Discontinued Operations	—		83
Total Current Assets	805,283		626,139
Property, Plant and Equipment:
Property, Plant and Equipment	13,738,388		13,771,388
Less—Accumulated Depreciation, Depletion and Amortization	5,939,426		5,630,949
Total Property, Plant and Equipment—Net	7,798,962		8,140,439
Other Assets:
Deferred Income Taxes	—		4,290
Investment in Affiliates	190,154		190,964
Other	185,169		222,149
Total Other Assets	375,323		417,403
TOTAL ASSETS	$	8,979,568	$	9,183,981



	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2017	2016	2017	2016
Anti-Dilutive Options	5,407,465	2,989,610	2,731,362	6,230,099
Anti-Dilutive Restricted Stock Units	1,102,180	3,455	183,479	645,302
Anti-Dilutive Performance Share Units	1,793,302	1,659,014	—	2,326,120
Anti-Dilutive Performance Stock Options	802,804	802,804	802,804	802,804
	9,105,751	5,454,883	3,717,645	10,004,325



	Long-Term Liabilities
Balance at December 31, 2016	$	(392,556	)
Amounts Reclassified from Accumulated Other Comprehensive Loss	10,430
Add: Other Comprehensive Loss Attributable to Non-Controlling Interest	34
Balance at September 30, 2017	$	(382,092	)



	For the Three Months Ended			For the Nine Months Ended
	September 30, 2016			September 30, 2016
Coal Sales	$	6,974		$	102,904
Freight-Outside Coal	305			1,322
Miscellaneous Other Income	2,204			2,237
Loss on Sale of Assets	(53,119		)	(91,372		)
Total Revenue and Other Income	$	(43,636	)	$	15,091
Total Costs	11,789			124,865
Loss From Operations Before Income Taxes	$	(55,425	)	$	(109,774	)
Impairment on Assets Held for Sale	—			355,681
Income Tax Benefit	(20,450		)	(142,708		)
Loss From Discontinued Operations, net	$	(34,975	)	$	(322,747	)



	September 30, 2017		December 31, 2016
Assets:
Accounts Receivable - Trade	$	—	$	83
Total Current Assets	$	—	$	83
Total Assets of Discontinued Operations	$	—	$	83
Liabilities:
Accounts Payable	$	—	$	36
Other Current Liabilities	5,353		6,014
Total Current Liabilities	$	5,353	$	6,050
Total Liabilities of Discontinued Operations	$	5,353	$	6,050



	Pension Benefits												Other Post-Employment Benefits
	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016		2017			2016
Service Cost	$	846		$	482		$	2,537		$	1,445		$	—		$	—	$	—		$	—
Interest Cost	6,428			5,895			19,285			19,578			5,986			6,060		17,958			18,181
Expected Return on Plan Assets	(10,596		)	(11,195		)	(31,787		)	(34,933		)	—			—		—			—
Amortization of Prior Service Credits	(148		)	(148		)	(443		)	(443		)	(601		)	—		(1,804		)	—
Recognized Net Actuarial Loss	2,351			2,743			7,052			6,975			5,778			4,792		17,334			14,376
Settlement Loss	—			3,651			—			17,347			—			—		—			—
Net Periodic Benefit (Credit) Cost	$	(1,119	)	$	1,428		$	(3,356	)	$	9,969		$	11,163		$	10,852	$	33,488		$	32,557



	CWP												Workers' Compensation
	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Service Cost	$	1,129		$	1,041		$	3,388		$	3,285		$	1,463		$	1,904		$	4,389		$	5,713
Interest Cost	1,013			1,053			3,038			3,230			592			638			1,776			1,913
Amortization of Actuarial Gain	(1,908		)	(1,188		)	(5,724		)	(3,759		)	(153		)	(101		)	(458		)	(303		)
Administrative Fees	151			—			454			—			138			792			413			2,491
State Administrative Fees and Insurance Bond Premiums	—			—			—			—			621			—			2,009			—
Curtailment Gain	—			—			—			(1,307		)	—			—			—			—
Net Periodic Benefit Cost	$	385		$	906		$	1,156		$	1,449		$	2,661		$	3,233		$	8,129		$	9,814



	September 30, 2017		December 31, 2016
Coal	$	9,905	$	7,800
Supplies	53,277		57,661
Total Inventories	$	63,182	$	65,461



	September 30, 2017		December 31, 2016
E&P Property, Plant and Equipment
Intangible drilling cost	$	3,663,552	$	3,583,565
Proved gas properties	1,950,232		2,016,916
Unproved gas properties	1,031,555		1,116,282
Gas gathering equipment	1,131,982		1,138,299
Gas wells and related equipment	825,201		791,996
Other gas assets	190,400		190,406
Gas advance royalties	13,323		13,762
Total E&P Property, Plant and Equipment	$	8,806,245	$	8,851,226
Less: Accumulated Depreciation, Depletion and Amortization	3,317,180		3,106,296
Total E&P Property, Plant and Equipment - Net	$	5,489,065	$	5,744,930

PA Mining Operations Property, Plant and Equipment
Coal and other plant and equipment	$	2,352,826	$	2,307,668
Coal properties and surface lands	460,688		458,398
Airshafts	378,296		371,752
Mine development	326,152		326,152
Coal advance mining royalties	16,136		16,224
Leased coal lands	26,556		26,566
Total PA Mining Operations and Other Property, Plant and Equipment	$	3,560,654	$	3,506,760
Less: Accumulated Depreciation, Depletion and Amortization	1,890,856		1,768,712
Total PA Mining Operations and Other Property, Plant and Equipment - Net	$	1,669,798	$	1,738,048

Other Property, Plant and Equipment
Coal and other plant and equipment	$	494,842	$	532,919
Coal properties and surface lands	476,281		481,126
Airshafts	10,003		10,003
Mine development	17,989		17,988
Coal advance mining royalties	311,538		310,530
Leased coal lands	60,836		60,836
Total Other Property, Plant and Equipment	$	1,371,489	$	1,413,402
Less: Accumulated Depreciation, Depletion and Amortization	731,390		755,941
Total Other Property, Plant and Equipment - Net	$	640,099	$	657,461

Total Company Property, Plant and Equipment - Continuing Operations	$	13,738,388	$	13,771,388
Less - Total Company Accumulated Depreciation, Depletion and Amortization	5,939,426		5,630,949
Total Property, Plant and Equipment of Continuing Operations - Net	$	7,798,962	$	8,140,439



	September 30, 2017		December 31, 2016
Debt:
Senior Notes due April 2022 at 5.875% (Principal of $1,730,975 and $1,850,000 plus Unamortized Premium of $3,804 and $4,731, respectively)	$	1,734,779	$	1,854,731
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $4,977 and $5,656, respectively)	495,023		494,344
Revolving Credit Facility - CNX Coal Resources LP	188,000		201,000
MEDCO Revenue Bonds in Series due September 2025 at 5.75%	102,865		102,865
Senior Notes due April 2020 at 8.25%, Issued at Par Value	—		74,470
Senior Notes due March 2021 at 6.375%, Issued at Par Value	—		20,611
Advance Royalty Commitments (7.73% Weighted Average Interest Rate)	2,678		2,678
Other Note Maturing in 2018 (Principal of $692 and $1,789, respectively, less Unamortized Discount of $117 at December 31, 2016)	692		1,672
Less: Unamortized Debt Issuance Costs	22,265		27,699
	2,501,772		2,724,672
Less: Amounts Due in One Year*	990		1,677
Long-Term Debt	$	2,500,782	$	2,722,995



Asset Derivative Instruments					Liability Derivative Instruments
	September 30,		December 31,			September 30,		December 31,
	2017		2016			2017		2016
Commodity Swaps:
Prepaid Expense	$	19,840	$	16	Other Accrued Liabilities	$	45,097	$	209,980
Other Assets	40,105		29,596		Other Liabilities	47,109		67,139
Total Asset	$	59,945	$	29,612	Total Liability	$	92,206	$	277,119

Basis Only Swaps:
Prepaid Expense	$	25,252	$	56,916	Other Accrued Liabilities	$	33,077	$	21,593
Other Assets	14,119		35,603		Other Liabilities	19,963		11,575
Total Asset	$	39,371	$	92,519	Total Liability	$	53,040	$	33,168



	Marcellus Shale		Utica Shale		Coalbed Methane		Other Gas			Total E&P		PA Mining Operations		Other			Adjustments and Eliminations			Consolidated
Sales—Outside	$	133,793	$	43,375	$	46,744	$	10,531		$	234,443	$	279,245	$	—		$	—		$	513,688	(A)
Gain on Commodity Derivative Instruments	11,299		2,517		3,093		2,274			19,183		—		—			—			19,183
Other Outside Sales	—		—		—		—			—		—		16,959			—			16,959
Sales—Purchased Gas	—		—		—		13,384			13,384		—		—			—			13,384
Freight—Outside	—		—		—		—			—		21,803		—			—			21,803
Intersegment Transfers	—		—		—		—			—		—		5,994			(5,994		)	—
Total Sales and Freight	$	145,092	$	45,892	$	49,837	$	26,189		$	267,010	$	301,048	$	22,953		$	(5,994	)	$	585,017
Earnings (Loss) From Continuing Operations Before Income Tax	$	12,123	$	7,342	$	5,454	$	(4,693	)	$	20,226	$	21,011	$	(34,136	)	$	(5,994	)	$	1,107	(B)
Segment Assets										$	5,941,092	$	1,912,656	$	1,113,540		$	12,280		$	8,979,568	(C)
Depreciation, Depletion and Amortization										$	101,585	$	41,638	$	5,545		$	—		$	148,768
Capital Expenditures										$	147,522	$	27,157	$	2,615		$	—		$	177,294



	Marcellus Shale		Utica Shale		Coalbed Methane		Other Gas		Total E&P		PA Mining Operations		Other			Adjustments and Eliminations		Consolidated
Sales—Outside	$	107,676	$	40,312	$	46,917	$	11,008	$	205,913	$	267,685	$	—		$	—	$	473,598
Gain on Commodity Derivative Instruments	23,548		4,646		8,197		161,801		198,192		—		—			—		198,192
Other Outside Sales	—		—		—		—		—		—		4,714			—		4,714
Sales—Purchased Gas	—		—		—		12,086		12,086		—		—			—		12,086
Freight—Outside	—		—		—		—		—		9,392		—			—		9,392
Intersegment Transfers	—		—		—		—		—		—		—			—		—
Total Sales and Freight	$	131,224	$	44,958	$	55,114	$	184,895	$	416,191	$	277,077	$	4,714		$	—	$	697,982
Earnings (Loss) From Continuing Operations Before Income Tax	$	10,465	$	4,342	$	6,989	$	139,279	$	161,075	$	34,741	$	(80,390	)	$	—	$	115,426	(D)
Segment Assets									$	6,537,210	$	2,007,767	$	1,018,406		$	2,111	$	9,565,494	(E)
Depreciation, Depletion and Amortization									$	101,257	$	42,370	$	8,085		$	—	$	151,712
Capital Expenditures									$	48,746	$	12,292	$	3,094		$	—	$	64,132



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			CNXC Non-Guarantor		Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	234,443	$	—		$	—	$	—		$	234,443
Gain on Commodity Derivative Instruments	—			19,183		—			—		—			19,183
Coal Sales	—			—		209,434			69,811		—			279,245
Other Outside Sales	—			—		16,959			—		—			16,959
Purchased Gas Sales	—			13,384		—			—		—			13,384
Freight-Outside Coal	—			—		16,352			5,451		—			21,803
Miscellaneous Other Income	8,476			23,656		14,384			2,996		(8,476		)	41,036
Gain on Sale of Assets	—			26,648		18,576			6		—			45,230
Total Revenue and Other Income	8,476			317,314		275,705			78,264		(8,476		)	671,283
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			21,754		—			—		—			21,754
Transportation, Gathering and Compression	—			98,768		—			—		—			98,768
Production, Ad Valorem, and Other Fees	—			5,919		—			—		—			5,919
Depreciation, Depletion and Amortization	—			101,585		—			—		—			101,585
Exploration and Production Related Other Costs	—			4,479		—			—		—			4,479
Purchased Gas Costs	—			13,142		—			—		—			13,142
Other Corporate Expenses	—			26,844		—			—		—			26,844
Selling, General, and Administrative Costs	—			20,328		—			—		—			20,328
Total Exploration and Production Costs	—			292,819		—			—		—			292,819
PA Mining Operations Costs
Operating and Other Costs	—			—		155,612			52,160		—			207,772
Depreciation, Depletion and Amortization	—			—		31,286			10,352		—			41,638
Freight Expense	—			—		16,352			5,451		—			21,803
Selling, General, and Administrative Costs	—			—		14,381			4,283		—			18,664
Total PA Mining Operations Costs	—			—		217,631			72,246		—			289,877
Other Costs
Miscellaneous Operating Expense	17,413			—		18,105			—		—			35,518
Selling, General, and Administrative Costs	—			—		2,896			—		—			2,896
Depreciation, Depletion and Amortization	—			—		5,545			—		—			5,545
Loss on Debt Extinguishment	2,019			—		—			—		—			2,019
Interest Expense	36,733			575		1,790			2,404		—			41,502
Total Other Costs	56,165			575		28,336			2,404		—			87,480
Total Costs And Expenses	56,165			293,394		245,967			74,650		—			670,176
(Loss) Earnings from Continuing Operations Before Income Tax	(47,689		)	23,920		29,738			3,614		(8,476		)	1,107
Income Tax (Benefit) Expense	(21,248		)	9,506		38,500			—		—			26,758
(Loss) Income From Continuing Operations	(26,441		)	14,414		(8,762		)	3,614		(8,476		)	(25,651		)
Less: Net Income Attributable to Noncontrolling Interest	—			—		—			—		790			790
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(26,441	)	$	14,414	$	(8,762	)	$	3,614	$	(9,266	)	$	(26,441	)



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non-Guarantor			Other Subsidiary Non-Guarantors			Elimination			Consolidated
Net Cash Provided by (Used in) Continuing Operating Activities	$	454,447		$	(22,404	)	$	5,244		$	60,708		$	590		$	(25,747	)	$	472,838
Net Cash Used in Discontinued Operating Activities	—			—			—			—			(614		)	—			(614		)
Net Cash Provided by (Used in) Operating Activities	$	454,447		$	(22,404	)	$	5,244		$	60,708		$	(24	)	$	(25,747	)	$	472,224
Cash Flows from Investing Activities:
Capital Expenditures	$	(1,550	)	$	(390,619	)	$	(46,190	)	$	(12,261	)	$	—		$	—		$	(450,620	)
Proceeds from Sales of Assets	—			382,186			43,192			1,500			—			—			426,878
Net Distributions from Equity Affiliates	—			35,620			—			—			—			—			35,620
Net Cash (Used in) Provided by Investing Activities	$	(1,550	)	$	27,187		$	(2,998	)	$	(10,761	)	$	—		$	—		$	11,878
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	$	(1,917	)	$	(4,782	)	$	(2,246	)	$	1		$	—		$	—		$	(8,944	)
Payments on Long-Term Notes	(213,728		)	—			—			—			—			—			(213,728		)
Net Payments on Revolver - CNX Coal Resources LP	—			—			—			(13,000		)	—			—			(13,000		)
Distributions to Noncontrolling Interest	—			—			—			(42,150		)	—			25,747			(16,403		)
Issuance of Common Stock	859			—			—			—			—			—			859
Treasury Stock Activity	(6,346		)	—			—			(1,009		)	—			—			(7,355		)
Debt Repurchase and Financing Fees	(298		)	—			—			—			—			—			(298		)
Net Cash (Used in) Provided by Financing Activities	$	(221,430	)	$	(4,782	)	$	(2,246	)	$	(56,158	)	$	—		$	25,747		$	(258,869	)



	CONE			The Partnership			Total
Balance at December 31, 2016	$	151,075		$	18,133		$	169,208
Equity in Earnings	4,500			29,469			33,969
Distributions	(17,254		)	(18,366		)	(35,620		)
Asset Transfer	(2,527		)	2,527			—
Balance at September 30, 2017	$	135,794		$	31,763		$	167,557



	Q4 2017		2017		2018		2019		2020
NYMEX Only Hedges
Volumes (Bcf)	73.5		282.4		316.1		226.3		161.6
Average Prices ($/Mcf)	$	3.16	$	3.14	$	3.14	$	2.99	$	2.89
Index Hedges and Contracts
Volumes (Bcf)	9.6		34.2		17.2		13.1		11.9
Average Prices ($/Mcf)	$	3.01	$	3.11	$	2.62	$	2.44	$	2.27
Total Volumes Hedged (Bcf)¹	83.1		316.6		333.3		239.4		173.5


NYMEX + Basis (fully-covered volumes)²
Volumes (Bcf)	81.7		311.3		333.3		239.1		166.2
Average Prices ($/Mcf)	$	2.62	$	2.59	$	2.78	$	2.69	$	2.59
NYMEX Only Hedges Exposed to Basis
Volumes (Bcf)	1.4		5.3		—		0.3		7.3
Average Prices ($/Mcf)	$	3.16	$	3.14	$	—	$	2.99	$	2.89
Total Volumes Hedged (Bcf)¹	83.1		316.6		333.3		239.4		173.5



	For the Nine Months Ended													Difference to Nine Months Ended
	September 30, 2017													September 30, 2016
(in millions)	Marcellus			Utica			CBM			Other Gas		Total E&P		Marcellus			Utica			CBM			Other Gas			Total E&P
Natural Gas, NGLs and Oil Sales	$	477		$	136		$	157		$	43	$	813	$	190		$	21		$	34		$	13		$	258
(Loss) Gain on Commodity Derivative Instruments	(43		)	(2		)	(13		)	138		80		(164		)	(27		)	(57		)	274			26
Purchased Gas Sales	—			—			—			33		33		—			—			—			4			4
Miscellaneous Other Income	—			—			—			52		52		—			—			—			(9		)	(9		)
Gain on Sale of Assets	—			—			—			165		165		—			—			—			155			155
Total Revenue and Other Income	434			134			144			431		1,143		26			(6		)	(23		)	437			434
Lease Operating Expense	23			14			19			8		64		(4		)	(3		)	1			(4		)	(10		)
Production, Ad Valorem, and Other Fees	9			3			6			2		20		(4		)	(1		)	2			(1		)	(4		)
Transportation, Gathering and Compression	184			33			49			14		280		13			(4		)	(5		)	(4		)	—
Depreciation, Depletion and Amortization	159			50			61			18		288		5			(14		)	(5		)	(9		)	(23		)
Exploration and Production Related Other Costs	—			—			—			34		34		—			—			—			29			29
Purchased Gas Costs	—			—			—			32		32		—			—			—			3			3
Other Corporate Expenses	—			—			—			68		68		—			—			—			2			2
Impairment of Exploration and Production Properties	—			—			—			138		138		—			—			—			138			138
Selling, General and Administrative Costs	—			—			—			63		63		—			—			—			(11		)	(11		)
Total Exploration and Production Costs	375			100			135			377		987		10			(22		)	(7		)	143			124
Interest Expense	—			—			—			2		2		—			—			—			—			—
Total E&P Division Costs	375			100			135			379		989		10			(22		)	(7		)	143			124
Earnings (Loss) Before Income Tax	$	59		$	34		$	9		$	52	$	154	$	16		$	16		$	(16	)	$	294		$	310