CNX Resources Corp - Quarter Report: 2019 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended June 30, 2019



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CNX Resources Corporation

(Exact name of registrant as specified in its charter)



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

CNX Center

1000 CONSOL Energy Drive Suite 400

Canonsburg, PA 15317-6506

(724) 485-4000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)



Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of exchange on which registered
Common Stock ($.01 par value)	CNX	New York Stock Exchange
Preferred Share Purchase Rights	--	New York Stock Exchange

__________________________________________________

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller Reporting Company ☐

Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Shares outstanding as of July 15, 2019
Common stock, $0.01 par value		187,563,388

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Consolidated Financial Statements
	Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018	4
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2019 and 2018	5
	Consolidated Balance Sheets at June 30, 2019 and December 31, 2018	6
	Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2019 and 2018	8
	Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018	9
	Notes to Unaudited Consolidated Financial Statements	10

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	62

ITEM 4.	Controls and Procedures	63

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	64

ITEM 1A.	Risk Factors	64

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64

ITEM 6.	Exhibits	65

GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMS

The following are abbreviations of certain measurement terms commonly used in the oil and gas industry and included within this Form 10-Q:

Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf - One billion cubic feet of natural gas.

Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

Btu - One British Thermal unit.

BBtu - One billion British Thermal units.

Mbbls - One thousand barrels of oil or other liquid hydrocarbons.

Mcf - One thousand cubic feet of natural gas.

Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

MMbtu - One million British Thermal units.

MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

NGL - Natural gas liquids - those hydrocarbons in natural gas that are separated from the gas as liquids through the process.

net - “net” natural gas or “net” acres are determined by adding the fractional ownership working interests the Company has in gross wells or acres.

TIL - turn-in-line; a well turned to sales.

blending - process of mixing dry and damp gas in order to meet downstream pipeline specifications.

proved reserves - quantities of oil, natural gas, and NGLs which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

proved developed reserves (PDPs) - proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

proved undeveloped reserves (PUDs) - proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

reservoir - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

development well - a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

exploratory well - a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

gob well - a well drilled or vent hole converted to a well which produces or is capable of producing coalbed methane or other natural gas from a distressed zone created above and below a mined-out coal seam by any prior full seam extraction of the coal.

service well - a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.

play - a proven geological formation that contains commercial amounts of hydrocarbons.

royalty interest - the land owner’s share of oil or gas production, typically 1/8.

throughput - the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period.

working interest - an interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

wet gas - natural gas that contains significant heavy hydrocarbons, such as propane, butane and other liquid hydrocarbons.

PART I : FINANCIAL INFORMATION


ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



(Dollars in thousands, except per share data)	Three Months Ended						Six Months Ended
(Unaudited)	June 30,						June 30,
Revenues and Other Operating Income:	2019			2018			2019			2018
Natural Gas, NGLs and Oil Revenue	$	342,865		$	334,517		$	778,811		$	740,140
Gain on Commodity Derivative Instruments	221,581			25,660			26,205			60,747
Purchased Gas Revenue	18,768			9,930			34,989			27,985
Midstream Revenue	18,895			23,483			37,338			49,737
Other Operating Income	2,923			8,534			6,120			19,244
Total Revenue and Other Operating Income	605,032			402,124			883,463			897,853
Costs and Expenses:
Operating Expense
Lease Operating Expense	19,876			25,338			38,504			62,148
Transportation, Gathering and Compression	84,614			75,767			164,023			162,028
Production, Ad Valorem, and Other Fees	7,030			7,703			13,976			16,936
Depreciation, Depletion and Amortization	128,999			119,087			254,159			243,754
Exploration and Production Related Other Costs	5,567			3,699			8,825			6,079
Purchased Gas Costs	18,772			9,747			34,986			26,801
Impairment of Other Intangible Assets	—			18,650			—			18,650
Selling, General, and Administrative Costs	48,970			34,909			84,709			66,258
Other Operating Expense	17,976			17,786			41,451			33,832
Total Operating Expense	331,804			312,686			640,633			636,486
Other Expense (Income)
Other (Income) Expense	(99		)	575			(681		)	(5,917		)
(Gain) Loss on Asset Sales and Abandonments	(387		)	(3,280		)	2,699			(14,622		)
Gain on Previously Held Equity Interest	—			—			—			(623,663		)
Loss on Debt Extinguishment	77			23,413			7,614			39,048
Interest Expense	40,152			38,438			75,923			76,989
Total Other Expense (Income)	39,743			59,146			85,555			(528,165		)
Total Costs and Expenses	371,547			371,832			726,188			108,321
Earnings Before Income Tax	233,485			30,292			157,275			789,532
Income Tax Expense (Benefit)	40,791			(31,102		)	29,231			182,592
Net Income	192,694			61,394			128,044			606,940
Less: Net Income Attributable to Noncontrolling Interest	30,217			19,380			52,904			37,363
Net Income Attributable to CNX Resources Shareholders	$	162,477		$	42,014		$	75,140		$	569,577

Earnings per Share
Basic	$	0.85		$	0.19		$	0.39		$	2.60
Diluted	$	0.84		$	0.19		$	0.38		$	2.57

Dividends Declared	$	—		$	—		$	—		$	—

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended				Six Months Ended
(Dollars in thousands)	June 30,				June 30,
(Unaudited)	2019		2018		2019		2018
Net Income	$	192,694	$	61,394	$	128,044	$	606,940
Other Comprehensive Income:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($14), ($687), ($29), ($781))	41		1,812		85		1,982

Comprehensive Income	192,735		63,206		128,129		608,922

Less: Comprehensive Income Attributable to Noncontrolling Interest	30,217		19,380		52,904		37,363

Comprehensive Income Attributable to CNX Resources Shareholders	$	162,518	$	43,826	$	75,225	$	571,559

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands)	June 30, 2019		December 31, 2018
ASSETS
Current Assets:
Cash and Cash Equivalents	$	32,611	$	17,198
Accounts and Notes Receivable:
Trade	125,084		252,424
Other Receivables	11,636		11,077
Supplies Inventories	11,242		9,715
Recoverable Income Taxes	113,592		149,481
Prepaid Expenses	165,929		61,791
Total Current Assets	460,094		501,686
Property, Plant and Equipment:
Property, Plant and Equipment	10,203,489		9,567,428
Less—Accumulated Depreciation, Depletion and Amortization	2,863,627		2,624,984
Total Property, Plant and Equipment—Net	7,339,862		6,942,444
Other Assets:
Operating Lease Right-of-Use Assets	224,950		—
Investment in Affiliates	17,637		18,663
Goodwill	796,359		796,359
Other Intangible Assets	99,923		103,200
Other	207,872		229,818
Total Other Assets	1,346,741		1,148,040
TOTAL ASSETS	$	9,146,697	$	8,592,170

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands, except per share data)	June 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	305,070		$	229,806
Current Portion of Finance Lease Obligations	7,133			6,997
Current Portion of Operating Lease Obligations	66,209			—
Other Accrued Liabilities	244,833			286,172
Total Current Liabilities	623,245			522,975
Non-Current Liabilities:
Long-Term Debt	2,618,375			2,378,205
Finance Lease Obligations	10,569			13,299
Deferred Income Taxes	427,942			398,682
Operating Lease Obligations	137,464			—
Asset Retirement Obligations	32,951			37,479
Other	196,156			159,787
Total Non-Current Liabilities	3,423,457			2,987,452
TOTAL LIABILITIES	4,046,702			3,510,427
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 187,559,362 Issued and Outstanding at June 30, 2019; 198,663,342 Issued and Outstanding at December 31, 2018	1,879			1,990
Capital in Excess of Par Value	2,203,969			2,264,063
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,127,627			2,071,809
Accumulated Other Comprehensive Loss	(7,819		)	(7,904		)
Total CNX Resources Stockholders’ Equity	4,325,656			4,329,958
Noncontrolling Interest	774,339			751,785
TOTAL STOCKHOLDERS' EQUITY	5,099,995			5,081,743
TOTAL LIABILITIES AND EQUITY	$	9,146,697		$	8,592,170

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY



	Three Months Ended						Six Months Ended
(Unaudited)	June 30,						June 30,
Dollars in Thousands	2019			2018			2019			2018
Total Stockholders’ Equity, Beginning Balance	$	4,974,809		$	5,067,906		$	5,081,743		$	3,899,899

Common Stock and Capital in Excess of Par Value:
Beginning Balance	2,251,475			2,411,665			2,266,053			2,452,564
Issuance of Common Stock	62			507			161			1,563
Purchase and Retirement of Common Stock	(69,022		)	(42,402		)	(93,990		)	(88,688		)
Amortization of Stock-Based Compensation Awards	23,333			5,018			33,624			9,349
Ending Balance	2,205,848			2,374,788			2,205,848			2,374,788

Retained Earnings:
Beginning Balance	1,971,898			1,940,882			2,071,809			1,455,811
Net Income	162,477			42,014			75,140			569,577
Purchase and Retirement of Common Stock	(5,261		)	(42,354		)	(13,790		)	(80,031		)
Shares Withheld for Taxes	(1,487		)	(35		)	(5,532		)	(4,850		)
Ending Balance	2,127,627			1,940,507			2,127,627			1,940,507

Accumulated Other Comprehensive Loss:
Beginning Balance	(7,860		)	(8,306		)	(7,904		)	(8,476		)
Other Comprehensive Income	41			1,812			85			1,982
Ending Balance	(7,819		)	(6,494		)	(7,819		)	(6,494		)

Total CNX Resources Corporation Stockholders' Equity	4,325,656			4,308,801			4,325,656			4,308,801

Non-Controlling Interest:
Beginning Balance	759,296			723,665			751,785			—
Net Income	30,217			19,380			52,904			37,363
Shares Withheld for Taxes	(25		)	—			(690		)	(347		)
Amortization of Stock-Based Compensation Awards	540			691			1,152			1,269
Distributions to CNXM Noncontrolling Interest Holders	(15,689		)	(13,614		)	(30,812		)	(26,740		)
Acquisition of CNX Gathering, LLC	—			—			—			718,577
Ending Balance	774,339			730,122			774,339			730,122

Total Stockholders' Equity, Ending Balance	$	5,099,995		$	5,038,923		$	5,099,995		$	5,038,923

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:	2019			2018
Net Income	$	128,044		$	606,940
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	254,159			243,754
Amortization of Deferred Financing Costs	4,408			4,821
Impairment of Other Intangible Assets	—			18,650
Stock-Based Compensation	34,776			10,618
Loss (Gain) on Asset Sales and Abandonments	2,699			(14,622		)
Gain on Previously Held Equity Interest	—			(623,663		)
Loss on Debt Extinguishment	7,614			39,048
Gain on Commodity Derivative Instruments	(26,205		)	(60,747		)
Net Cash Paid in Settlement of Commodity Derivative Instruments	(30,710		)	(307		)
Deferred Income Taxes	29,231			190,194
Equity in Earnings of Affiliates	(1,030		)	(3,447		)
Return on Equity Investment	2,056			—
Changes in Operating Assets:
Accounts and Notes Receivable	125,991			44,156
Recoverable Income Taxes	35,888			3,743
Supplies Inventories	(1,527		)	243
Prepaid Expenses	4,287			1,327
Changes in Operating Liabilities:
Accounts Payable	29,346			(3,198		)
Accrued Interest	5,050			(3,358		)
Other Operating Liabilities	(36,392		)	1,504
Changes in Other Liabilities	(6,907		)	(5,374		)
Other	(105		)	648
Net Cash Provided by Operating Activities	560,673			450,930
Cash Flows from Investing Activities:
Capital Expenditures	(628,365		)	(496,659		)
CNX Gathering LLC Acquisition, Net of Cash Acquired	—			(299,272		)
Proceeds from Asset Sales	7,087			153,420
Net Distributions from Equity Affiliates	—			3,650
Net Cash Used in Investing Activities	(621,278		)	(638,861		)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	(3,515		)	(3,748		)
Payments on Long-Term Notes	(405,876		)	(723,419		)
Net Proceeds from (Payments on) CNXM Revolving Credit Facility	124,000			(138,500		)
Proceeds from CNX Revolving Credit Facility	18,000			422,000
Proceeds from Issuance of CNX Senior Notes	500,000			—
Proceeds from Issuance of CNXM Senior Notes	—			394,000
Distributions to CNXM Noncontrolling Interest Holders	(30,812		)	(26,740		)
Proceeds from Issuance of Common Stock	161			1,563
Shares Withheld for Taxes	(6,222		)	(5,197		)
Purchases of Common Stock	(109,780		)	(166,720		)
Debt Repurchase and Financing Fees	(9,938		)	(19,629		)
Net Cash Provided by (Used in) Financing Activities	76,018			(266,390		)
Net Increase (Decrease) in Cash and Cash Equivalents	15,413			(454,321		)
Cash and Cash Equivalents at Beginning of Period	17,198			509,167
Cash and Cash Equivalents at End of Period	$	32,611		$	54,846

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

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 six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for future periods.

The Consolidated Balance Sheet at December 31, 2018 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, 2018 included in CNX Resources Corporation's ("CNX," "CNX Resources," the "Company," "we," "us," or "our") Annual Report on Form 10-K as filed with the Securities and Exchange Commission (SEC) on February 7, 2019.

Certain amounts in prior periods have been reclassified to conform to the current period presentation.

The Consolidated Balance Sheet at June 30, 2019 reflects the full consolidation of CNX Gathering LLC's assets and liabilities as a result of the acquisition by CNX Gas Company LLC ("CNX Gas"), an indirect wholly owned subsidiary of CNX, of NBL Midstream, LLC's ("Noble") 50% interest in CNX Gathering LLC on January 3, 2018 (See Note 5 - Acquisitions and Dispositions for more information).

NOTE 2—EARNINGS PER SHARE:

Basic earnings per share is computed by dividing net income attributable to CNX shareholders by the weighted average shares outstanding during the reporting period. Diluted earnings per share are computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock options, restricted stock units and performance share units, if dilutive. 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, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. CNX Midstream Partners LP's ("CNXM") dilutive units did not have a material impact on the Company's earnings per share calculations for the three or six months ended June 30, 2019, the three months ended June 30, 2018, or the period from January 3, 2018 through June 30, 2018.

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 antidilutive:



	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2019	2018	2019	2018
Anti-dilutive Options	2,041,273	2,300,785	2,041,273	2,300,785
Anti-dilutive Restricted Stock Units	150,007	—	220,858	7,828
Anti-dilutive Performance Share Units	—	—	—	178,189
Anti-dilutive Performance Stock Options	927,268	927,268	927,268	927,268
	3,118,548	3,228,053	3,189,399	3,414,070

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,
	2019	2018	2019	2018
Options	7,093	73,583	20,841	227,301
Restricted Stock Units	515,265	7,260	973,234	178,397
Performance Share Units	—	—	342,882	357,597
	522,358	80,843	1,336,957	763,295

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

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



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Net Income	$	192,694	$	61,394	$	128,044	$	606,940
Less: Net Income Attributable to Non-Controlling Interest	30,217		19,380		52,904		37,363
Net Income Attributable to CNX Resources Shareholders	$	162,477	$	42,014	$	75,140	$	569,577

Weighted-average Shares of Common Stock Outstanding	191,524,289		215,991,490		194,483,555		218,944,422
Effect of Diluted Shares	1,256,443		2,938,470		1,507,800		2,701,442
Weighted-average Diluted Shares of Common Stock Outstanding	192,780,732		218,929,960		195,991,355		221,645,864

Earnings per Share:
Basic	$	0.85	$	0.19	$	0.39	$	2.60
Diluted	$	0.84	$	0.19	$	0.38	$	2.57

NOTE 3—CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS:

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



	Amount
Balance at December 31, 2018	$	(7,904	)
Amounts Reclassified from Accumulated Other Comprehensive Loss, net of tax	85
Balance at June 30, 2019	$	(7,819	)

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Actuarially Determined Long-Term Liability Adjustments
Amortization of Prior Service Costs	$	(4	)	$	(90	)	$	(8	)	$	(181	)
Recognized Net Actuarial Loss	59			354			122			708
Total	55			264			114			527
Less: Tax Benefit	14			94			29			188
Net of Tax	$	41		$	170		$	85		$	339

NOTE 4—REVENUE FROM CONTRACTS WITH CUSTOMERS:

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

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

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

Disaggregation of Revenue

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



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Revenue from Contracts with Customers
Natural Gas Revenue	$	317,071	$	289,294	$	720,758	$	636,642
NGLs Revenue	24,025		39,557		53,790		90,441
Condensate Revenue	1,680		4,996		4,007		11,499
Oil Revenue	89		670		256		1,558
Total Natural Gas, NGLs and Oil Revenue	342,865		334,517		778,811		740,140

Purchased Gas Revenue	18,768		9,930		34,989		27,985
Midstream Revenue	18,895		23,483		37,338		49,737

Other Sources of Revenue and Other Operating Income
Gain on Commodity Derivative Instruments	221,581		25,660		26,205		60,747
Other Operating Income	2,923		8,534		6,120		19,244
Total Revenue and Other Operating Income	$	605,032	$	402,124	$	883,463	$	897,853

The disaggregated revenue corresponds with the Company’s segment reporting found in Note 16 - Segment Information.

Contract Balances

CNX invoices its customers once a performance obligation has been satisfied, at which point payment is unconditional. Accordingly, CNX's contracts with customers do not give rise to contract assets or liabilities under Accounting Standards Codification (ASC) 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer. The opening and closing balances of the Company’s receivables related to contracts with customers were $252,424 and $125,084, respectively.

Transaction Price Allocated to Remaining Performance Obligations

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

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

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

For revenue associated with contract terms greater than one year with a fixed price component, the aggregate amount of the transaction price allocated to remaining performance obligations was $142,899 as of June 30, 2019. The Company expects to recognize net revenue of $48,904 in the next 12 months and $41,076 over the following 12 months, with the remainder recognized thereafter.

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

Prior-Period Performance Obligations

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

NOTE 5—ACQUISITIONS AND DISPOSITIONS:

On May 2, 2018, CNX closed on an Asset Exchange Agreement (the “AEA”) with HG Energy II Appalachia, LLC (“HG Energy”), pursuant to which, among other things, HG Energy (i) paid to CNX approximately $7,000 and (ii) assigned to CNX certain undeveloped Marcellus and Utica acreage in Southwest Pennsylvania, in exchange for CNX (x) assigning its interest in certain non-core midstream assets and surface acreage and (y) releasing certain HG Energy oil and gas acreage from dedication under a gathering agreement that is partially held, indirectly, by CNX. In connection with the transaction, CNX also agreed to certain transactions with CNXM, including the amendment of the existing gas gathering agreement between CNX and CNXM to increase the existing well commitment by an additional forty wells. The net gain on the sale was $286 and is included in the Gain on Asset Sales line of the Consolidated Statements of Income.

As a result of the AEA, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were acquired in connection with the Midstream Acquisition discussed below (see also Note 8 - Goodwill and Other Intangible Assets) exceeded their fair value, and recognized an impairment of approximately $18,650 which is included in the Impairment of Other Intangible Assets line of the Consolidated Statements of Income.

On March 30, 2018, CNX Gas completed the sale of substantially all of its shallow oil and gas assets and certain Coalbed Methane (CBM) assets in Pennsylvania and West Virginia for $89,296 in cash consideration. In connection with the sale, the buyer assumed approximately $196,514 of asset retirement obligations. The net gain on the sale was $4,751 and is included in Loss (Gain) on Asset Sales and Abandonments in the Consolidated Statements of Income.

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

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

The fair value assigned to the previously held equity interest in CNX Gathering and CNXM for purposes of calculating the gain or loss was $799,033 and was determined using the income approach, based on a discounted cash flow methodology. The resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $623,663 is included in Gain on Previously Held Equity Interest in the Consolidated Statements of Income.

The fair value of the previously held equity interests was based on inputs that are not observable in the market and therefore represent Level 3 inputs (See Note 14 - Fair Value of Financial Instruments). The fair value was measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation included estimates of: (i) gathering

volumes; (ii) future operating costs; and (iii) a market-based weighted average cost of capital. These inputs required significant judgments and estimates by management.

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

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

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

Allocation of Purchase Price (Midstream Acquisition)

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

Fair Value of Consideration Transferred:



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

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



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

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

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

Post-Acquisition Operating Results (Midstream Acquisition)

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Midstream Revenue	$	78,450	$	61,325	$	151,019	$	125,503
Earnings Before Income Tax	$	44,414	$	27,795	$	76,998	$	63,329

NOTE 6—INCOME TAXES:

The effective tax rates for the three and six months ended June 30, 2019 were 17.5% and 18.6%, respectively. The effective tax rate for the six months ended June 30, 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation and state income taxes.

The effective tax rates for the three and six months ended June 30, 2018 were (102.7)% and 23.1%, respectively. The effective rate for the six months ended June 30, 2018 differs from the U.S. federal statutory rate of 21% primarily due to a benefit from the filing of a Federal 10-year net operating loss ("NOL") carryback which resulted in the Company being able to utilize previously valued tax attributes at a tax rate differential of 14%, as well as non-controlling interest. The benefits were partially offset by increases for both state income taxes and state valuation allowances.

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

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

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

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

CNX and its subsidiaries file federal income tax returns with the United States and tax returns within various state jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2016. The Company expects the Internal Revenue Service to conclude its audit of tax years 2016 through 2017 in the third quarter of 2019.

NOTE 7—PROPERTY, PLANT AND EQUIPMENT:



	June 30, 2019		December 31, 2018
Property, Plant and Equipment
Intangible Drilling Cost	$	4,411,513	$	4,120,283
Proved Gas Properties	1,150,723		1,135,411
Gas Gathering Equipment	2,324,938		2,126,895
Unproved Gas Properties	946,114		927,667
Gas Wells and Related Equipment	983,214		859,359
Surface Land and Other Equipment	236,141		238,487
Other Gas Assets	150,846		159,326
Total Property, Plant and Equipment	10,203,489		9,567,428
Less: Accumulated Depreciation, Depletion and Amortization	2,863,627		2,624,984
Total Property, Plant and Equipment - Net	$	7,339,862	$	6,942,444

NOTE 8—GOODWILL AND OTHER INTANGIBLE ASSETS:

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

All goodwill is attributed to the Midstream reportable segment and there have been no changes in the carrying amount since the date of the Midstream Acquisition.

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



	June 30, 2019		December 31, 2018
Other Intangible Assets
Gross Amortizable Asset - Customer Relationships	$	109,752	$	109,752
Less: Accumulated Amortization - Customer Relationships	9,829		6,552
Total Other Intangible Assets, net	$	99,923	$	103,200

During the second quarter of 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets exceeded their fair value as a result of an Asset Exchange Agreement with HG Energy II Appalachia, LLC. Accordingly, CNX recognized an impairment on this intangible asset of $18,650. There were no such impairments in the current period.

Amortization expense related to other intangible assets for the three and six months ended June 30, 2019 was $1,639 and $3,277, respectively. Amortization expense for other intangible assets was $1,733 and $3,655 for the three and six months ended June 30, 2018, respectively.

The customer relationship intangible asset is being amortized on a straight-line basis over approximately 17 years. The estimated annual amortization expense is expected to approximate $6,552 per year for each of the next five years.

NOTE 9—REVOLVING CREDIT FACILITIES:

CNX Resources Corporation (CNX)

In April 2019, CNX amended its senior secured revolving credit facility ("Credit Facility"), and extended its maturity to April 2024. The lenders' commitments remained unchanged at $2,100,000, with an accordion feature that allows the Company to increase the commitments to $3,000,000. The borrowing base was reaffirmed at $2,100,000, including a $650,000 letters of credit aggregate sub-limit. In addition, the Cumulative Credit Basket for dividends and distributions was replaced with a basket for dividends and distributions subject to a pro forma net leverage ratio of at least 3.00 to 1.00 and availability under the credit facility of at least 15% of the aggregate commitments. If the aggregate principal amount of the existing 5.875% Senior Notes due in April 2022 and certain other publicly traded debt securities outstanding 91 days prior to the earliest maturity of such debt (the "Springing Maturity Date") is greater than $500,000, then the Credit Facility will mature on the Springing Maturity Date.

Under the terms of the amended agreement, borrowings under the revolving credit facility will bear interest at CNX's option at either:


•	the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, or (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.25% to 1.25%; or

•the LIBOR rate, which is the LIBOR rate plus a margin ranging from 1.25% to 2.25%.

The CNX Credit Facility is secured by substantially all of the assets of CNX and certain of its subsidiaries. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the Credit 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 CNX's proved natural gas reserves.

The CNX Credit Facility contains a number of affirmative and negative covenants including those that, except in certain circumstances, limit the Company and the subsidiary guarantors' ability to create, incur, assume or suffer to exist indebtedness, create or permit to exist liens on properties, dispose of assets, make investments, purchase or redeem CNX common stock, pay dividends, merge with another corporation and amend the senior unsecured notes. The Company must also mortgage 80% of the value of its proved reserves and 80% of the value of its proved developed producing reserves, in each case, which are included in the borrowing base, maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof, and enter into control agreements with respect to such applicable accounts.

The CNX Credit Facility contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants.

The CNX Credit Facility also requires that CNX maintain a maximum net leverage ratio of no greater than 4.00 to 1.00, which is calculated as the ratio of debt less cash on hand to consolidated EBITDA, measured quarterly. 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 borrowings under the revolver, measured quarterly. The calculation of all of the ratios exclude CNXM. CNX was in compliance with all financial covenants as of June 30, 2019.

At June 30, 2019, the CNX Credit Facility had $630,000 of borrowings outstanding and $198,581 of letters of credit outstanding, leaving $1,271,419 of unused capacity. At December 31, 2018, the Credit Facility had $612,000 of borrowings outstanding and $198,396 of letters of credit outstanding, leaving $1,289,604 of unused capacity.

CNX Midstream Partners LP (CNXM)

In April 2019, CNXM amended its senior secured revolving credit facility and extended its maturity to April 2024. The lenders’ commitments remained unchanged at $600,000, with an accordion feature that allows the Company to increase the available borrowings by up to an additional $250,000 under certain terms and conditions. Among other things, the revolving credit facility now includes (i) the addition of a restricted payment basket permitting cash repurchases of Incentive Distribution Rights (IDRs) subject to a secured leverage ratio of 3.00 to 1.00, a pro forma total leverage ratio of 4.00 to 1.00 and pro forma availability of 20% of commitments and (ii) a restricted payment basket for the repurchase of LP units not to exceed Available Cash (as defined in the partnership agreement) in any quarter, of up to $150,000 per year and up to $200,000 during the life of the facility.

Under the terms of the amended agreement, borrowings under the revolving credit facility will bear interest at CNXM's option at either:


•	the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, or (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.50% to 1.50%; or


•	the LIBOR rate, plus a margin ranging from 1.50% to 2.50%.

Fees and interest rate spreads under the CNXM credit facility are based on the total leverage ratio, measured quarterly. The CNXM credit facility includes the ability to issue letters of credit up to $100,000 in the aggregate.

The CNXM revolving credit facility contains a number of affirmative and negative covenants that include, among others, covenants that, except in certain circumstances, restrict the ability of CNXM, its subsidiary guarantors and certain of its non-guarantor, non-wholly-owned subsidiaries, except in certain circumstances, to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) prepay certain indebtedness unless there is no default or event of default under the revolving facility; (iv) make or pay any dividends or distributions in excess of certain amounts; (v) merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets; (vi) make particular investments and loans;

(vii) sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances; (viii) deal with any affiliate except in the ordinary course of business on terms no less favorable to CNXM than it would otherwise receive in an arm’s length transaction; and (ix) amend in any material manner its certificate of incorporation, bylaws, or other organizational documents without giving prior notice to the lenders and, in some cases, obtaining the consent of the lenders.

In addition, CNXM is obligated to maintain at the end of each fiscal quarter (w) for so long as at least $150,000 of the CNXM senior notes are outstanding, a maximum total leverage ratio of no greater than 5.25 to 1.00 (which increases to no greater than 5.50 to 1.00 during qualifying acquisition periods); (x) if less than $150,000 of the CNXM senior notes are outstanding, a maximum total leverage ratio of no greater than 4.75 to 1.00 (which increases to no greater than 5.25 to 1.00 during qualifying acquisition periods); (y) a maximum secured leverage ratio of no greater than 3.50 to 1.00 and (z) a minimum interest coverage ratio of no less than 2.50 to 1.00. CNXM was in compliance with all financial covenants as of June 30, 2019.

The CNXM revolving credit facility also contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under the revolving credit facility are secured by substantially all of the assets of CNXM and its wholly-owned subsidiaries. CNX is not a guarantor under the revolving credit facility.

At June 30, 2019, the CNXM credit facility had $208,000 of borrowings outstanding. CNXM had the maximum amount of revolving credit available for borrowing at June 30, 2019, or $392,000. At December 31, 2018, the CNXM credit facility had $84,000 of borrowings outstanding.

NOTE 10—LONG-TERM DEBT:



	June 30, 2019		December 31, 2018
Senior Notes due April 2022 at 5.875% (Principal of $894,307 and $1,294,307 plus Unamortized Premium of $1,215 and $2,069, respectively)	$	895,522	$	1,296,376
CNX Credit Facility	630,000		612,000
Senior Notes due March 2027 at 7.25%, Issued at Par Value	500,000		—
CNX Midstream Partners LP Senior Notes due March 2026 at 6.50% (Principal of $400,000 less Unamortized Discount of $5,000 and $5,375, respectively)	395,000		394,625
CNX Midstream Partners LP Revolving Credit Facility	208,000		84,000
Less: Unamortized Debt Issuance Costs	10,147		8,796
Long-Term Debt	$	2,618,375	$	2,378,205

During the six months ended June 30, 2019, CNX completed a private offering of $500,000 of 7.25% senior notes due in March 2027. The notes are guaranteed by most of CNX's subsidiaries but do not include CNXM's general partner or CNXM.

During the six months ended June 30, 2019, CNX purchased $400,000 of its outstanding 5.875% senior notes due in April 2022. As part of this transaction, a loss of $7,614 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income, which includes an adjustment to the final settlement amount of $77 that was included in Loss on Debt Extinguishment in the Consolidated Statements of Income during the three months ended June 30, 2019.

During the six months ended June 30, 2018, CNXM completed a private offering of $400,000 of 6.50% senior notes due in March 2026 less $6,000 of unamortized bond discount. CNX is not a guarantor of CNXM's 6.50% senior notes due in March 2026 or CNXM's senior secured revolving credit facility.

During the six months ended June 30, 2018, CNX purchased $391,375 of its outstanding 5.875% senior notes due in April 2022. As part of this transaction, a loss of $15,635 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income.

During the three and six months ended June 30, 2018, CNX purchased $300,000 of its outstanding 8.00% senior notes due in April 2023. As part of this transaction, a loss of $23,413 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income.

NOTE 11—LEASES:

On January 1, 2019, the Company adopted Accounting Standard Update (ASU) 2016-02, and all related amendments, using the transition method, which allows for a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. CNX has elected the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all leases that existed prior to the transition date. As a result, CNX did not reassess 1) whether existing or expired contracts contain leases 2) lease classification for any existing or expired leases or 3) whether lease origination costs qualified as initial direct costs. Additionally, the Company elected the short-term practical expedient for all asset classes by establishing an accounting policy to exclude leases with a term of 12 months or less. CNX will not separate lease components from non-lease components for any asset class. Lastly, CNX adopted the easement practical expedient, which allows the Company to apply ASC 842 prospectively to land easements after the adoption date. Easements that existed or expired prior to the adoption date that were not previously assessed under ASC 840 will not be reassessed.

CNX's leasing activities primarily consist of operating and finance leases for electric fracturing equipment, natural gas drilling rigs, CNX's corporate headquarters as well as field offices, a natural gas gathering pipeline and commercial vehicles. Some leases include options to renew ranging from a period of 1 to 10 years, which are not recognized as part of the lease right-of-use (ROU) assets or liabilities as they are not reasonably certain to be exercised.

Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of the lease payments over the lease term. As most of CNX's leases do not provide an implicit rate, an incremental borrowing rate is used to determine the present value of lease payments.

The components of lease cost were as follows:



	For the Three Months Ended		For the Six Months Ended
	June 30, 2019		June 30, 2019
Operating Lease Cost	$	21,441	$	31,356
Finance Lease Cost:
Amortization of Right-of-Use Assets	1,309		2,626
Interest on Lease Liabilities	324		676
Short-term Lease Cost	2,543		4,367
Variable Lease Cost*	7,539		11,539
Total Lease Cost	$	33,156	$	50,564

*Amounts recognized on the balance sheet for natural gas drilling rigs are measured using the rates that would be paid if the rigs were idle, as this represents the minimum payment that could be made under the contract. Variable lease cost represents amounts paid for natural gas drilling rigs above this minimum when the rigs are in use. Amounts recognized on the balance sheet for electric fracturing equipment are measured using minimum pumping hours under the contract; however, pumping hours may exceed the minimum and vary period to period. Any such amounts paid related to pumping hours in excess of the minimum represent variable lease cost.

Amounts recognized in the Consolidated Balance Sheet are as follows:



	June 30,
	2019
Operating Leases:
Operating Lease Right-of-Use Asset	$	224,950

Current Portion of Operating Lease Obligations	66,209
Operating Lease Obligations	137,464
Total Operating Lease Liabilities	$	203,673

Finance Leases:
Property, Plant and Equipment	$	72,932
Less—Accumulated Depreciation, Depletion and Amortization	61,102
Property, Plant and Equipment—Net	$	11,830

Current Portion of Finance Lease Obligations	$	7,133
Finance Lease Obligations	10,569
Total Finance Lease Liabilities	$	17,702

Supplemental cash flow information related to leases was as follows:



	For the Six Months Ended
	June 30, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating Cash Flows from Operating Leases	$	21,153
Operating Cash Flows from Finance Leases	$	676
Financing Cash Flows from Finance Leases	$	3,515
Right-of-Use Assets Obtained in Exchange for Lease Obligations:
Operating Leases	$	15,347
Finance Leases	$	994

Maturities of lease liabilities are as follows:



	Operating		Finance
	Leases		Leases
Twelve months ended June 30,
2020	$	74,712	$	8,171
2021	59,536		7,627
2022	51,288		3,258
2023	5,465		243
2024	5,446		128
Thereafter	33,257		—
Total Lease Payments	229,704		19,427
Less: Interest	26,031		1,725
Present Value of Lease Liabilities	$	203,673	$	17,702

Lease terms and discount rates are as follows:



	June 30,
	2019
Weighted Average Remaining Lease Term (years):
Operating Leases	4.54
Finance Leases	2.47

Weighted Average Discount Rate:
Operating Leases	4.94	%
Finance Leases	7.10	%

NOTE 12—COMMITMENTS AND CONTINGENT LIABILITIES:

CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, royalty accounting, damage to property, 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. 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 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 CNX; however, such amounts cannot be reasonably estimated.

At June 30, 2019, CNX has provided the following financial guarantees, unconditional purchase obligations, and letters of credit to certain third-parties as described by major category in the following 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 unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management believes that the commitments in the following table will expire without being funded, and therefore will not have a material adverse effect on financial condition.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Firm Transportation	$	198,316	$	162,443	$	35,873	$	—	$	—
Other	265		265		—		—		—
Total Letters of Credit	198,581		162,708		35,873		—		—
Surety Bonds:
Employee-Related	1,850		1,850		—		—		—
Environmental	11,296		11,237		59		—		—
Financial Guarantees	81,670		81,670		—		—		—
Other	9,337		7,840		1,497		—		—
Total Surety Bonds	104,153		102,597		1,556		—		—
Total Commitments	$	302,734	$	265,305	$	37,429	$	—	$	—

Excluded from the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business (See CNX's 2018 Annual Report on Form 10-K as filed with the SEC on February 7, 2019 for further information). Although CONSOL Energy has 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 Energy will satisfy its obligations to indemnify CNX in the event that CNX is so called upon.

CNX 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 in the Consolidated Balance Sheets. As of June 30, 2019, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	251,384
1 - 3 years	492,206
3 - 5 years	423,726
More than 5 years	1,159,534
Total Purchase Obligations	$	2,326,850

NOTE 13—DERIVATIVE INSTRUMENTS:

In June 2019, CNX entered into an interest rate swap agreement to manage its exposure to interest rate volatility. The interest rate swap agreement relates to $160,000 of borrowings under CNX’s senior secured revolving credit facility (See Note 9 - Revolving Credit Facilities) and has the economic effect of modifying the variable-interest obligation into a fixed-interest obligation over a three-year period.

The change in fair value of the interest rate swap agreement is accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings. The fair value at June 30, 2019 and the corresponding change in fair value from inception through June 30, 2019 was nominal.

CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. These natural gas commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings.

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 CNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if 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, 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. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis.

Each of 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, CNX and the applicable counterparty would net settle all open hedge positions.

The total notional amounts of production of CNX's derivative instruments were as follows:



	June 30,	December 31,	Forecasted to
	2019	2018	Settle Through
Natural Gas Commodity Swaps (Bcf)	1,515.8	1,484.4	2024
Natural Gas Basis Swaps (Bcf)	1,166.1	1,056.6	2024

The gross fair value of CNX's derivative instruments was as follows:



Asset Derivative Instruments					Liability Derivative Instruments
	June 30,		December 31,			June 30,		December 31,
	2019		2018			2019		2018
Commodity Swaps:
Prepaid Expense	$	144,771	$	28,612	Other Accrued Liabilities	$	1,606	$	34,640
Other Assets	176,794		164,310		Other Liabilities	37,603		52,011
Total Asset	$	321,565	$	192,922	Total Liability	$	39,209	$	86,651

Basis Only Swaps:
Prepaid Expense	$	4,934	$	11,628	Other Accrued Liabilities	$	46,250	$	27,021
Other Assets	13,225		48,788		Other Liabilities	97,893		40,210
Total Asset	$	18,159	$	60,416	Total Liability	$	144,143	$	67,231

The effect of 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,
	2019			2018			2019			2018
Cash Received (Paid) in Settlement of Commodity Derivative Instruments:
Natural Gas:
Commodity Swaps	$	18,567		$	17,058		$	(8,383	)	$	16,624
Basis Swaps	(7,895		)	(374		)	(22,327		)	(16,931		)
Total Cash Received (Paid) in Settlement of Commodity Derivative Instruments	10,672			16,684			(30,710		)	(307		)

Unrealized Gain (Loss) on Commodity Derivative Instruments:
Natural Gas:
Commodity Swaps	226,845			46,450			176,084			49,250
Basis Swaps	(15,936		)	(37,474		)	(119,169		)	11,804
Total Unrealized Gain on Commodity Derivative Instruments	210,909			8,976			56,915			61,054

Gain (Loss) on Commodity Derivative Instruments:
Natural Gas:
Commodity Swaps	245,412			63,508			167,701			65,874
Basis Swaps	(23,831		)	(37,848		)	(141,496		)	(5,127		)
Total Gain on Commodity Derivative Instruments	$	221,581		$	25,660		$	26,205		$	60,747

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—FAIR VALUE OF FINANCIAL INSTRUMENTS:

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 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 1 - Quoted prices for identical instruments in active markets.

Level 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 discount rates and basis forward curves.

Level 3 - Unobservable inputs significant to the fair value measurement supported by little or no market activity.

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 instrument measured at fair value on a recurring basis is summarized below:



	Fair Value Measurements at June 30, 2019						Fair Value Measurements at December 31, 2018
Description	(Level 1)		(Level 2)		(Level 3)		(Level 1)		(Level 2)		(Level 3)
Gas Derivatives	$	—	$	156,372	$	—	$	—	$	99,456	$	—

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



	June 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and Cash Equivalents	$	32,611	$	32,611	$	17,198	$	17,198
Long-Term Debt (Excluding Debt Issuance Costs)	$	2,628,522	$	2,495,223	$	2,387,001	$	2,290,537

Cash and cash equivalents represent 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.

NOTE 15—VARIABLE INTEREST ENTITIES:

The Company determined CNXM, of which the Company owns an approximately 34% limited partner interest, to be a variable interest entity. As a result of the Midstream Acquisition (see Note 5 - Acquisitions and Dispositions), the Company has the power through the Company's ownership and control of CNXM's general partner (CNX Midstream GP LLC) to direct the activities that most significantly impact CNXM's economic performance. In addition, through its limited partner interest and incentive distribution rights, or IDRs, in CNXM, the Company has the obligation to absorb the losses of CNXM and the right to receive benefits in accordance with such interests. As the Company has a controlling financial interest and is the primary beneficiary of CNXM, the Company consolidated CNXM commencing January 3, 2018.

The risks associated with the operations of CNXM are discussed in its Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on February 7, 2019.

The following table presents amounts included in the Company's Consolidated Balance Sheets that were for the use or obligation of CNXM:



	June 30,		December 31,
	2019		2018
Assets:
Cash	$	11,677	3,966
Receivables - Related Party	19,028		17,073
Receivables - Third Party	6,681		7,028
Other Current Assets	1,648		2,383
Property, Plant and Equipment, net	1,076,977		891,775
Operating Lease ROU Asset	7,875		—
Other Assets	3,731		3,203
Total Assets	$	1,127,617	$	925,428
Liabilities:
Accounts Payable and Accrued Liabilities	$	96,295	$	43,919
Accounts Payable - Related Party	3,425		4,980
Revolving Credit Facility	208,000		84,000
Long-Term Debt	393,688		393,215
Long-Term Operating Lease Liabilities	1,171		—
Total Liabilities	$	702,579	$	526,114

The following table summarizes CNXM's Consolidated Statements of Operations and Cash Flows, inclusive of affiliate amounts:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Revenue
Gathering Revenue - Related Party	$	59,205		$	37,576		$	112,981		$	75,306
Gathering Revenue - Third Party	18,896			23,438			37,339			49,577
Total Revenue	78,101			61,014			150,320			124,883
Expenses
Operating Expense - Related Party	6,514			5,079			12,062			9,514
Operating Expense - Third Party	6,188			7,406			12,162			15,874
General and Administrative Expense - Related Party	4,027			3,620			7,994			7,232
General and Administrative Expense - Third Party	1,364			2,319			2,900			4,868
(Gain) Loss on Asset Sales and Abandonments	—			(254		)	7,229			2,501
Depreciation Expense	5,860			5,443			11,510			11,299
Interest Expense	7,685			7,119			15,024			9,608
Total Expense	31,638			30,732			68,881			60,896
Net Income	$	46,463		$	30,282		$	81,439		$	63,987

Net Cash Provided by Operating Activities	$	74,753		$	53,674		$	124,666		$	95,541
Net Cash Used in Investing Activities	$	(104,310	)	$	(24,969	)	$	(182,867	)	$	(35,125	)
Net Cash Provided by (Used in) Financing Activities	$	41,164		$	(29,964	)	$	65,912		$	(62,903	)

In March 2018, CNXM closed on its acquisition of CNX's remaining 95% interest in the gathering system and related assets commonly referred to as the Shirley-Penns System, in exchange for cash consideration in the amount of $265,000. CNXM funded the cash consideration with proceeds from the issuance of its 6.50% senior notes due 2026 (See Note 10 - Long-Term Debt).

At June 30, 2019 and December 31, 2018, CNX had a net payable of $15,584 and $12,202 respectively, due to CNX Gathering and CNXM, primarily for accrued but unpaid gathering services.

NOTE 16—SEGMENT INFORMATION:

CNX consists of two principal business divisions: Exploration and Production (E&P) and Midstream. The principal activity of the E&P Division, which includes four reportable segments, is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P Division's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas. The Other Gas Segment is primarily related to shallow oil and gas production which is not significant to the Company due to sale of substantially all of CNX's shallow oil and gas assets in the 2018 period (See Note 5 - Acquisitions and Dispositions for more information). It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, as well as various other operating activities assigned to the E&P Division but not allocated to each individual segment.

CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets of CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third-parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM. As a result of the Midstream Acquisition (See Note 5 - Acquisitions and Dispositions for more information), CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus the Company began consolidating CNXM on January 3, 2018.

The Company's unallocated expenses include other expense, gain on asset sales related to non-core assets, gain on previously held equity interest, loss on debt extinguishment, impairment of other intangible assets and income taxes.

In the preparation of the following information, intersegment sales have been recorded at amounts approximating market prices. 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 CNX, 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.

Industry segment results for the three months ended June 30, 2019:



	Marcellus Shale		Utica Shale		Coalbed Methane		Other Gas		Total E&P		Midstream		Unallocated		Intercompany Eliminations			Consolidated
Natural Gas, NGLs and Oil Revenue	$	237,257	$	65,213	$	39,638	$	757	$	342,865	$	—	$	—	$	—		$	342,865	(A)
Purchased Gas Revenue	—		—		—		18,768		18,768		—		—		—			18,768
Midstream Revenue	—		—		—		—		—		78,450		—		(59,555		)	18,895
Gain on Commodity Derivative Instruments	6,831		2,747		1,085		210,918		221,581		—		—		—			221,581
Other Operating Income	—		—		—		3,038		3,038		—		—		(115		)	2,923		(B)
Total Revenue and Other Operating Income	$	244,088	$	67,960	$	40,723	$	233,481	$	586,252	$	78,450	$	—	$	(59,670	)	$	605,032
Earnings Before Income Tax	$	50,381	$	17,941	$	7,603	$	112,335	$	188,260	$	44,414	$	811	$	—		$	233,485
Segment Assets									$	6,887,043	$	2,116,492	$	146,203	$	(3,041	)	$	9,146,697	(C)
Depreciation, Depletion and Amortization									$	120,705	$	8,294	$	—				$	128,999
Capital Expenditures									$	224,684	$	104,543	$	—	$	—		$	329,227


(A)	Included in Total Natural Gas, NGLs and Oil Revenue are sales of $48,476 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with customers for the period.


(B)	Includes equity in earnings of unconsolidated affiliates of $527 for Total E&P.


(C)	Includes investments in unconsolidated equity affiliates of $17,637 for Total E&P.

Industry segment results for the three months ended June 30, 2018:



	Marcellus Shale		Utica Shale		Coalbed Methane		Other Gas			Total E&P		Midstream		Unallocated			Intercompany Eliminations			Consolidated
Natural Gas, NGLs and Oil Revenue	$	178,305	$	107,758	$	46,882	$	1,572		$	334,517	$	—	$	—		$	—		$	334,517	(D)
Purchased Gas Revenue	—		—		—		9,930			9,930		—		—			—			9,930
Midstream Revenue	—		—		—		—			—		61,325		—			(37,842		)	23,483
Gain on Commodity Derivative Instruments	9,128		5,371		2,155		9,006			25,660		—		—			—			25,660
Other Operating Income	—		—		—		8,595			8,595		—		—			(61		)	8,534		(E)
Total Revenue and Other Operating Income	$	187,433	$	113,129	$	49,037	$	29,103		$	378,702	$	61,325	$	—		$	(37,903	)	$	402,124
Earnings (Loss) Before Income Tax	$	47,273	$	46,486	$	12,405	$	(64,039	)	$	42,125	$	27,795	$	(39,628	)	$	—		$	30,292
Segment Assets										$	6,055,545	$	1,830,007	$	333,372		$	(11,166	)	$	8,207,758	(F)
Depreciation, Depletion and Amortization										$	111,125	$	7,962	$	—		$	—		$	119,087
Capital Expenditures										$	238,889	$	25,285	$	—		$	—		$	264,174


(D)	Included in Total Natural Gas, NGLs and Oil Revenue are sales of $36,849 to NJR Energy Services Company and $34,644 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with customers for the period.


(E)	Includes equity in earnings of unconsolidated affiliates of $1,669 for Total E&P.


(F)	Includes investments in unconsolidated equity affiliates of $22,347 for Total E&P.

Industry segment results for the six months ended June 30, 2019:



	Marcellus Shale			Utica Shale			Coalbed Methane			Other Gas			Total E&P		Midstream		Unallocated			Intercompany Eliminations			Consolidated
Natural Gas, NGLs and Oil Revenue	$	530,514		$	158,164		$	89,473		$	660		$	778,811	$	—	$	—		$	—		$	778,811	(A)
Purchased Gas Revenue	—			—			—			34,989			34,989		—		—			—			34,989
Midstream Revenue	—			—			—			—			—		151,019		—			(113,681		)	37,338
(Loss) Gain on Commodity Derivative Instruments	(20,627		)	(6,854		)	(3,217		)	56,903			26,205		—		—			—			26,205
Other Operating Income	—			—			—			6,296			6,296		—		—			(176		)	6,120		(B)
Total Revenue and Other Operating Income	$	509,887		$	151,310		$	86,256		$	98,848		$	846,301	$	151,019	$	—		$	(113,857	)	$	883,463
Earnings (Loss) Before Income Tax	$	137,312		$	49,945		$	20,502		$	(125,929	)	$	81,830	$	76,998	$	(1,553	)	$	—		$	157,275
Segment Assets													$	6,887,043	$	2,116,492	$	146,203		$	(3,041	)	$	9,146,697	(C)
Depreciation, Depletion and Amortization													$	237,780	$	16,379	$	—		$	—		$	254,159
Capital Expenditures													$	448,475	$	179,890	$	—		$	—		$	628,365


(A)	Included in Total Natural Gas, NGLs and Oil Revenue are sales of $116,245 to Direct Energy Business Marketing LLC and $94,447 to NJR Energy Services Company, each of which comprise over 10% of revenue from contracts with customers for the period.


(B)	Includes equity in earnings of unconsolidated affiliates of $1,030 for Total E&P.


(C)	Includes investments in unconsolidated equity affiliates of $17,637 for Total E&P.

Industry segment results for the six months ended June 30, 2018:



	Marcellus Shale			Utica Shale		Coalbed Methane			Other Gas			Total E&P		Midstream		Unallocated		Intercompany Eliminations			Consolidated
Natural Gas, NGLs and Oil Revenue	$	383,321		$	238,080	$	104,383		$	14,356		$	740,140	$	—	$	—	$	—		$	740,140	(D)
Purchased Gas Revenue	—			—		—			27,985			27,985		—		—		—			27,985
Midstream Revenue	—			—		—			—			—		125,503		—		(75,766		)	49,737
(Loss) Gain on Commodity Derivative Instruments	(385		)	897		(275		)	60,510			60,747		—		—		—			60,747
Other Operating Income	—			—		—			19,386			19,386		—		—		(142		)	19,244		(E)
Total Revenue and Other Operating Income	$	382,936		$	238,977	$	104,108		$	122,237		$	848,258	$	125,503	$	—	$	(75,908	)	$	897,853
Earnings (Loss) Before Income Tax	$	91,515		$	102,593	$	25,522		$	(77,695	)	$	141,935	$	63,329	$	584,268	$	—		$	789,532
Segment Assets												$	6,055,545	$	1,830,007	$	333,372	$	(11,166	)	$	8,207,758	(F)
Depreciation, Depletion and Amortization												$	226,991	$	16,763	$	—	$	—		$	243,754
Capital Expenditures												$	455,397	$	41,262	$	—	$	—		$	496,659


(D)	Included in Total Natural Gas, NGLs and Oil Revenue are sales of $115,845 to NJR Energy Services Company and $92,571 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with customers for the period.


(E)	Includes equity in earnings of unconsolidated affiliates of $3,447 for Total E&P.


(F)	Includes investments in unconsolidated equity affiliates of $22,347 for Total E&P.

Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Operating Income



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Total Segment Revenue from Contracts with External Customers	$	380,528	$	367,930	$	851,138	$	817,862
Gain on Commodity Derivative Instruments	221,581		25,660		26,205		60,747
Other Operating Income	2,923		8,534		6,120		19,244
Total Consolidated Revenue and Other Operating Income	$	605,032	$	402,124	$	883,463	$	897,853

Earnings Before Income Tax:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Segment Income Before Income Taxes for Reportable Business Segments:
Total E&P	$	188,260		$	42,125		$	81,830		$	141,935
Midstream	44,414			27,795			76,998			63,329
Total Segment Income Before Income Taxes for Reportable Business Segments	$	232,674		$	69,920		$	158,828		$	205,264
Unallocated Expenses:
Other Income (Expense)	501			(575		)	1,531			5,917
Gain on Certain Asset Sales	387			3,010			4,530			12,386
Gain on Previously Held Equity Interest	—			—			—			623,663
Loss on Debt Extinguishment	(77		)	(23,413		)	(7,614		)	(39,048		)
Impairment of Other Intangible Assets	—			(18,650		)	—			(18,650		)
Earnings Before Income Tax	$	233,485		$	30,292		$	157,275		$	789,532

Total Assets:



	June 30,
	2019			2018
Segment Assets for Total Reportable Business Segments:
E&P	$	6,887,043		$	6,055,545
Midstream	2,116,492			1,830,007
Intercompany Eliminations	(3,041		)	(11,166		)
Items Excluded from Segment Assets:
Cash and Cash Equivalents	32,611			54,846
Recoverable Income Taxes	113,592			27,780
Assets Held for Sale	—			250,746
Total Consolidated Assets	$	9,146,697		$	8,207,758

NOTE 17—STOCK REPURCHASE:

Since the October 30, 2017 inception of the current stock repurchase program, CNX's Board of Directors has approved in total a $750,000 stock repurchase program, which is not subject to an expiration date. The repurchases may be 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 stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans. During the six months ended June 30, 2019, 11,929,487 shares were repurchased and retired at an average price of $9.01 per share for a total cost of $107,780.

NOTE 18—RECENT ACCOUNTING PRONOUNCEMENTS:

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02 - Leases (Topic 842), which increases transparency and comparability among organizations by recognizing ROU lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 maintains 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 remain similar to the previous accounting treatment. A lessee is permitted to make an accounting policy election by class of underlying asset to exclude from balance sheet recognition any ROU lease assets and lease liabilities with a term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the ROU asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position. As discussed in Note 11 - Leases, the Company adopted Update 2016-02 as of January 1, 2019.

In May 2019, the FASB issued ASU 2019-05 - Financial Instruments - Credit Losses (Topic 326), which provides optional targeted transition relief to entities adopting ASU 2016-13. ASU 2016-13 replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. ASU 2019-05 provides the option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost basis. For those entities, the targeted transition relief will increase comparability of financial statement information by providing an option to align measurement methodologies for similar financial assets. The amendments in this ASU will be applied using the modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and interim periods within those annual periods. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.


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

General

During the second quarter of 2019, CNX sold 134.5 Bcfe of natural gas, an increase of 9.7% from the 122.6 Bcfe sold in the year-earlier quarter, primarily due to an increase in Marcellus Shale volumes. The increase was offset, in part, by a decrease in Utica Shale volumes due to the sale of substantially all of CNX's Ohio Utica joint venture ("JV") assets in the third quarter of 2018. Total quarterly production costs increased to $2.07 per Mcfe, compared to the year-earlier quarter of $2.00 per Mcfe, driven primarily by increases in transportation, gathering and compression, offset, in part, by reductions in lease operating expense. Capital expenditures increased to $329 million in the second quarter of 2019, compared to $264 million of spend in the second quarter of 2018.

Marketing Update:

For the second quarter of 2019, CNX's average sales price for natural gas, natural gas liquids (NGLs), oil, and condensate was $2.63 per Mcfe. The average realized price for all liquids for the second quarter of 2019 was $19.14 per barrel.

CNX's weighted average differential from NYMEX in the second quarter of 2019 was negative $0.31 per MMBtu. CNX's average sales price for natural gas before hedging decreased 21.8% to $2.51 per Mcf compared with the average sales price of $3.21 per Mcf in the first quarter of 2019. This decrease resulted primarily from a lower Henry Hub price reflecting current general market conditions coupled with a wider differential. Including the impact of cash settlements from hedging, CNX's average sales price for natural gas was $0.11 per Mcf, or 4.1%, lower than last year's second quarter.

CNX Guidance:

CNX updates 2019 production volumes to 510-530 Bcfe, compared to the previous guidance of 495-515 Bcfe. CNX updates 2020 production volumes to 570-595 Bcfe, which equates to an approximately 12% annual increase, based on the midpoint of guidance.

Total hedged natural gas production in the 2019 third quarter is 103.9 Bcf. The annual gas hedge position is shown in the table below:



	2019	2020
Volumes Hedged (Bcf), as of 7/8/19	396.6*	470.5

^*Includes actual settlements of 205.8 Bcf.

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

Results of Operations - Three Months Ended June 30, 2019 Compared with Three Months Ended June 30, 2018

Net Income Attributable to CNX Resources Shareholders

CNX reported net income attributable to CNX Resources shareholders of $162 million, or earnings per diluted share of $0.84 for the three months ended June 30, 2019, compared to net income attributable to CNX Resources shareholders of $42 million, or earnings per diluted share of $0.19, for the three months ended June 30, 2018.



	For the Three Months Ended June 30,
(Dollars in thousands)	2019		2018		Variance
Net Income	$	192,694	$	61,394	$	131,300
Less: Net Income Attributable to Noncontrolling Interest	30,217		19,380		10,837
Net Income Attributable to CNX Resources Shareholders	$	162,477	$	42,014	$	120,463

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

The principal activity of the E&P Division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P Division's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas.

CNX's E&P Division had earnings before income tax of $188 million for the three months ended June 30, 2019, compared to earnings before income tax of $42 million for the three months ended June 30, 2018. Included in the 2019 earnings was an unrealized gain on commodity derivative instruments of $211 million. Included in the 2018 earnings was an unrealized gain on commodity derivative instruments of $9 million.

CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets, through CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third-parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM.

CNX's Midstream Division had earnings before income tax of $44 million for the three months ended June 30, 2019, compared to earnings before income tax of $28 million for the three months ended June 30, 2018.

E&P Division Summary

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



	For the Three Months Ended June 30,
	2019		2018		Variance			Percent Change
Sales Volumes (Bcfe)	134.5		122.6		11.9			9.7	%

Average Sales Price (per Mcfe)	$	2.63	$	2.87	$	(0.24	)	(8.4	)%
Lease Operating Expense (per Mcfe)	0.15		0.21		(0.06		)	(28.6	)%
Production, Ad Valorem, and Other Fees (per Mcfe)	0.05		0.06		(0.01		)	(16.7	)%
Transportation, Gathering and Compression (per Mcfe)	0.98		0.82		0.16			19.5	%
Depreciation, Depletion and Amortization (DD&A) (per Mcfe)	0.89		0.91		(0.02		)	(2.2	)%
Average Costs (per Mcfe)	2.07		2.00		0.07			3.5	%
Average Margin (per Mcfe)	$	0.56	$	0.87	$	(0.31	)	(35.6	)%

Natural gas, NGLs, and oil revenue was $343 million for the three months ended June 30, 2019, compared to $335 million for the three months ended June 30, 2018. The increase was primarily due to the 9.7% increase in total sales volumes, offset in part by the decrease in natural gas pricing, when excluding the impact of hedging, as well as a decrease in NGL pricing.

The decrease in average sales price per Mcfe was the result of the $0.07 per Mcf decrease in the realized gain on commodity derivative instruments related to the Company's hedging program, a $0.14 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging, and a $0.04 per Mcf decrease in general natural gas prices, in the markets in which CNX sells its natural gas, during the current period.

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


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

•

Transportation, gathering, and compression expense increased on a per-unit basis primarily due to an increase in CNXM gathering fees related to an increase in our Marcellus production and an increase in firm transportation expense primarily as a result of new contracts that give CNX the ability to move and sell natural gas outside of the Appalachian basin. The decrease in production from CNX's lower cost dry Utica volumes also contributed to the increase on a per unit basis.

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



	For the Three Months Ended June 30,
in thousands (unless noted)	2019		2018		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	7,855		8,365		(510		)	(6.1	)%
Sales Volume (Mbbls)	1,309		1,394		(85		)	(6.1	)%
Gross Price ($/Bbl)	$	18.36	$	28.38	$	(10.02	)	(35.3	)%
Gross Revenue	$	24,025	$	39,557	$	(15,532	)	(39.3	)%

Oil:
Sales Volume (MMcfe)	10		69		(59		)	(85.5	)%
Sales Volume (Mbbls)	2		11		(9		)	(81.8	)%
Gross Price ($/Bbl)	$	50.52	$	58.32	$	(7.80	)	(13.4	)%
Gross Revenue	$	89	$	670	$	(581	)	(86.7	)%

Condensate:
Sales Volume (MMcfe)	222		528		(306		)	(58.0	)%
Sales Volume (Mbbls)	37		88		(51		)	(58.0	)%
Gross Price ($/Bbl)	$	45.36	$	56.82	$	(11.46	)	(20.2	)%
Gross Revenue	$	1,680	$	4,996	$	(3,316	)	(66.4	)%

GAS
Sales Volume (MMcf)	126,378		113,599		12,779			11.2	%
Sales Price ($/Mcf)	$	2.51	$	2.55	$	(0.04	)	(1.6	)%
Gross Revenue	$	317,071	$	289,294	$	27,777		9.6	%

Hedging Impact ($/Mcf)	$	0.08	$	0.15	$	(0.07	)	(46.7	)%
Gain on Commodity Derivative Instruments - Cash Settlement	10,672		16,684		(6,012		)	(36.0	)%

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

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



	For the Three Months Ended June 30,
(in millions)	2019		2018		Variance			Percent Change
SG&A
Salaries and Wages	$	10	$	10	$	—		—	%
Long-Term Equity-Based Compensation (Non-Cash)	24		6		18			300.0	%
Short-Term Incentive Compensation	3		6		(3		)	(50.0	)%
Other	12		13		(1		)	(7.7	)%
Total SG&A	$	49	$	35	$	14		40.0	%

Long-Term Equity-Based Compensation - During the three months ended June 30, 2019, the Company incurred $20 million of additional long-term equity-based compensation (non-cash) expense, which is included in Selling, General, and Administrative Costs in the Consolidated Statements of Income, as a result of the acceleration of vesting of certain restricted stock units and performance share units held by certain employees. The expense related to the restricted stock units is based on the closing stock price on the grant date, and the expense related to the performance share units is based upon a Monte Carlo valuation as of the grant date, with any payout of such performance share units continuing to be subject to the attainment of performance goals (total shareholder return relative to the S&P 500 index and absolute stock price growth). As of June 30, 2019, in order for the expense to result in equivalent value for these certain employees, the Company stock price would have to rebound materially. See Note 2 - Earnings Per Share in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information

Unallocated Expense

Certain costs and expenses, such as other (income) expense, (gain) loss on asset sales and abandonments related to non-core assets, loss on debt extinguishment, impairment of other intangible assets and income taxes are unallocated expenses and therefore are excluded from the per unit costs above as well as segment reporting. Below is a summary of these costs and expenses:

Other (Income) Expense



	For the Three Months Ended June 30,
(in millions)	2019		2018			Variance			Percent Change
Other Income
Royalty Income	$	1	$	3		$	(2	)	(66.7	)%
Right of Way Sales	3		1			2			200.0	%
Other	1		2			(1		)	(50.0	)%
Total Other Income	$	5	$	6		$	(1	)	(16.7	)%

Other Expense
Professional Services	$	1	$	1		$	—		—	%
Bank Fees	3		3			—			—	%
Other Corporate Expense	1		3			(2		)	(66.7	)%
Total Other Expense	$	5	$	7	—	$	(2	)	(28.6	)%

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

(Gain) Loss on Asset Sales and Abandonments

A nominal gain on asset sales related to non-core assets was recognized in the three months ended June 30, 2019 compared to a gain of $3 million in the three months ended June 30, 2018. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Loss on Debt Extinguishment

Loss on debt extinguishment was nominal in the three months ended June 30, 2019 compared to a loss on debt extinguishment of $23 million in the three months ended June 30, 2018. During the three months end June 30, 2018, CNX purchased $300 million of its 8.00% Senior notes due in April 2023 at an average price equal to 106.0% of the principal amount. See Note 10 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Impairment of Other Intangible Assets

Intangible assets are tested for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized when the carrying amount of the asset exceeds the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. The impairment loss to be recorded would be the excess of the asset's carrying value over its fair value.

In connection with the AEA with HG Energy (See Note 5 - Acquisition and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) that occurred during the three months ended June 30, 2018, CNX determined that the carrying value of the other intangible asset - customer relationship exceeded its fair value, and an impairment of $19 million was included in Impairment of Other Intangible Assets in the Consolidated Statement of Income. No such transactions occurred in the current period.

Income Taxes

The effective income tax rate was 17.5% for the three months ended June 30, 2019 compared to (102.7)% for the three months ended June 30, 2018. The effective rate for the three months ended June 30, 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation, and state income taxes. The effective rate for the three months ended June 30, 2018 differs from the U.S. federal statutory rate of 21% primarily due to a benefit from the filing of a federal 10-year net operating loss ("NOL") carryback which resulted in the Company being able to utilize previously valued tax attributes at a tax rate differential of 14%, as well as non-controlling interest. The benefits were partially offset by increases for both state income taxes and state valuation allowances.

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



	For the Three Months Ended June 30,
(in millions)	2019			2018			Variance			Percent Change
Total Company Earnings Before Income Tax	$	233		$	30		$	203		676.7	%
Income Tax Expense (Benefit)	$	41		$	(31	)	$	72		(232.3	)%
Effective Income Tax Rate	17.5		%	(102.7		)%	120.2		%

TOTAL E&P DIVISION ANALYSIS for the three months ended June 30, 2019 compared to the three months ended June 30, 2018:

The E&P division had earnings before income tax of $188 million for the three months ended June 30, 2019 compared to earnings before income tax of $42 million for the three months ended June 30, 2018. Variances by individual E&P segment are discussed below.



	For the Three Months Ended											Difference to Three Months Ended
	June 30, 2019											June 30, 2018
(in millions)	Marcellus		Utica		CBM		Other Gas			Total E&P		Marcellus			Utica			CBM			Other Gas			Total E&P
Natural Gas, NGLs and Oil Revenue	$	237	$	66	$	40	$	—		$	343	$	59		$	(42	)	$	(7	)	$	(2	)	$	8
Gain on Commodity Derivative Instruments	7		2		1		211			221		(2		)	(3		)	(1		)	201			195
Purchased Gas Revenue	—		—		—		19			19		—			—			—			9			9
Other Operating Income	—		—		—		3			3		—			—			—			(5		)	(5		)
Total Revenue and Other Operating Income	244		68		41		233			586		57			(45		)	(8		)	203			207
Lease Operating Expense	11		4		4		1			20		—			(5		)	(1		)	1			(5		)
Production, Ad Valorem, and Other Fees	4		2		2		(1		)	7		(1		)	—			—			—			(1		)
Transportation, Gathering and Compression	114		8		10		—			132		41			(8		)	(1		)	(1		)	31
Depreciation, Depletion and Amortization	65		36		17		3			121		14			(4		)	(2		)	2			10
Exploration and Production Related Other Costs	—		—		—		5			5		—			—			—			1			1
Purchased Gas Costs	—		—		—		19			19		—			—			—			9			9
Other Operating Expense	—		—		—		18			18		—			—			—			—			—
Selling, General and Administrative Costs	—		—		—		44			44		—			—			—			15			15
Total Operating Costs and Expenses	194		50		33		89			366		54			(17		)	(4		)	27			60
Interest Expense	—		—		—		32			32		—			—			—			1			1
Total E&P Division Costs	194		50		33		121			398		54			(17		)	(4		)	28			61
Earnings Before Income Tax	$	50	$	18	$	8	$	112		$	188	$	3		$	(28	)	$	(4	)	$	175		$	146

MARCELLUS SEGMENT

The Marcellus segment had earnings before income tax of $50 million for the three months ended June 30, 2019 compared to earnings before income tax of $47 million for the three months ended June 30, 2018.



	For the Three Months Ended June 30,
	2019		2018		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	84.3		58.0		26.3			45.3	%
NGLs Sales Volumes (Bcfe)*	7.9		6.3		1.6			25.4	%
Condensate Sales Volumes (Bcfe)*	0.2		0.4		(0.2		)	(50.0	)%
Total Marcellus Sales Volumes (Bcfe)*	92.4		64.7		27.7			42.8	%

Average Sales Price - Gas (per Mcf)	$	2.51	$	2.47	$	0.04		1.6	%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	0.08	$	0.16	$	(0.08	)	(50.0	)%
Average Sales Price - NGLs (per Mcfe)*	$	3.06	$	4.95	$	(1.89	)	(38.2	)%
Average Sales Price - Condensate (per Mcfe)*	$	7.52	$	9.32	$	(1.80	)	(19.3	)%

Total Average Marcellus Sales Price (per Mcfe)	$	2.64	$	2.90	$	(0.26	)	(9.0	)%
Average Marcellus Lease Operating Expenses (per Mcfe)	0.12		0.16		(0.04		)	(25.0	)%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)	0.04		0.07		(0.03		)	(42.9	)%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)	1.24		1.13		0.11			9.7	%
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)	0.69		0.81		(0.12		)	(14.8	)%
Total Average Marcellus Costs (per Mcfe)	$	2.09	$	2.17	$	(0.08	)	(3.7	)%
Average Margin for Marcellus (per Mcfe)	$	0.55	$	0.73	$	(0.18	)	(24.7	)%

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

The Marcellus segment had natural gas, NGLs and oil revenue of $237 million for the three months ended June 30, 2019 compared to $178 million for the three months ended June 30, 2018. The $59 million increase was primarily due to a 42.8% increase in total Marcellus sales volumes. The increase in sales volumes was primarily due to additional wells being turned in-line throughout 2018 and the first three months of 2019 as part of the Company's ongoing drilling and completions program.

The decrease in the total average Marcellus sales price was primarily due to a $1.89 per Mcfe decrease in the average NGL sales price and a $0.08 per Mcf decrease in the realized gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 61.9 Bcf of the Company's produced Marcellus gas sales volumes for the three months ended June 30, 2019 at an average gain of $0.11 per Mcf. For the three months ended June 30, 2018, these financial hedges represented approximately 47.4 Bcf at an average gain of $0.20 per Mcf.

Total operating costs and expenses for the Marcellus segment were $194 million for the three months ended June 30, 2019 compared to $140 million for the three months ended June 30, 2018. The increase in total dollars and decrease in unit costs for the Marcellus segment were due to the following items:

•Marcellus lease operating expenses were consistent at $11 million for the three months ended June 30, 2019 and June 30, 2018. The decrease in unit costs was driven by the 42.8% increase in total Marcellus sales volumes.

•Marcellus production, ad valorem, and other fees were $4 million for the three months ended June 30, 2019 compared to $5 million for the three months ended June 30, 2018. The decrease in total dollars was primarily related to a decrease in CNX's severance tax liability due to the production mix by state. The decrease in unit costs was driven by the decreased total dollars, along with the 42.8% increase in total Marcellus sales volumes.

•Marcellus transportation, gathering and compression costs were $114 million for the three months ended June 30, 2019 compared to $73 million for the three months ended June 30, 2018. The increase in total dollars was primarily related to the increase in production which resulted in an increase in both CNX Midstream fees as well as an increase in utilized firm transportation

expense. The increase in firm transportation total dollars was also related to new contracts that give CNX the ability to move and sell natural gas outside of the Appalachian basin. The increase in unit costs was driven by the increased total dollars described above, partially offset by the 42.8% increase in total Marcellus sales volumes.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $65 million for the three months ended June 30, 2019 compared to $51 million for the three months ended June 30, 2018. These amounts included depletion on a unit of production basis of $0.69 per Mcfe and $0.79 per Mcfe, respectively. The decrease in units of production depreciation, depletion and amortization rate is the result of positive reserve revisions within our core development area. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

UTICA SEGMENT

The Utica segment had earnings before income tax of $18 million for the three months ended June 30, 2019 compared to earnings before income tax of $46 million for the three months ended June 30, 2018.



	For the Three Months Ended June 30,
	2019		2018		Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	28.1		40.4		(12.3		)	(30.4	)%
NGLs Sales Volumes (Bcfe)*	—		2.1		(2.1		)	(100.0	)%
Condensate Sales Volumes (Bcfe)*	—		0.1		(0.1		)	(100.0	)%
Total Utica Sales Volumes (Bcfe)*	28.1		42.6		(14.5		)	(34.0	)%

Average Sales Price - Gas (per Mcf)	$	2.34	$	2.43	$	(0.09	)	(3.7	)%
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)	$	0.10	$	0.13	$	(0.03	)	(23.1	)%
Average Sales Price - NGLs (per Mcfe)*	$	—	$	4.05	$	(4.05	)	(100.0	)%
Average Sales Price - Condensate (per Mcfe)*	$	—	$	9.92	$	(9.92	)	(100.0	)%

Total Average Utica Sales Price (per Mcfe)	$	2.44	$	2.66	$	(0.22	)	(8.3	)%
Average Utica Lease Operating Expenses (per Mcfe)	0.15		0.21		(0.06		)	(28.6	)%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)	0.05		0.03		0.02			66.7	%
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)	0.27		0.38		(0.11		)	(28.9	)%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)	1.33		0.95		0.38			40.0	%
Total Average Utica Costs (per Mcfe)	$	1.80	$	1.57	$	0.23		14.6	%
Average Margin for Utica (per Mcfe)	$	0.64	$	1.09	$	(0.45	)	(41.3	)%

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

The Utica segment had natural gas, NGLs and oil revenue of $66 million for the three months ended June 30, 2019 compared to $108 million for the three months ended June 30, 2018. The $42 million decrease was primarily due to the 34.0% decrease in total Utica sales volumes. The decrease in total Utica sales volumes was primarily due to the sale of substantially all of CNX's Ohio Utica JV assets in the third quarter of 2018 as well as normal production declines in the remaining dry Utica wells.

The decrease in total average Utica sales price was primarily due to a $0.09 decrease in the average gas sales price, as well as a $0.03 per Mcf decrease in the realized gain on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 19.3 Bcf of the Company's produced Utica gas sales volumes for the three months ended June 30, 2019 at an average gain of $0.14. For the three months ended June 30, 2018, these financial hedges represented approximately 29.6 Bcf at an average gain of $0.15 per Mcf. Additionally, there was a $0.10 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging due to the sale of the previously mentioned JV assets in the third quarter of 2018 which consisted primarily of wet gas production.

Total operating costs and expenses for the Utica segment were $50 million for the three months ended June 30, 2019 compared to $67 million for the three months ended June 30, 2018. The decrease in total dollars and increase in unit costs for the Utica segment were due to the following items:

•Utica lease operating expense was $4 million for the three months ended June 30, 2019 compared to $9 million for the three months ended June 30, 2018. The decrease in total dollars was primarily due to a decrease in water disposal costs due to lower production volumes and an increase in reuse of produced water in well completions as well as a reduction in well operating costs due to the overall decrease in Utica volumes described above. The decrease in unit costs was driven by the decrease in total dollars.

•Utica transportation, gathering and compression costs were $8 million for the three months ended June 30, 2019 compared to $16 million for the three months ended June 30, 2018. The $8 million decrease in total dollars and $0.11 per Mcfe decrease in unit costs were both due to the overall decrease in Utica volumes as well as the shift to lower cost dry Utica production.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $36 million for the three months ended June 30, 2019 compared to $40 million for the three months ended June 30, 2018. These amounts included depletion on a unit of production basis of $1.18 per Mcfe and $0.93 per Mcfe, respectively. The increase in the units of production depreciation, depletion and amortization rate was due to negative reserve revisions, an increase in capital expenditures and a higher DD&A rate on deep dry Utica wells compared to the lower capital cost Utica wells which were part of the Ohio JV asset sale in 2018. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $8 million for the three months ended June 30, 2019 compared to earnings before income tax of $12 million for the three months ended June 30, 2018.



	For the Three Months Ended June 30,
	2019		2018		Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	13.9		14.8		(0.9		)	(6.1	)%

Average Sales Price - Gas (per Mcf)	$	2.85	$	3.17	$	(0.32	)	(10.1	)%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	0.08	$	0.15	$	(0.07	)	(46.7	)%

Total Average CBM Sales Price (per Mcf)	$	2.93	$	3.31	$	(0.38	)	(11.5	)%
Average CBM Lease Operating Expenses (per Mcf)	0.32		0.36		(0.04		)	(11.1	)%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)	0.13		0.11		0.02			18.2	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	0.71		0.77		(0.06		)	(7.8	)%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.22		1.23		(0.01		)	(0.8	)%
Total Average CBM Costs (per Mcf)	$	2.38	$	2.47	$	(0.09	)	(3.6	)%
Average Margin for CBM (per Mcf)	$	0.55	$	0.84	$	(0.29	)	(34.5	)%

The CBM segment had natural gas revenue of $40 million for the three months ended June 30, 2019 compared to $47 million for the three months ended June 30, 2018. The $7 million decrease was primarily due to the 6.1% decrease in total CBM sales volumes and the 11.5% decrease in total average CBM sales price. The decrease in CBM sales volumes was primarily due to normal well declines.

The total average CBM sales price decreased $0.38 per Mcf due to a $0.32 decrease in the average gas sales price, along with a $0.07 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 9.5 Bcf of the Company's produced CBM sales volumes for the three months ended June 30, 2019 at an average gain of $0.11 per Mcf. For the three months ended June 30, 2018, these financial hedges represented approximately 11.4 Bcf at an average gain of $0.21 per Mcf.

Total operating costs and expenses for the CBM segment were $33 million for the three months ended June 30, 2019 compared to $37 million for the three months ended June 30, 2018. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:

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

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

•Depreciation, depletion and amortization costs attributable to the CBM segment were $17 million for the three months ended June 30, 2019 compared to $19 million for the three months ended June 30, 2018. These amounts included depletion on a unit of production basis of $0.70 per Mcfe for each corresponding period. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

OTHER GAS SEGMENT

The Other Gas segment had earnings before income tax of $112 million for the three months ended June 30, 2019 compared to a loss before income tax of $63 million for the three months ended June 30, 2018.



	For the Three Months Ended June 30,
	2019	2018	Variance		Percent Change
Other Gas Sales Volumes (Bcf)	0.1	0.4	(0.3	)	(75.0	)%
Oil Sales Volumes (Bcfe)*	—	0.1	(0.1	)	(100.0	)%
Total Other Sales Volumes (Bcfe)*	0.1	0.5	(0.4	)	(80.0	)%

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

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

Other Gas sales volumes are primarily related to shallow oil and gas production. CNX sold substantially all of these assets on March 30, 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). There was nominal natural gas, NGLs and oil revenue related to the Other Gas segment for the three months ended June 30, 2019 and June 30, 2018. Total operating costs and expenses related to these other gas sales volumes were $1 million for each of the three months ended June 30, 2019 and June 30, 2018.

The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $211 million for the three months ended June 30, 2019. For the three months ended June 30, 2018, the Other Gas segment recognized an unrealized gain on commodity derivative instruments of $9 million as well as cash settlements received of $1 million. The unrealized gain on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis.

Purchased Gas

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were $19 million for the three months ended June 30, 2019 compared to $10 million for the three months ended June 30, 2018. Purchased gas costs were $19 million for the three months ended June 30, 2019 compared to $10 million for the three months ended June 30, 2018. The period-to-period increase in purchased gas revenue was due to the increase in purchased gas sales volumes offset in part by a decrease in average sales price.



	For the Three Months Ended June 30,
	2019		2018		Variance			Percent Change
Purchased Gas Sales Volumes (in Bcfe)	7.8		3.5		4.3			122.9	%
Average Sales Price (per Mcfe)	$	2.40	$	2.82	$	(0.42	)	(14.9	)%
Average Cost (per Mcfe)	$	2.40	$	2.77	$	(0.37	)	(13.4	)%

Other Operating Income

Other operating income was $3 million for the three months ended June 30, 2019 compared to $8 million for the three months ended June 30, 2018. The $5 million decrease was due to the following items:



	For the Three Months Ended June 30,
(in millions)	2019		2018		Variance			Percent Change
Water Income	$	—	$	4	$	(4	)	(100.0	)%
Equity in Earnings of Affiliates	1		2		(1		)	(50.0	)%
Gathering Income	2		2		—			—	%
Total Other Operating Income	$	3	$	8	$	(5	)	(62.5	)%


•	Water income decreased $4 million due to sales of freshwater to third-parties for hydraulic fracturing in the 2018 period. There were nominal sales in the 2019 period.

Exploration and Production Related Other Costs

Exploration and production related other costs were $5 million for the three months ended June 30, 2019 compared to $4 million for the three months ended June 30, 2018.



	For the Three Months Ended June 30,
(in millions)	2019		2018		Variance			Percent Change
Lease Expiration Costs	$	3	$	1	$	2		200.0	%
Land Rentals	2		1		1			100.0	%
Other	—		2		(2		)	(100.0	)%
Total Exploration and Production Other Costs	$	5	$	4	$	1		25.0	%

Other Operating Expense

Other operating expense was $18 million for the three months ended June 30, 2019 and June 30, 2018:



	For the Three Months Ended June 30,
	2019		2018		Variance			Percent Change
Water Expense	$	—	$	3	$	(3	)	(100.0	)%
Consulting and Professional Services	—		3		(3		)	(100.0	)%
Insurance Expense	1		1		—			—	%
Idle Equipment and Service Charges	3		1		2			200.0	%
Unutilized Firm Transportation and Processing Fees	14		10		4			40.0	%
Total Other Operating Expense	$	18	$	18	$	—		—	%


•	Water Expense decreased $3 million due to the associated costs related to the sale of freshwater to third-parties for hydraulic fracturing in the 2018 period as shown in Total Other Operating Income above. There were nominal sales in the 2019 period.


•	Consulting and Professional Services in the prior year mainly related to the sale of the majority of CNX's shallow oil and gas assets in 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

•

Idle Equipment and Service Charges primarily relate to the temporary idling of some of the Company's natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process. The increase of $2 million in the period-to-period comparison was primarily a result of the acceleration of five months of idle rig expense due to CNX terminating one of its drilling rig contacts early.

•

Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The increase in the period-to-period comparison was primarily due to previously-acquired capacity which was not utilized during the current period to transport the Company’s flowing production. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The

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

Selling, General and Administrative

SG&A costs represent direct charges for the management and operation of CNX's E&P division. SG&A costs were $44 million for the three months ended June 30, 2019 compared to $29 million for the three months ended June 30, 2018. Refer to the discussion of total company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders" of this Form 10-Q for a detailed cost explanation.

Interest Expense

Interest expense of $32 million was recognized in the three months ended June 30, 2019 compared to $31 million in the three months ended June 30, 2018. The $1 million increase was primarily due to additional borrowings on the CNX credit facility, offset, in part, by the reduction in higher-cost long-term debt resulting from the $500 million purchase, in the 2018 period, of the outstanding 8.00% senior notes due in April 2023, $300 million of which was purchased during the three months ended June 30, 2018. See Note 10 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

TOTAL MIDSTREAM DIVISION ANALYSIS for the three months ended June 30, 2019 compared to the three months ended June 30, 2018:

On January 3, 2018, CNX completed the Midstream Acquisition (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). CNX Gathering holds all of the interests in CNX Midstream GP LLC, which holds the general partner interest and incentive distribution rights in CNXM. As a result of this transaction, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus the Company began consolidating CNXM on January 3, 2018.



	For the Three Months Ended June 30,
(in millions)	2019		2018		Variance
Midstream Revenue - Related Party	$	60	$	38	$	22
Midstream Revenue - Third Party	18		23		(5		)
Total Revenue	$	78	$	61	$	17

Transportation, Gathering and Compression	$	13	$	12	$	1
Depreciation, Depletion and Amortization	8		8		—
Selling, General, and Administrative Costs	5		6		(1		)
Total Operating Costs and Expenses	26		26		—
Interest Expense	8		7		1
Total Midstream Division Costs	34		33		1
Earnings Before Income Tax	$	44	$	28	$	16

Midstream Revenue

Midstream revenue consists of revenue related to volumes gathered on behalf of CNX and other third-party natural gas producers. CNXM charges a higher fee for natural gas that is shipped on its wet system compared to gas shipped through its dry system. CNXM revenue can also be impacted by the relative mix of gathered volumes by area, which may vary depending upon delivery point and may change dynamically depending on commodity prices at time of shipment.

The table below summarizes volumes gathered by gas type:



	For the Three Months Ended June 30,
	2019	2018	Variance
Dry Gas (BBtu/d) (*)	891	698	193
Wet Gas (BBtu/d) (*)	731	653	78
Other (BBtu/d) ()(*)	178	9	169
Total Gathered Volumes	1,800	1,360	440

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

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

Transportation, Gathering and Compression

Transportation, Gathering and Compression costs were $13 million for the three months ended June 30, 2019 compared to $12 million for the three months ended June 30, 2018 and are comprised of items directly related to the cost of gathering natural gas at the wellhead and transporting it to interstate pipelines or other local sales points. These costs include items such as electrically-powered compression, compressor rental, repairs and maintenance, supplies, treating and contract services.

Selling, General and Administrative Expense

SG&A expense is comprised of direct charges for the management and operation of CNXM assets. SG&A costs were $5 million for the three months ended June 30, 2019 compared to $6 million for the three months ended June 30, 2018. Refer to the discussion of total Company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders" of this Form 10-Q for a detailed cost explanation.

Depreciation Expense

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

Interest Expense

Interest expense is comprised of interest on the outstanding balance under CNXM's senior notes due 2026 and its revolving credit facility. Interest expense was $8 million for the three months ended June 30, 2019 compared to $7 million for the three months ended June 30, 2018.

Results of Operations - Six Months Ended June 30, 2019 Compared with Six Months Ended June 30, 2018

Net Income Attributable to CNX Resources Shareholders

CNX reported net income attributable to CNX Resources shareholders of $75 million, or earnings per diluted share of $0.38 for the six months ended June 30, 2019, compared to net income attributable to CNX Resources shareholders of $570 million, or earnings per diluted share of $2.57, for the six months ended June 30, 2018.



	For the Six Months Ended June 30,
(Dollars in thousands)	2019		2018		Variance
Net Income	$	128,044	$	606,940	$	(478,896	)
Less: Net Income Attributable to Noncontrolling Interest	52,904		37,363		15,541
Net Income Attributable to CNX Resources Shareholders	$	75,140	$	569,577	$	(494,437	)

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

CNX's E&P Division had earnings before income tax of $82 million for the six months ended June 30, 2019, compared to earnings before income tax of $142 million for the six months ended June 30, 2018. Included in 2019 earnings was an unrealized gain on commodity derivative instruments of $57 million. Included in the 2018 earnings was an unrealized gain on commodity derivative instruments of $61 million.

As a result of the Midstream Acquisition (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q), CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus the Company began consolidating CNXM on January 3, 2018. The resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $624 million was included in the Gain on Previously Held Equity Interest line of the Consolidated Statements of Income in the 2018 period and was part of CNX's unallocated expenses. No such transactions occurred in the current period. Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment.

CNX's Midstream Division had earnings before income tax of $77 million for the six months ended June 30, 2019, compared to earnings before income tax of $63 million for the period from January 3, 2018 through June 30, 2018.

E&P Division Summary

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



	For the Six Months Ended June 30,
	2019		2018		Variance			Percent Change
Sales Volumes (Bcfe)	267.5		252.1		15.4			6.1	%

Average Sales Price (per Mcfe)	$	2.80	$	2.94	$	(0.14	)	(4.8	)%
Lease Operating Expense (per Mcfe)	0.14		0.25		(0.11		)	(44.0	)%
Production, Ad Valorem, and Other Fees (per Mcfe)	0.05		0.07		(0.02		)	(28.6	)%
Transportation, Gathering and Compression (per Mcfe)	0.95		0.84		0.11			13.1	%
Depreciation, Depletion and Amortization (DD&A) (per Mcfe)	0.89		0.89		—			—	%
Average Costs (per Mcfe)	2.03		2.05		(0.02		)	(1.0	)%
Average Margin (per Mcfe)	$	0.77	$	0.89	$	(0.12	)	(13.5	)%

Natural gas, NGLs, and oil revenue was $779 million for the six months ended June 30, 2019, compared to $740 million for the six months ended June 30, 2018. The increase was primarily due to an increase in natural gas pricing, when excluding the impact of hedging and natural gas liquids, as well as a 6.1% increase in total sales volumes.

The decrease in average sales price per Mcfe was the result of the $0.12 per Mcf increase in the realized loss on commodity derivative instruments related to the Company's hedging program and a $0.13 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging, offset in part by the $0.11 per Mcf increase in general natural gas prices, in the markets in which CNX sells its natural gas, during the current period.

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


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

•

Transportation, gathering, and compression expense increased on a per-unit basis primarily due to an increase in CNXM gathering fees related to an increase in our Marcellus production and an increase in firm transportation expense primarily as a result of new contracts that give CNX the ability to move and sell natural gas outside of the Appalachian basin. The decrease in production from CNX's lower cost dry Utica volumes as well as the third quarter 2018 sale of CNX's Ohio JV assets also contributed to the increase on a per unit basis.

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



	For the Six Months Ended June 30,
in thousands (unless noted)	2019			2018			Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	14,536			19,474			(4,938		)	(25.4	)%
Sales Volume (Mbbls)	2,423			3,246			(823		)	(25.4	)%
Gross Price ($/Bbl)	$	22.20		$	27.84		$	(5.64	)	(20.3	)%
Gross Revenue	$	53,790		$	90,441		$	(36,651	)	(40.5	)%

Oil:
Sales Volume (MMcfe)	34			163			(129		)	(79.1	)%
Sales Volume (Mbbls)	6			27			(21		)	(77.8	)%
Gross Price ($/Bbl)	$	45.78		$	57.24		$	(11.46	)	(20.0	)%
Gross Revenue	$	256		$	1,558		$	(1,302	)	(83.6	)%

Condensate:
Sales Volume (MMcfe)	580			1,319			(739		)	(56.0	)%
Sales Volume (Mbbls)	97			220			(123		)	(55.9	)%
Gross Price ($/Bbl)	$	41.46		$	52.32		$	(10.86	)	(20.8	)%
Gross Revenue	$	4,007		$	11,499		$	(7,492	)	(65.2	)%

GAS
Sales Volume (MMcf)	252,316			231,114			21,202			9.2	%
Sales Price ($/Mcf)	$	2.86		$	2.75		$	0.11		4.0	%
Gross Revenue	$	720,758		$	636,642		$	84,116		13.2	%

Hedging Impact ($/Mcf)	$	(0.12	)	$	—		$	(0.12	)	(100.0	)%
Loss on Commodity Derivative Instruments - Cash Settlement	$	(30,710	)	$	(307	)	$	(30,403	)	(9,903.3	)%

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



	For the Six Months Ended June 30,
(in millions)	2019		2018		Variance			Percent Change
SG&A
Salaries and Wages	$	21	$	21	$	—		—	%
Long-Term Equity-Based Compensation (Non-Cash)	35		11		24			218.2	%
Short-Term Incentive Compensation	7		11		(4		)	(36.4	)%
Other	22		23		(1		)	(4.3	)%
Total SG&A	$	85	$	66	$	19		28.8	%

Long-Term Equity-Based Compensation - During the six months ended June 30, 2019, the Company incurred $20 million of additional long-term equity-based compensation (non-cash) expense, which is included in Selling, General, and Administrative Costs in the Consolidated Statements of Income, as a result of the acceleration of vesting of certain restricted stock units and performance share units held by certain employees. The expense related to the restricted stock units is based on the closing stock price on the grant date, and the expense related to the performance share units is based upon a Monte Carlo valuation as of the grant date, with any payout of such performance share units continuing to be subject to the attainment of performance goals (total shareholder return relative to the S&P 500 index and absolute stock price growth). As of June 30, 2019, in order for the expense to result in equivalent value for these certain employees, the Company stock price would have to rebound materially. See Note 2 - Earnings Per Share in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information

Unallocated Expense

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

Other (Income) Expense



	For the Six Months Ended June 30,
(in millions)	2019			2018			Variance			Percent Change
Other Income
Royalty Income	$	4		$	10		$	(6	)	(60.0	)%
Right of Way Sales	4			4			—			—	%
Interest Income	1			—			1			100.0	%
Other	1			4			(3		)	(75.0	)%
Total Other Income	$	10		$	18		$	(8	)	(44.4	)%

Other Expense
Professional Services	$	1		$	5		$	(4	)	(80.0	)%
Bank Fees	6			5			1			20.0	%
Other Corporate Expense	2			2			—			—	%
Total Other Expense	$	9		$	12		$	(3	)	(25.0	)%

Total Other (Income) Expense	$	(1	)	$	(6	)	$	5		(83.3	)%

(Gain) Loss on Asset Sales and Abandonments

A gain on asset sales of $5 million related to non-core assets was recognized in the six months ended June 30, 2019 compared to a gain of $13 million in the six months ended June 30, 2018. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Also refer to the discussion of (Gain) Loss on Asset Sales and Abandonments contained in the section "Total Midstream Division Analysis" of this Form 10-Q for additional items that are not part of Unallocated Expense.

Gain on Previously Held Equity Interest

CNX recognized a gain on previously held equity interest of $624 million in the six months ended June 30, 2018 due to the Midstream Acquisition in January 2018. No such transactions occurred in the current period. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Loss on Debt Extinguishment

Loss on debt extinguishment of $8 million was recognized in the six months ended June 30, 2019 compared to a loss on debt extinguishment of $39 million in the six months ended June 30, 2018. During the six months ended June 30, 2019, CNX purchased $400 million of its 5.875% Senior notes due in April 2022 at an average price equal to 101.5% of the principal amount. During the six months end June 30, 2018 CNX purchased $391 million of its 5.875% Senior notes due in April 2022 at an average price equal to 103.8% of the principal amount and $300 million of its 8.00% Senior notes due in April 2023 at an average price equal to 106.0% of the principal amount. See Note 10 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

Impairment of Other Intangible Assets

In connection with the AEA with HG Energy (See Note 5 - Acquisition and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) that occurred during the six months ended June 30, 2018, CNX determined that the carrying value of the other intangible asset - customer relationship exceeded its fair value, and an impairment of $19 million was included in Impairment of Other Intangible Assets in the Consolidated Statement of Income. No such transactions occurred in the current period.

Income Taxes

The effective income tax rate was 18.6% for the six months ended June 30, 2019 compared to 23.1% for the six months ended June 30, 2018. The effective rate for the six months ended June 30, 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of noncontrolling interest, equity compensation, and state income taxes. The effective rate for the six months ended June 30, 2018 differs from the U.S. federal statutory 21% primarily due to a benefit from the filing of a federal 10-year net operating loss ("NOL") carryback which resulted in the Company being able to utilize previously valued tax attributes at a tax rate differential of 14%, as well as non-controlling interest. The benefits were partially offset by increases for both state income taxes and state valuation allowances.

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



	For the Six Months Ended June 30,
(in millions)	2019			2018			Variance			Percent Change
Total Company Earnings Before Income Tax	$	157		$	790		$	(633	)	(80.1	)%
Income Tax Expense	$	29		$	183		$	(154	)	(84.2	)%
Effective Income Tax Rate	18.6		%	23.1		%	(4.5		)%

TOTAL E&P DIVISION ANALYSIS for the six months ended June 30, 2019 compared to the six months ended June 30, 2018:

The E&P division had earnings before income tax of $82 million for the six months ended June 30, 2019 compared to earnings before income tax of $142 million for the six months ended June 30, 2018. Variances by individual E&P segment are discussed below.



	For the Six Months Ended														Difference to Six Months Ended
	June 30, 2019														June 30, 2018
(in millions)	Marcellus			Utica			CBM			Other Gas			Total E&P		Marcellus			Utica			CBM			Other Gas			Total E&P
Natural Gas, NGLs and Oil Revenue	$	531		$	158		$	89		$	1		$	779	$	148		$	(80	)	$	(15	)	$	(14	)	$	39
(Loss) Gain on Commodity Derivative Instruments	(21		)	(7		)	(3		)	57			26		(21		)	(8		)	(3		)	(3		)	(35		)
Purchased Gas Revenue	—			—			—			35			35		—			—			—			7			7
Other Operating Income	—			—			—			6			6		—			—			—			(13		)	(13		)
Total Revenue and Other Operating Income	510			151			86			99			846		127			(88		)	(18		)	(23		)	(2		)
Lease Operating Expense	21			9			9			—			39		(6		)	(12		)	(3		)	(2		)	(23		)
Production, Ad Valorem, and Other Fees	7			3			4			—			14		(3		)	—			—			—			(3		)
Transportation, Gathering and Compression	218			16			19			1			254		68			(16		)	(7		)	(3		)	42
Depreciation, Depletion and Amortization	127			73			33			5			238		23			(7		)	(3		)	(2		)	11
Exploration and Production Related Other Costs	—			—			—			8			8		—			—			—			2			2
Purchased Gas Costs	—			—			—			35			35		—			—			—			8			8
Other Operating Expense	—			—			—			41			41		—			—			—			7			7
Selling, General and Administrative Costs	—			—			—			74			74		—			—			—			20			20
Total Operating Costs and Expenses	373			101			65			164			703		82			(35		)	(13		)	30			64
Interest Expense	—			—			—			61			61		—			—			—			(6		)	(6		)
Total E&P Division Costs	373			101			65			225			764		82			(35		)	(13		)	24			58
Earnings (Loss) Before Income Tax	$	137		$	50		$	21		$	(126	)	$	82	$	45		$	(53	)	$	(5	)	$	(47	)	$	(60	)

MARCELLUS SEGMENT

The Marcellus segment had earnings before income tax of $137 million for the six months ended June 30, 2019 compared to earnings before income tax of $92 million for the six months ended June 30, 2018.



	For the Six Months Ended June 30,
	2019			2018		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	166.0			114.1		51.9			45.5	%
NGLs Sales Volumes (Bcfe)*	14.5			15.5		(1.0		)	(6.5	)%
Condensate Sales Volumes (Bcfe)*	0.6			1.0		(0.4		)	(40.0	)%
Total Marcellus Sales Volumes (Bcfe)*	181.1			130.6		50.5			38.7	%

Average Sales Price - Gas (per Mcf)	$	2.85		$	2.66	$	0.19		7.1	%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(0.12	)	$	—	$	(0.12	)	(100.0	)%
Average Sales Price - NGLs (per Mcfe)*	$	3.70		$	4.60	$	(0.90	)	(19.6	)%
Average Sales Price - Condensate (per Mcfe)*	$	6.88		$	8.73	$	(1.85	)	(21.2	)%

Total Average Marcellus Sales Price (per Mcfe)	$	2.82		$	2.93	$	(0.11	)	(3.8	)%
Average Marcellus Lease Operating Expenses (per Mcfe)	0.11			0.20		(0.09		)	(45.0	)%
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)	0.04			0.08		(0.04		)	(50.0	)%
Average Marcellus Transportation, Gathering and Compression Costs (per Mcfe)	1.21			1.15		0.06			5.2	%
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)	0.70			0.80		(0.10		)	(12.5	)%
Total Average Marcellus Costs (per Mcfe)	$	2.06		$	2.23	$	(0.17	)	(7.6	)%
Average Margin for Marcellus (per Mcfe)	$	0.76		$	0.70	$	0.06		8.6	%

The Marcellus segment had natural gas, NGLs and oil revenue of $531 million for the six months ended June 30, 2019 compared to $383 million for the six months ended June 30, 2018. The $148 million increase was primarily due to a 38.7% increase in total Marcellus sales volumes. The increase in sales volumes was primarily due to additional wells being turned in-line throughout 2018 and the first six months of 2019 as part of the Company's ongoing drilling and completions program.

The decrease in the total average Marcellus sales price was primarily due to a $0.90 per Mcfe decrease in the average NGL sales price, as well as a $0.12 per Mcf increase 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 117.2 Bcf of the Company's produced Marcellus gas sales volumes for the six months ended June 30, 2019 at an average loss of $0.18 per Mcf. For the six months ended June 30, 2018, these financial hedges represented approximately 95.0 Bcf at a nominal loss. The decreases were offset, in part, by a $0.19 per Mcfe increase average gas sales price.

Total operating costs and expenses for the Marcellus segment were $373 million for the six months ended June 30, 2019 compared to $291 million for the six months ended June 30, 2018. The increase in total dollars and decrease in unit costs for the Marcellus segment were due to the following items:

•Marcellus lease operating expenses were $21 million for the six months ended June 30, 2019 compared to $27 million for the six months ended June 30, 2018. The decrease in total dollars was primarily due to a decrease in water disposal costs in the current period due to an increase in the reuse of produced water in well completions activity. The decrease in unit costs was driven by the decrease in total dollars, along with the 38.7% increase in total Marcellus sales volumes.

•Marcellus production, ad valorem, and other fees were $7 million for the six months ended June 30, 2019 compared to $10 million for the six months ended June 30, 2018. The decrease in total dollars was primarily related to a decrease in CNX's severance tax liability due to the production mix by state. The decrease in unit costs was driven by the decreased total dollars, along with the 38.7% increase in total Marcellus sales volumes.

•Marcellus transportation, gathering and compression costs were $218 million for the six months ended June 30, 2019 compared to $150 million for the six months ended June 30, 2018. The increase in total dollars was primarily related to the increase in production which resulted in an increase in both CNX Midstream fees as well as an increase in utilized firm transportation expense. The increase in firm transportation total dollars was also related to new contracts that give CNX the ability to move and sell natural gas outside of the Appalachian basin. These increases were offset by lower processing costs from a drier production mix. The increase in unit costs was driven by the increased total dollars described above, partially offset by the 38.7% increase in total Marcellus sales volumes.

•Depreciation, depletion and amortization costs attributable to the Marcellus segment were $127 million for the six months ended June 30, 2019 compared to $104 million for the six months ended June 30, 2018. These amounts included depletion on a unit of production basis of $0.69 per Mcfe and $0.79 per Mcfe, respectively. The decrease in units of production depreciation, depletion and amortization rate is the result of positive reserve revisions within our core development area. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

UTICA SEGMENT

The Utica segment had earnings before income tax of $50 million for the six months ended June 30, 2019 compared to earnings before income tax of $103 million for the six months ended June 30, 2018.



	For the Six Months Ended June 30,
	2019			2018		Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	58.6			81.9		(23.3		)	(28.4	)%
NGLs Sales Volumes (Bcfe)*	—			3.9		(3.9		)	(100.0	)%
Condensate Sales Volumes (Bcfe)*	—			0.3		(0.3		)	(100.0	)%
Total Utica Sales Volumes (Bcfe)*	58.6			86.1		(27.5		)	(31.9	)%

Average Sales Price - Gas (per Mcf)	$	2.70		$	2.64	$	0.06		2.3	%
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)	$	(0.12	)	$	0.01	$	(0.13	)	(1,300.0	)%
Average Sales Price - NGLs (per Mcfe)*	$	—		$	4.83	$	(4.83	)	(100.0	)%
Average Sales Price - Condensate (per Mcfe)*	$	—		$	8.68	$	(8.68	)	(100.0	)%

Total Average Utica Sales Price (per Mcfe)	$	2.58		$	2.78	$	(0.20	)	(7.2	)%
Average Utica Lease Operating Expenses (per Mcfe)	0.15			0.25		(0.10		)	(40.0	)%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)	0.05			0.04		0.01			25.0	%
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)	0.28			0.37		(0.09		)	(24.3	)%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)	1.25			0.93		0.32			34.4	%
Total Average Utica Costs (per Mcfe)	$	1.73		$	1.59	$	0.14		8.8	%
Average Margin for Utica (per Mcfe)	$	0.85		$	1.19	$	(0.34	)	(28.6	)%

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

The Utica segment had natural gas, NGLs and oil revenue of $158 million for the six months ended June 30, 2019 compared to $238 million for the six months ended June 30, 2018. The $80 million decrease was primarily due to the 31.9% decrease in total Utica sales volumes. The decrease in total Utica sales volumes was primarily due to the sale of substantially all of CNX's Ohio Utica JV assets in the third quarter of 2018 as well as normal production declines in the remaining dry Utica wells.

The decrease in total average Utica sales price was primarily due to a $0.13 per Mcf decrease in the realized (loss) gain on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 38.9 Bcf of the Company's produced Utica gas sales volumes for the six months ended June 30, 2019 at an average loss of $0.18 per Mcf. For the six months ended June 30, 2018, these financial hedges represented approximately 55.6 Bcf at a nominal gain. Additionally, there was a $0.13 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging due to the sale of the previously mentioned Ohio JV assets in the third quarter of 2018 which consisted primarily of wet Utica production. The decreases were partially offset by an $0.06 per Mcf increase in average gas sales price.

Total operating costs and expenses for the Utica segment were $101 million for the six months ended June 30, 2019 compared to $136 million for the six months ended June 30, 2018. The decrease in total dollars and increase in unit costs for the Utica segment were due to the following items:

•Utica lease operating expense was $9 million for the six months ended June 30, 2019 compared to $21 million for the six months ended June 30, 2018. The decrease in total dollars was primarily due to a decrease in water disposal costs due to lower production volumes and an increase in reuse of produced water in well completions and a reduction in well operating costs due to the overall decrease in Utica volumes described above. The decrease in unit costs was driven by the decrease in total dollars.

•Utica transportation, gathering and compression costs were $16 million for the six months ended June 30, 2019 compared to $32 million for the six months ended June 30, 2018. The $16 million decrease in total dollars and $0.09 per Mcfe decrease in unit costs were both due to the overall decrease in Utica volumes as well as the shift to lower cost dry Utica production.

•Depreciation, depletion and amortization costs attributable to the Utica segment were $73 million for the six months ended June 30, 2019 compared to $80 million for the six months ended June 30, 2018. These amounts included depletion on a unit of production basis of $1.18 per Mcfe and $0.93 per Mcfe, respectively. The increase in the units of production depreciation, depletion and amortization rate was due to negative reserve revisions, an increase in capital expenditures and a higher DD&A rate on deep dry Utica wells compared to the lower capital cost Utica wells which were part of the Ohio JV asset sale in 2018. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $21 million for the six months ended June 30, 2019 compared to earnings before income tax of $26 million for the six months ended June 30, 2018.



	For the Six Months Ended June 30,
	2019			2018			Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	27.6			30.7			(3.1		)	(10.1	)%

Average Sales Price - Gas (per Mcf)	$	3.24		$	3.40		$	(0.16	)	(4.7	)%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(0.11	)	$	(0.01	)	$	(0.10	)	(1,000.0	)%

Total Average CBM Sales Price (per Mcf)	$	3.13		$	3.39		$	(0.26	)	(7.7	)%
Average CBM Lease Operating Expenses (per Mcf)	0.31			0.39			(0.08		)	(20.5	)%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)	0.14			0.12			0.02			16.7	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	0.70			0.84			(0.14		)	(16.7	)%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.24			1.21			0.03			2.5	%
Total Average CBM Costs (per Mcf)	$	2.39		$	2.56		$	(0.17	)	(6.6	)%
Average Margin for CBM (per Mcf)	$	0.74		$	0.83		$	(0.09	)	(10.8	)%

The CBM segment had natural gas revenue of $89 million for the six months ended June 30, 2019 compared to $104 million for the six months ended June 30, 2018. The $15 million decrease was primarily due to the 10.1% decrease in total CBM sales volumes and the 7.7% decrease in total average CBM sales price. The decrease in CBM sales volumes was primarily due to normal well declines, as well as the sale of certain CBM assets that were sold along with the majority of CNX's shallow oil and gas assets in 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).

The total average CBM sales price decreased $0.26 per Mcf due to a $0.16 decrease in average gas sales price, along with a $0.10 per Mcf increase in the loss on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 18.3 Bcf of the Company's produced CBM sales volumes for the six months ended June 30, 2019 at an average loss of $0.18 per Mcf. For the six months ended June 30, 2018, these financial hedges represented approximately 23.0 Bcf at a nominal loss.

Total operating costs and expenses for the CBM segment were $65 million for the six months ended June 30, 2019 compared to $78 million for the six months ended June 30, 2018. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:

•CBM lease operating expense was $9 million for the six months ended June 30, 2019 compared to $12 million for the six months ended June 30, 2018. The $3 million decrease was primarily due to reductions in contractor services and a decrease in repairs and maintenance costs. The decrease in unit costs was also due to the decrease in total dollars.

•CBM transportation, gathering and compression costs were $19 million for the six months ended June 30, 2019 compared to $26 million for the six months ended June 30, 2018. The $7 million decrease in total dollars as well as the $0.14 per Mcf decrease in unit costs were primarily related to a decrease in electrical power expense as well as a decrease in contractor services.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $33 million for the six months ended June 30, 2019 compared to $36 million for the six months ended June 30, 2018. These amounts both included depletion on a unit of production basis of $0.70 per Mcfe. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

OTHER GAS SEGMENT

The Other Gas segment had a loss before income tax of $126 million for the six months ended June 30, 2019 compared to a loss before income tax of $79 million for the six months ended June 30, 2018.



	For the Six Months Ended June 30,
	2019	2018	Variance		Percent Change
Other Gas Sales Volumes (Bcf)	0.2	4.6	(4.4	)	(95.7	)%
Oil Sales Volumes (Bcfe)*	—	0.1	(0.1	)	(100.0	)%
Total Other Sales Volumes (Bcfe)*	0.2	4.7	(4.5	)	(95.7	)%

Other Gas sales volumes are primarily related to shallow oil and gas production. CNX sold substantially all of these assets on March 30, 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). There was nominal natural gas, NGLs and oil revenue related to the Other Gas segment for the six months ended June 30, 2019 compared to $15 million for the six months ended June 30, 2018. The decrease in natural gas, NGLs and oil revenue was due to the asset sale. Total operating costs and expenses related to these other gas sales volumes were $3 million for the six months ended June 30, 2019 compared to $13 million for the six months ended June 30, 2018.

The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $57 million for the six months ended June 30, 2019. For the six months ended June 30, 2018, the Other Gas segment recognized an unrealized gain on commodity derivative instruments of $61 million as well as cash settlements paid of $1 million. The unrealized gain on commodity derivative instruments represents changes in the fair value of all of the Company's existing commodity hedges on a mark-to-market basis.

Purchased Gas

Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were $35 million for the six months ended June 30, 2019 compared to $28 million for the six months ended June 30, 2018. Purchased gas costs were $35 million for the six months ended June 30, 2019 compared to $27 million for the six months ended June 30, 2018. The period-to-period increase in purchased gas revenue was due to an increase in purchased gas sales volumes offset, in part, by the decrease in averages sales price.



	For the Six Months Ended June 30,
	2019		2018		Variance			Percent Change
Purchased Gas Sales Volumes (in Bcfe)	13.2		8.8		4.4			50.0	%
Average Sales Price (per Mcfe)	$	2.64	$	3.19	$	(0.55	)	(17.2	)%
Average Cost (per Mcfe)	$	2.64	$	3.05	$	(0.41	)	(13.4	)%

Other Operating Income

Other operating income was $6 million for the six months ended June 30, 2019 compared to $19 million for the six months ended June 30, 2018. The $13 million decrease was due to the following items:



	For the Six Months Ended June 30,
(in millions)	2019		2018		Variance			Percent Change
Water Income	$	—	$	11	$	(11	)	(100.0	)%
Equity in Earnings of Affiliates	1		3		(2		)	(66.7	)%
Gathering Income	5		5		—			—	%
Total Other Operating Income	$	6	$	19	$	(13	)	(68.4	)%


•	Water income decreased $11 million due to sales of freshwater to third-parties for hydraulic fracturing in the 2018 period. There were nominal sales in the 2019 period.

Exploration and Production Related Other Costs

Exploration and production related other costs were $8 million for the six months ended June 30, 2019 compared to $6 million for the six months ended June 30, 2018.



	For the Six Months Ended June 30,
(in millions)	2019		2018		Variance			Percent Change
Lease Expiration Costs	$	5	$	2	$	3		150.0	%
Land Rentals	3		2		1			50.0	%
Other	—		2		(2		)	(100.0	)%
Total Exploration and Production Other Costs	$	8	$	6	$	2		33.3	%

Other Operating Expense

Other operating expense was $41 million for the six months ended June 30, 2019 compared to $34 million for the six months ended June 30, 2018. The $7 million increase was due to the following items:



	For the Six Months Ended June 30,
	2019		2018		Variance			Percent Change
Unutilized Firm Transportation and Processing Fees	$	28	$	18	$	10		55.6	%
Idle Equipment and Service Charges	8		4		4			100.0	%
Insurance Expense	1		2		(1		)	(50.0	)%
Severance Expense	—		1		(1		)	(100.0	)%
Consulting and Professional Services	—		4		(4		)	(100.0	)%
Water Expense	—		4		(4		)	(100.0	)%
Other	4		1		3			300.0	%
Total Other Operating Expense	$	41	$	34	$	7		20.6	%

•

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

•

Idle Equipment and Service Charges primarily relate to the temporary idling of some of the Company's natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process. The increase of $4 million in the period-to-period comparison was primarily result of the acceleration of five months of idle rig expense due to CNX terminating one of its drilling rig contacts early, as well as additional idle service expense related to the Shaw 1G Utica Shale well that occurred in the first quarter of 2019.


•	Consulting and Professional Services in the prior year mainly related to the sale of the majority of CNX's shallow oil and gas assets in 2018 (See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).


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

Selling, General and Administrative

SG&A costs represent direct charges for the management and operation of CNX's E&P division. SG&A costs were $74 million for the six months ended June 30, 2019 compared to $54 million for the six months ended June 30, 2018. Refer to the discussion of total company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders" of this Form 10-Q for a detailed cost explanation.

Interest Expense

Interest expense of $61 million was recognized in the six months ended June 30, 2019 compared to $67 million in the six months ended June 30, 2018. The $6 million decrease was primarily due to the reduction in higher cost long-term debt, resulting from the $500 million purchase, in the 2018 period, of the outstanding 8.00% senior notes due in April 2023, offset, in part, by additional borrowings on the CNX credit facility. In the six months ended June 30, 2018, CNX purchased $391 million of its outstanding 5.875% senior notes due in April 2022 and $300 million of its outstanding 8.00% senior notes due in April 2023. See Note 10 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

TOTAL MIDSTREAM DIVISION ANALYSIS for the six months ended June 30, 2019 compared to the period January 3, 2018 through June 30, 2018:



(in millions)	For the six months ended June 30, 2019		For the period January 3, 2018 through June 30, 2018			Variance
Midstream Revenue - Related Party	$	114	$	76		$	38
Midstream Revenue - Third Party	37		50			(13		)
Total Revenue	$	151	$	126		$	25

Transportation, Gathering and Compression	$	24	$	26		$	(2	)
Depreciation, Depletion and Amortization	16		17			(1		)
Selling, General, and Administrative Costs	11		12			(1		)
Total Operating Costs and Expenses	51		55			(4		)
Other Expense	1		—			1
Loss (Gain) on Asset Sales and Abandonments	7		(2		)	9
Interest Expense	15		10			5
Total Midstream Division Costs	74		63			11
Earnings Before Income Tax	$	77	$	63		$	14

Midstream Revenue

The table below summarizes volumes gathered by gas type:



	For the six months ended June 30, 2019	For the period January 3, 2018 through June 30, 2018	Variance
Dry Gas (BBtu/d) (*)	865	703	162
Wet Gas (BBtu/d) (*)	715	682	33
Other (BBtu/d) ()(*)	156	17	139
Total Gathered Volumes	1,736	1,402	334

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

Transportation, Gathering and Compression

Transportation, Gathering and Compression costs were $24 million for the six months ended June 30, 2019 compared to $26 million for the period January 3, 2018 through June 30, 2018 and are comprised of items directly related to the cost of gathering natural gas at the wellhead and transporting it to interstate pipelines or other local sales points. These costs include items such as electrically-powered compression, compressor rental, repairs and maintenance, supplies, treating and contract services.

Selling, General and Administrative Expense

SG&A expense is comprised of direct charges for the management and operation of CNXM assets. SG&A costs were $11 million for the six months ended June 30, 2019 compared to $12 million for the period January 3, 2018 through June 30, 2018. Refer to the discussion of total Company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders" of this Form 10-Q for a detailed cost explanation.

Depreciation Expense

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

(Gain) Loss on Asset Sales and Abandonments

During the six months ended June 30, 2019, CNXM abandoned the construction of a compressor station that was designed to support additional production within certain areas of what is referred to as their "Anchor System," incurring a loss of $7 million that is included in (Gain) Loss on Asset Sales and Abandonments in the Consolidated Statements of Income. CNXM continues to evaluate projects as CNX's and third-party customer development plans change in order to optimize system design and to actively manage capital investments. During the period January 3, 2018 through June 30, 2018, CNXM sold property and equipment to an unrelated third-party for $6 million in cash proceeds resulting in a gain of $2 million.

Interest Expense

Interest expense is comprised of interest on the outstanding balance under CNXM's senior notes due 2026 and its revolving credit facility. Interest expense was $15 million for the six months ended June 30, 2019 compared to $10 million for the period January 3, 2018 through June 30, 2018.

Liquidity and Capital Resources

CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CNX believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, some of which are beyond CNX’s control.

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

Uncertainty in the financial markets brings additional potential risks to CNX. These risks include declines in the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact the Company's collection of trade receivables. As a result, CNX regularly monitors the creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments and security. CNX believes that its current group of customers is financially sound and represents no abnormal business risk.

In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX has also entered into various natural gas swap and option transactions, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $156 million at June 30, 2019 and a net asset of $99 million at December 31, 2018. The Company has not experienced any issues of non-performance by derivative counterparties.

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

Cash Flows (in millions)



	For the Six Months Ended June 30,
	2019			2018			Change
Cash Provided by Operating Activities	$	561		$	451		$	110
Cash Used in Investing Activities	$	(621	)	$	(639	)	$	18
Cash Provided by (Used in) Financing Activities	$	76		$	(266	)	$	342

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


•	Net income decreased $479 million in the period-to-period comparison.

•

Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $161 million change in deferred income taxes, a $624 million decrease in gain on previously held equity interest, $24 million increase in stock-based compensation, an $18 million decrease in impairment of other intangible assets, a $31 million decrease in the loss on debt extinguishment, and a $17 million change in loss (gain) on asset sales and abandonments.

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

•

Capital expenditures increased $132 million in the period-to-period comparison primarily due to increased expenditures in the Utica and Marcellus Shale plays resulting from increased drilling and completions activity as well as additional water expenditures due to the installation of new water pipelines. CNXM's capital expenditures increased due to additional spend in order to support both CNX's and third-party customer development plans.


•	Proceeds from asset sales decreased $146 million primarily due to the 2018 sale of substantially all of CNX's shallow oil and gas and certain CBM assets in Pennsylvania and West Virginia. See Note 5 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.


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

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

•

During the six months ended June 30, 2019, CNX paid $406 million to repurchase $400 million of the senior notes due in 2022 at a 101.5% principal amount. During the six months ended June 30, 2018, CNX paid $405 million to repurchase $391 million of the senior notes due in 2022 at a 103.8% principal amount as well as $318 million to repurchase $300 million of the senior notes due in 2023 at a 106.0% principal amount. See Note 10 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

•

During the six months ended June 30, 2019, CNX received proceeds of $500 million from the issuance of senior notes due in 2027. During the six months ended June 30, 2018, CNX received proceeds of $394 million from the issuance of CNXM's senior notes due in 2026. See Note 10 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.


•	In the six months ended June 30, 2019, CNX repurchased $110 million of its common stock on the open market compared to $167 million in the six months ended June 30, 2018.


•	In the six months ended June 30, 2019, there were $18 million of net proceeds from the CNX credit facility and $422 million of proceeds in the 2018 period.


•	In the six months ended June 30, 2019, there were $124 million of net proceeds from the CNXM credit facility compared to $139 million of net payments during the six months ended June 30, 2018.


•	In the six months ended June 30, 2019, there were $10 million in debt issuance and financing fees compared to $20 million during the six months ended June 30, 2018.


•	In the six months ended June 30, 2019, there were $31 million in distributions to CNXM unitholders compared to $27 million during the six months ended June 30, 2018.

The following is a summary of the Company's significant contractual obligations at June 30, 2019 (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	$	9,143	$	2,918	$	647	$	—	$	12,708
Gas Firm Transportation and Processing	242,241		489,288		423,079		1,159,534		2,314,142
Long-Term Debt	—		895,522		838,000		895,000		2,628,522
Interest on Long-Term Debt	149,669		301,527		185,537		160,749		797,482
Finance Lease Obligations	7,133		10,261		308		—		17,702
Interest on Finance Lease Obligations	1,038		625		62		—		1,725
Operating Lease Obligations	66,209		102,266		7,484		27,714		203,673
Interest on Operating Lease Obligations	8,506		8,557		3,427		5,541		26,031
Long-Term Liabilities—Employee Related (a)	1,865		3,984		4,409		25,316		35,574
Other Long-Term Liabilities (b)	201,284		24,642		8,250		12,375		246,551
Total Contractual Obligations (c)	$	687,088	$	1,839,590	$	1,471,203	$	2,286,229	$	6,284,110

_________________________


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


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


(c)	The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

Debt

At June 30, 2019, CNX had total long-term debt of $2,629 million, excluding unamortized debt issuance costs. This long-term debt consisted of:


•	An aggregate principal amount of $895 million of 5.875% Senior Notes due in April 2022 plus $1 million of unamortized bond premium. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM.


•	An aggregate principal amount of $630 million in outstanding borrowings under the CNX credit facility.


•	An aggregate principal amount of $500 million of 7.25% Senior Notes due in March 2027. Interest on the notes is payable March 14 and September 14 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM.


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


•	An aggregate principal amount of $208 million in outstanding borrowings under the CNXM revolver. CNX is not a guarantor of CNXM's revolving credit facility.

Total Equity and Dividends

CNX had total equity of $5,100 million at June 30, 2019 compared to $5,082 million at December 31, 2018. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance can be given that CNX will pay dividends in the future. CNX's Board of Directors determines whether dividends will be paid quarterly. CNX suspended its quarterly dividend in March 2016 to further reflect the Company's increased emphasis on growth. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX, and such other factors as the Board of Directors deems relevant. The Company's Credit Facility limits CNX's ability to pay dividends in excess of an annual rate of $0.10 per share when the Company's net leverage ratio exceeds 3.00 to 1.00 and is subject to availability under the Credit Facility of at least 15% of the aggregate commitments. The net leverage ratio was 2.35 to 1.00 at June 30, 2019. The Credit Facility does not permit dividend payments in the event of default. The indentures to the 5.875% Senior Notes due in April 2022 and the 7.25% Senior Notes due in March 2027 limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the six months ended June 30, 2019.

On July 19, 2019 the Board of Directors of CNX Midstream GP LLC, the general partner of CNX Midstream Partners LP, announced the declaration of a cash distribution of $0.3865 per unit with respect to the second quarter of 2019. The distribution will be made on August 14, 2019 to unitholders of record as of the close of business on August 6, 2019. The distribution, which equates to an annual rate of $1.546 per unit, represents an increase of 3.6% over the prior quarter, and an increase of 15% over the distribution paid with respect to the second quarter of 2018.

Off-Balance Sheet Transactions

CNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CNX uses a combination of surety bonds, corporate guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected in the Consolidated Balance Sheet at June 30, 2019. Management believes these items will expire without being funded. See Note 12 - Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CNX.

Forward-Looking Statements

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


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


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


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


•	the high-risk nature of drilling and developing 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 drilling;


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


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


•	the impact of potential, 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 for our securities;


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


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


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


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


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


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


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


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


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


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


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


•	failure to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;


•	risks associated with our debt;


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


•	changes in federal or state income tax laws;


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


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


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


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


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


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


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


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


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


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


•	the separation of CONSOL Energy could result in substantial tax liability; and


•	other factors discussed in the Company's 2018 Annual Report on Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file at the Securities and Exchange Commission.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

CNX is exposed to market price risk in the normal course of selling natural gas. CNX uses fixed-price contracts, options and derivative commodity instruments to minimize exposure to market price volatility in the sale of natural gas and NGLs. Under our risk management policy, it is not our intent to engage in derivative activities for speculative purposes.

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

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

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

At June 30, 2019 and December 31, 2018, our open gas derivative instruments were in a net asset position with a fair value of $156 million and $99 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at June 30, 2019 and December 31, 2018. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $415 million and $427 million at June 30, 2019 and December 31, 2018, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by $447 million and $453 million at June 30, 2019 and December 31, 2018, respectively.

CNX's interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2019 and December 31, 2018, CNX had $1,798 million and $1,703 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $10 million and $9 million, respectively. At June 30, 2019 and December 31, 2018, CNX had $838 million and $696 million, respectively, of debt outstanding under variable-rate instruments. CNX’s primary exposure to market risk for changes in interest rates relates to our Credit Facility, under which there were $630 million of borrowings at June 30, 2019 and $612 million at December 31, 2018, and CNXM's revolving credit facility, under which there were $208 million of borrowings at June 30, 2019 and $84 million at December 31, 2018. A hypothetical 100 basis-point increase in the average rate for CNX's and CNXM's revolving credit facilities would decrease pre-tax future earnings as of June 30, 2019 and December 31, 2018 by $8 million and $7 million, respectively, on an annualized basis.

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

Natural Gas Hedging Volumes

As of July 8, 2019, our hedged volumes for the periods indicated are as follows:



	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2019 Fixed Price Volumes
Hedged Bcf	N/A		N/A		103.9		109.0		212.9
Weighted Average Hedge Price per Mcf	N/A		N/A		$	2.63	$	2.67	$	2.65
2020 Fixed Price Volumes
Hedged Bcf	115.6		121.1		122.4		122.4		470.5*
Weighted Average Hedge Price per Mcf	$	2.58	$	2.51	$	2.51	$	2.51	$	2.52
2021 Fixed Price Volumes
Hedged Bcf	102.6		103.8		104.9		104.9		416.2
Weighted Average Hedge Price per Mcf	$	2.40	$	2.40	$	2.40	$	2.39	$	2.40
2022 Fixed Price Volumes
Hedged Bcf	68.9		69.7		70.4		70.4		279.4
Weighted Average Hedge Price per Mcf	$	2.45	$	2.45	$	2.45	$	2.45	$	2.45
2023 Fixed Price Volumes
Hedged Bcf	36.0		36.5		36.9		36.9		146.3
Weighted Average Hedge Price per Mcf	$	2.28	$	2.28	$	2.28	$	2.28	$	2.28
2024 Fixed Price Volumes
Hedged Bcf	15.3		15.3		15.4		15.4		61.4
Weighted Average Hedge Price per Mcf	$	2.60	$	2.60	$	2.60	$	2.60	$	2.60

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


ITEM 4.	CONTROLS AND PROCEDURES

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

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

PART II: OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

The first paragraph of Note 12—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.

ITEM 1A. RISK FACTORS

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

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, 2019:



ISSUER PURCHASES OF EQUITY SECURITIES
	(a)	(b)		(c)	(d)
Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (000's omitted)
April 1, 2019- April 30, 2019	2,054,469	$	10.03	2,054,469	$	209,638
May 1, 2019- May 31, 2019	5,025,352	$	7.91	5,025,352	$	169,912
June 1, 2019- June 30, 2019	1,728,612	$	7.97	1,728,612	$	156,143
Total	8,808,433

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

(2) Shares repurchased as part of the Company’s current $750 million share repurchase program authorized by the Board of Directors in October 30, 2017 and subsequently amended from time to time (See Note 17 - Stock Repurchase in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for more information), which is not subject to an expiration date.


ITEM 6.	EXHIBITS



10.1			Amendment No. 1 to Credit Agreement, dated as of April 24, 2019, to the Second Amended and Restated Credit Agreement, dated as of March 8, 2018, among CNX Resources Corporation, the guarantors party thereto, the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent, and PNC Bank, National Association, as administrative agent and collateral agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on April 30, 2019.

10.2*			Amendment to the Amended and Restated Supplemental Retirement Plan of CNX Resources Corporation effective May 30, 2019, filed herewith.

10.3*			Form of Director Deferred Stock Unit Grant Agreement, updated May 2019, filed herewith.

10.4*			Form of Non-Qualified Stock Option Agreement for Directors, updated May 2019, filed herewith.

10.5*			Form of Restricted Stock Unit Award Agreement for Directors, updated May 2019, filed herewith.

31.1			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2			Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101			Interactive Data File (Form 10-Q for the quarterly period ended June 30, 2019 furnished in XBRL).

* Denotes the management contracts and compensatory arrangements in which any director or any named executive officer participates.

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: July 30, 2019



CNX RESOURCES CORPORATION

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

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

	By:	/S/ JASON L. MUMFORD
		Jason L. Mumford
		Chief Accounting Officer and Vice President (Duly Authorized Officer and Principal Accounting Officer)