10-Q 1 cnx-63018x10q.htm 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________
FORM 10-Q
__________________________________________________
(Mark One)

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

For the quarterly period ended June 30, 2018
OR

o | 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)
__________________________________________________
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 x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes x No o
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 x Accelerated filer o Non-accelerated filer o Smaller Reporting Company o
Emerging Growth Company o 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
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 17, 2018
Common stock, $0.01 par value |  | 213,059,169

TABLE OF CONTENTS
|  | Page
PART I FINANCIAL INFORMATION |
ITEM 1. | Condensed Financial Statements |
| Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 | 4
| Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2018 and 2017 | 5
| Consolidated Balance Sheets at June 30, 2018 and December 31, 2017 | 6
| Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2018 | 8
| Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017 | 9
| Notes to Unaudited Consolidated Financial Statements | 10
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 34
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk | 67
ITEM 4. | Controls and Procedures | 68
PART II OTHER INFORMATION |
ITEM 1. | Legal Proceedings | 68
ITEM 1A. | Risk Factors | 69
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 69
ITEM 6. | Exhibits | 70

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.
Bbtu - One billion British Thermal units.
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.
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.
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 CNX Resources Corporation and its subsidiaries have in gross wells or acres.
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 - 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.
Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

PART I : FINANCIAL INFORMATION

ITEM 1. | CONDENSED 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: | 2018 |  | 2017 |  | 2018 |  | 2017
Natural Gas, NGLs and Oil Revenue | $ | 334,517 |  |  | $ | 260,306 |  |  | $ | 740,140 |  |  | $ | 578,069 |
Gain on Commodity Derivative Instruments | 25,660 |  |  | 83,788 |  |  | 60,747 |  |  | 61,325 |
Purchased Gas Revenue | 9,930 |  |  | 10,316 |  |  | 27,985 |  |  | 19,294 |
Midstream Revenue | 23,483 |  |  | — |  |  | 49,737 |  |  | — |
Other Operating Income | 8,534 |  |  | 16,658 |  |  | 19,244 |  |  | 32,308 |
Total Revenue and Other Operating Income | 402,124 |  |  | 371,068 |  |  | 897,853 |  |  | 690,996 |
Costs and Expenses: |  |  |  |  |  |  |
Operating Expense |  |  |  |  |  |  |
Lease Operating Expense | 25,338 |  |  | 21,074 |  |  | 62,148 |  |  | 42,705 |
Transportation, Gathering and Compression | 75,767 |  |  | 86,599 |  |  | 162,028 |  |  | 180,931 |
Production, Ad Valorem, and Other Fees | 7,703 |  |  | 4,606 |  |  | 16,936 |  |  | 13,935 |
Depreciation, Depletion and Amortization | 119,087 |  |  | 91,640 |  |  | 243,754 |  |  | 187,318 |
Exploration and Production Related Other Costs | 3,699 |  |  | 19,717 |  |  | 6,079 |  |  | 29,502 |
Purchased Gas Costs | 9,747 |  |  | 10,194 |  |  | 26,801 |  |  | 19,089 |
Impairment of Exploration and Production Properties | — |  |  | — |  |  | — |  |  | 137,865 |
Impairment of Other Intangible Assets | 18,650 |  |  | — |  |  | 18,650 |  |  | — |
Selling, General, and Administrative Costs | 34,909 |  |  | 21,754 |  |  | 66,258 |  |  | 43,556 |
Other Operating Expense | 17,786 |  |  | 24,106 |  |  | 33,832 |  |  | 42,282 |
Total Operating Expense | 312,686 |  |  | 279,690 |  |  | 636,486 |  |  | 697,183 |
Other (Income) Expense |  |  |  |  |  |  |
Other Expense (Income) | 575 |  |  | 5,475 |  |  | (5,917 | ) |  | 9,550 |
Gain on Asset Sales | (3,280 | ) |  | (134,581 | ) |  | (14,622 | ) |  | (138,577 | )
Gain on Previously Held Equity Interest | — |  |  | — |  |  | (623,663 | ) |  | — |
Loss (Gain) on Debt Extinguishment | 23,413 |  |  | 36 |  |  | 39,048 |  |  | (786 | )
Interest Expense | 38,438 |  |  | 40,683 |  |  | 76,989 |  |  | 82,289 |
Total Other Expense (Income) | 59,146 |  |  | (88,387 | ) |  | (528,165 | ) |  | (47,524 | )
Total Costs And Expenses | 371,832 |  |  | 191,303 |  |  | 108,321 |  |  | 649,659 |
Earnings From Continuing Operations Before Income Tax | 30,292 |  |  | 179,765 |  |  | 789,532 |  |  | 41,337 |
Income Tax (Benefit) Expense | (31,102 | ) |  | 57,958 |  |  | 182,592 |  |  | 10,536 |
Income From Continuing Operations | 61,394 |  |  | 121,807 |  |  | 606,940 |  |  | 30,801 |
Income From Discontinued Operations, net | — |  |  | 47,703 |  |  | — |  |  | 99,743 |
Net Income | 61,394 |  |  | 169,510 |  |  | 606,940 |  |  | 130,544 |
Less: Net Income Attributable to Noncontrolling Interest | 19,380 |  |  | — |  |  | 37,363 |  |  | — |
Net Income Attributable to CNX Resources Shareholders | $ | 42,014 |  |  | $ | 169,510 |  |  | $ | 569,577 |  |  | $ | 130,544 |

The accompanying notes are an integral part of these financial statements.
4

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(CONTINUED)

(Dollars in thousands, except per share data) | Three Months Ended |  | Six Months Ended
(Unaudited) | June 30, |  | June 30,
Earnings Per Share | 2018 |  | 2017 |  | 2018 |  | 2017
Basic |  |  |  |  |  |  |
Income from Continuing Operations | $ | 0.19 |  |  | $ | 0.53 |  |  | $ | 2.60 |  |  | $ | 0.13 |
Income from Discontinued Operations | — |  |  | 0.21 |  |  | — |  |  | 0.44 |
Total Basic Earnings Per Share | $ | 0.19 |  |  | $ | 0.74 |  |  | $ | 2.60 |  |  | $ | 0.57 |
Dilutive |  |  |  |  |  |  |
Income from Continuing Operations | $ | 0.19 |  |  | $ | 0.52 |  |  | $ | 2.57 |  |  | $ | 0.13 |
Income from Discontinued Operations | — |  |  | 0.21 |  |  | — |  |  | 0.43 |
Total Dilutive Earnings Per Share | $ | 0.19 |  |  | $ | 0.73 |  |  | $ | 2.57 |  |  | $ | 0.56 |
Dividends Declared Per Share | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

| Three Months Ended |  | Six Months Ended
(Dollars in thousands) | June 30, |  | June 30,
(Unaudited) | 2018 |  | 2017 |  | 2018 |  | 2017
Net Income | $ | 61,394 |  |  | $ | 169,510 |  |  | $ | 606,940 |  |  | $ | 130,544 |
Other Comprehensive Income: |  |  |  |  |  |  |
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($687), ($2,034), ($781), ($4,086)) | 1,812 |  |  | 3,464 |  |  | 1,982 |  |  | 6,966 |
Comprehensive Income | 63,206 |  |  | 172,974 |  |  | 608,922 |  |  | 137,510 |
Less: Comprehensive Income Attributable to Noncontrolling Interest | 19,380 |  |  | — |  |  | 37,363 |  |  | — |
Comprehensive Income Attributable to CNX Resources Shareholders | $ | 43,826 |  |  | $ | 172,974 |  |  | $ | 571,559 |  |  | $ | 137,510 |

The accompanying notes are an integral part of these financial statements.
5

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| (Unaudited) |  |
(Dollars in thousands) | June 30, 2018 |  | December 31, 2017
ASSETS |  |  |
Current Assets: |  |  |
Cash and Cash Equivalents | $ | 54,846 |  |  | $ | 509,167 |
Accounts and Notes Receivable: |  |  |
Trade | 132,016 |  |  | 156,817 |
Other Receivables | 17,421 |  |  | 48,908 |
Supplies Inventories | 10,499 |  |  | 10,742 |
Recoverable Income Taxes | 27,780 |  |  | 31,523 |
Prepaid Expenses | 56,431 |  |  | 95,347 |
Current Assets Held for Sale | 20,153 |  |  | — |
Total Current Assets | 319,146 |  |  | 852,504 |
Property, Plant and Equipment: |  |  |
Property, Plant and Equipment | 8,941,426 |  |  | 9,316,495 |
Less—Accumulated Depreciation, Depletion and Amortization | 2,399,555 |  |  | 3,526,742 |
Property, Plant and Equipment of Assets Held for Sale, Net | 230,593 |  |  | — |
Total Property, Plant and Equipment—Net | 6,772,464 |  |  | 5,789,753 |
Other Assets: |  |  |
Investment in Affiliates | 22,347 |  |  | 197,921 |
Goodwill | 796,359 |  |  | — |
Other Intangible Assets | 106,476 |  |  | — |
Other | 190,966 |  |  | 91,735 |
Total Other Assets | 1,116,148 |  |  | 289,656 |
TOTAL ASSETS | $ | 8,207,758 |  |  | $ | 6,931,913 |

The accompanying notes are an integral part of these financial statements.
6

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| (Unaudited) |  |
(Dollars in thousands, except per share data) | June 30, 2018 |  | December 31, 2017
LIABILITIES AND EQUITY |  |  |
Current Liabilities: |  |  |
Accounts Payable | $ | 186,397 |  |  | $ | 211,161 |
Current Portion of Long-Term Debt | 6,915 |  |  | 7,111 |
Other Accrued Liabilities | 227,871 |  |  | 223,407 |
Current Liabilities Held for Sale | 53,808 |  |  | — |
Total Current Liabilities | 474,991 |  |  | 441,679 |
Long-Term Debt: |  |  |
Long-Term Debt | 2,330,780 |  |  | 2,187,026 |
Capital Lease Obligations | 16,846 |  |  | 20,347 |
Total Long-Term Debt | 2,347,626 |  |  | 2,207,373 |
Deferred Credits and Other Liabilities: |  |  |
Deferred Income Taxes | 235,407 |  |  | 44,373 |
Asset Retirement Obligations | 7,606 |  |  | 198,768 |
Other | 103,205 |  |  | 139,821 |
Total Deferred Credits and Other Liabilities | 346,218 |  |  | 382,962 |
TOTAL LIABILITIES | 3,168,835 |  |  | 3,032,014 |
Stockholders’ Equity: |  |  |
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 213,420,535 Issued and Outstanding at June 30, 2018; 223,743,322 Issued and Outstanding at December 31, 2017 | 2,138 |  |  | 2,241 |
Capital in Excess of Par Value | 2,372,650 |  |  | 2,450,323 |
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding | — |  |  | — |
Retained Earnings | 1,940,507 |  |  | 1,455,811 |
Accumulated Other Comprehensive Loss | (6,494 | ) |  | (8,476 | )
Total CNX Resources Stockholders’ Equity | 4,308,801 |  |  | 3,899,899 |
Noncontrolling Interest | 730,122 |  |  | — |
TOTAL STOCKHOLDERS' EQUITY | 5,038,923 |  |  | 3,899,899 |
TOTAL LIABILITIES AND EQUITY | $ | 8,207,758 |  |  | $ | 6,931,913 |

The accompanying notes are an integral part of these financial statements.
7

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Dollars in thousands) | Common Stock |  | Capital in Excess of Par Value |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total CNX Resources Corporation Stockholders’ Equity |  | Non- Controlling Interest |  | Total Stockholders' Equity
Balance at December 31, 2017 | $ | 2,241 |  |  | $ | 2,450,323 |  |  | $ | 1,455,811 |  |  | $ | (8,476 | ) |  | $ | 3,899,899 |  |  | $ | — |  |  | $ | 3,899,899 |
(Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income | — |  |  | — |  |  | 569,577 |  |  | — |  |  | 569,577 |  |  | 37,363 |  |  | 606,940 |
Other Comprehensive Income (Net of ($781) Tax) | — |  |  | — |  |  | — |  |  | 1,982 |  |  | 1,982 |  |  | — |  |  | 1,982 |
Comprehensive Income | — |  |  | — |  |  | 569,577 |  |  | 1,982 |  |  | 571,559 |  |  | 37,363 |  |  | 608,922 |
Issuance of Common Stock | 7 |  |  | 1,556 |  |  | — |  |  | — |  |  | 1,563 |  |  | — |  |  | 1,563 |
Purchase and Retirement of Common Stock (11,086,082 shares) | (110 | ) |  | (88,578 | ) |  | (80,031 | ) |  | — |  |  | (168,719 | ) |  | — |  |  | (168,719 | )
Shares Withheld for Taxes | — |  |  | — |  |  | (4,850 | ) |  | — |  |  | (4,850 | ) |  | (347 | ) |  | (5,197 | )
Acquisition of CNX Gathering, LLC | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 718,577 |  |  | 718,577 |
Amortization of Stock-Based Compensation Awards | — |  |  | 9,349 |  |  | — |  |  | — |  |  | 9,349 |  |  | 1,269 |  |  | 10,618 |
Distributions to CNXM Noncontrolling Interest Holders | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (26,740 | ) |  | (26,740 | )
Balance at June 30, 2018 | $ | 2,138 |  |  | $ | 2,372,650 |  |  | $ | 1,940,507 |  |  | $ | (6,494 | ) |  | $ | 4,308,801 |  |  | $ | 730,122 |  |  | $ | 5,038,923 |

The accompanying notes are an integral part of these financial statements.
8

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands) | Six Months Ended
(Unaudited) | June 30,
Cash Flows from Operating Activities: | 2018 |  | 2017
Net Income | $ | 606,940 |  |  | $ | 130,544 |
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities: |  |  |
Net Income from Discontinued Operations | — |  |  | (99,743 | )
Depreciation, Depletion and Amortization | 243,754 |  |  | 187,318 |
Amortization of Deferred Financing Costs | 4,821 |  |  | — |
Impairment of Exploration and Production Properties | — |  |  | 137,865 |
Impairment of Other Intangible Assets | 18,650 |  |  | — |
Stock-Based Compensation | 10,618 |  |  | 7,917 |
Gain on Sale of Assets | (14,622 | ) |  | (138,577 | )
Gain on Previously Held Equity Interest | (623,663 | ) |  | — |
Loss (Gain) on Debt Extinguishment | 39,048 |  |  | (786 | )
(Gain) Loss on Commodity Derivative Instruments | (60,747 | ) |  | (61,325 | )
Net Cash Paid in Settlement of Commodity Derivative Instruments | (307 | ) |  | (79,388 | )
Deferred Income Taxes | 190,194 |  |  | 10,536 |
Equity in Earnings of Affiliates | (3,447 | ) |  | (22,385 | )
Changes in Operating Assets: |  |  |
Accounts and Notes Receivable | 44,156 |  |  | 6,661 |
Recoverable Income Taxes | 3,743 |  |  | 6,492 |
Supplies Inventories | 243 |  |  | 328 |
Prepaid Expenses | 1,327 |  |  | 6,480 |
Changes in Operating Liabilities: |  |  |
Accounts Payable | (3,198 | ) |  | 20,813 |
Accrued Interest | (3,358 | ) |  | 795 |
Other Operating Liabilities | 1,504 |  |  | 699 |
Changes in Other Liabilities | (5,374 | ) |  | 13,516 |
Other | 648 |  |  | 44,572 |
Net Cash Provided by Continuing Operating Activities | 450,930 |  |  | 172,332 |
Net Cash Provided by Discontinued Operating Activities | — |  |  | 128,140 |
Net Cash Provided by Operating Activities | 450,930 |  |  | 300,472 |
Cash Flows from Investing Activities: |  |  |
Capital Expenditures | (496,659 | ) |  | (249,962 | )
CNX Gathering LLC Acquisition, Net of Cash Acquired | (299,272 | ) |  | — |
Proceeds from Asset Sales | 153,420 |  |  | 328,167 |
Net Distributions from Equity Affiliates | 3,650 |  |  | 24,700 |
Net Cash (Used in) Provided by Continuing Investing Activities | (638,861 | ) |  | 102,905 |
Net Cash Provided by Discontinued Investing Activities | — |  |  | (6,380 | )
Net Cash (Used in) Provided by Investing Activities | (638,861 | ) |  | 96,525 |
Cash Flows from Financing Activities: |  |  |
Payments on Miscellaneous Borrowings | (3,748 | ) |  | (5,973 | )
Payments on Long-Term Notes | (723,419 | ) |  | (117,185 | )
Net Payments on CNXM Revolving Credit Facility | (138,500 | ) |  | — |
Proceeds from CNX Revolving Credit Facility | 422,000 |  |  | — |
Proceeds from Issuance of CNXM Senior Notes | 394,000 |  |  | — |
Distributions to CNXM Noncontrolling Interest Holders | (26,740 | ) |  | — |
Proceeds from Issuance of Common Stock | 1,563 |  |  | 723 |
Shares Withheld for Taxes | (5,197 | ) |  | (7,093 | )
Purchases of Common Stock | (166,720 | ) |  | — |
Debt Repurchase and Financing Fees | (19,629 | ) |  | (298 | )
Net Cash Used in Continuing Financing Activities | (266,390 | ) |  | (129,826 | )
Net Cash Used in Discontinued Financing Activities | — |  |  | (21,935 | )
Net Cash Used in Financing Activities | (266,390 | ) |  | (151,761 | )
Net (Decrease) Increase in Cash and Cash Equivalents | (454,321 | ) |  | 245,236 |
Cash and Cash Equivalents at Beginning of Period | 509,167 |  |  | 46,299 |
Cash and Cash Equivalents at End of Period | $ | 54,846 |  |  | $ | 291,535 |

The accompanying notes are an integral part of these financial statements.
9

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, 2018 are not necessarily indicative of the results that may be expected for future periods.
The Consolidated Balance Sheet at December 31, 2017 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, 2017 included in CNX Resources Corporation's ("CNX," the "Company," "we," "us," or "our") Annual Report on Form 10-K as filed with the Securities and Exchange Commission on February 7, 2018.
Certain amounts in prior periods have been reclassified to conform to the current period presentation. On November 28, 2017, the Company spun-off the coal operations previously held by CNX, which were comprised of the Pennsylvania Mining Complex, Baltimore Marine Terminal, its direct and indirect ownership interest in CONSOL Coal Resources LP, formerly known as CNXC Coal Resources LP, and other related coal assets. The financial position, results of operations and cash flows of the coal operations are reflected as discontinued operations for all periods presented through the date of the spin-off. See Note 5 - Discontinued Operations for further details regarding the spin-off.
The Consolidated Balance Sheet at June 30, 2018 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 interest on January 3, 2018 (See Note 6 - Acquisitions and Dispositions for more information). The purchase accounting remains preliminary as contemplated by Generally Accepted Accounting Principles (GAAP) and, as a result, there may be upon further review future changes to the value, as well as allocation, of the acquired assets and liabilities, associated amortization expense, goodwill and the gain on the previously held equity interest. These changes may be material.
NOTE 2—EARNINGS PER SHARE:
Basic earnings per share are computed by dividing net income attributable to CNX shareholders by the weighted average shares outstanding during the reporting period. Dilutive 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 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,
| 2018 |  | 2017 |  | 2018 |  | 2017
Antidilutive Options | 2,300,785 |  |  | 2,360,197 |  |  | 2,300,785 |  |  | 2,360,197 |
Antidilutive Restricted Stock Units | — |  |  | 194,071 |  |  | 7,828 |  |  | 190,658 |
Antidilutive Performance Share Units | — |  |  | 1,284,924 |  |  | 178,189 |  |  | 1,284,924 |
Antidilutive Performance Stock Options | 927,268 |  |  | 802,804 |  |  | 927,268 |  |  | 802,804 |
| 3,228,053 |  |  | 4,641,996 |  |  | 3,414,070 |  |  | 4,638,583 |

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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,
| 2018 |  | 2017 |  | 2018 |  | 2017
Options | 73,583 |  |  | 28,838 |  |  | 227,301 |  |  | 90,462 |
Restricted Stock Units | 7,260 |  |  | 221 |  |  | 178,397 |  |  | 334,261 |
Performance Share Units | — |  |  | — |  |  | 357,597 |  |  | 560,936 |
| 80,843 |  |  | 29,059 |  |  | 763,295 |  |  | 985,659 |

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

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
| 2018 |  | 2017 |  | 2018 |  | 2017
Income from Continuing Operations | $ | 61,394 |  |  | $ | 121,807 |  |  | $ | 606,940 |  |  | $ | 30,801 |
Less: Net Income Attributable to Non-Controlling Interest | 19,380 |  |  | — |  |  | 37,363 |  |  | — |
Net Income from Continuing Operations Attributable to CNX Resources Shareholders | $ | 42,014 |  |  | $ | 121,807 |  |  | $ | 569,577 |  |  | $ | 30,801 |
Income from Discontinued Operations | — |  |  | 47,703 |  |  | — |  |  | 99,743 |
Net Income Attributable to CNX Resources Shareholders | $ | 42,014 |  |  | $ | 169,510 |  |  | $ | 569,577 |  |  | $ | 130,544 |
Weighted-average shares of common stock outstanding | 215,991,490 |  |  | 230,058,422 |  |  | 218,944,422 |  |  | 229,938,462 |
Effect of dilutive shares | 2,938,470 |  |  | 2,139,974 |  |  | 2,701,442 |  |  | 2,286,571 |
Weighted-average diluted shares of common stock outstanding | 218,929,960 |  |  | 232,198,396 |  |  | 221,645,864 |  |  | 232,225,033 |
Earnings per Share: |  |  |  |  |  |  |
Basic (Continuing Operations) | $ | 0.19 |  |  | $ | 0.53 |  |  | $ | 2.60 |  |  | $ | 0.13 |
Basic (Discontinued Operations) | — |  |  | 0.21 |  |  | — |  |  | 0.44 |
Total Basic | $ | 0.19 |  |  | $ | 0.74 |  |  | $ | 2.60 |  |  | $ | 0.57 |
Dilutive (Continuing Operations) | $ | 0.19 |  |  | $ | 0.52 |  |  | $ | 2.57 |  |  | $ | 0.13 |
Dilutive (Discontinued Operations) | — |  |  | 0.21 |  |  | — |  |  | 0.43 |
Total Dilutive | $ | 0.19 |  |  | $ | 0.73 |  |  | $ | 2.57 |  |  | $ | 0.56 |

NOTE 3—CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS:
Changes in Accumulated Other Comprehensive Loss related to pension obligations, net of tax, were as follows:

Balance at December 31, 2017 | $ | (8,476 | )
Other Comprehensive Income before Reclassifications | 1,643 |
Amounts Reclassified from Accumulated Other Comprehensive Loss, net of tax | 339 |
Current Period Other Comprehensive Income | 1,982 |
Balance at June 30, 2018 | $ | (6,494 | )

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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,
| 2018 |  | 2017 |  | 2018 |  | 2017
Actuarially Determined Long-Term Liability Adjustments* |  |  |  |  |  |  |
Amortization of Prior Service Costs | $ | (90 | ) |  | $ | (749 | ) |  | $ | (181 | ) |  | $ | (1,498 | )
Recognized Net Actuarial Loss | 354 |  |  | 6,247 |  |  | 708 |  |  | 12,550 |
Total | 264 |  |  | 5,498 |  |  | 527 |  |  | 11,052 |
Less: Tax Benefit | 94 |  |  | 2,034 |  |  | 188 |  |  | 4,086 |
Net of Tax | $ | 170 |  |  | $ | 3,464 |  |  | $ | 339 |  |  | $ | 6,966 |

*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the three and six months ended June 30, 2018.
NOTE 4—REVENUE FROM CONTRACTS WITH CUSTOMERS:
On January 1, 2018, the Company adopted Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method, which did not result in any changes to previously reported financial information. The updates related to the new revenue standard were applied only to contracts that were not complete as of January 1, 2018.
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.
Nature of Performance Obligations
At contract inception, the Company assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promised good or service that is distinct. To identify the performance obligations, the Company considers all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices.
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 Statement 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 represent 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.
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Transaction price allocated to remaining performance obligations
Accounting Standards Codifiation (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 our 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, we have 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 $185,984 as of June 30, 2018. The Company expects to recognize net revenue of $55,304 in the next 12 months and $42,227 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, we have 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 variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our midstream contracts, 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
We record 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, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and six months ended June 30, 2018 and 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
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Disaggregation of Revenue
The following table is a disaggregation of our revenue by major sources:

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
2018 |  | 2017 |  | 2018 |  | 2017
Revenue from Contracts with Customers |  |  |  |  |  |  |
Natural Gas Revenue | $ | 289,294 |  |  | $ | 233,723 |  |  | $ | 636,642 |  |  | $ | 507,270 |
NGLs Revenue | 39,557 |  |  | 21,637 |  |  | 90,441 |  |  | 60,920 |
Condensate Revenue | 4,996 |  |  | 3,885 |  |  | 11,499 |  |  | 8,189 |
Oil Revenue | 670 |  |  | 1,061 |  |  | 1,558 |  |  | 1,690 |
Total Natural Gas, NGLs and Oil Revenue | 334,517 |  |  | 260,306 |  |  | 740,140 |  |  | 578,069 |
Purchased Gas Revenue | 9,930 |  |  | 10,316 |  |  | 27,985 |  |  | 19,294 |
Midstream Revenue | 23,483 |  |  | — |  |  | 49,737 |  |  | — |
Other Sources of Revenue and Other Operating Income |  |  |  |  |  |  |
Gain on Commodity Derivative Instruments | 25,660 |  |  | 83,788 |  |  | 60,747 |  |  | 61,325 |
Other Operating Income | 8,534 |  |  | 16,658 |  |  | 19,244 |  |  | 32,308 |
Total Revenue and Other Operating Income | $ | 402,124 |  |  | $ | 371,068 |  |  | $ | 897,853 |  |  | $ | 690,996 |

The disaggregated revenue information corresponds with the Company’s segment reporting.
Contract balances
We invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts with customers do not give rise to contract assets or liabilities under ASC 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer.
The opening and closing balances of the Company’s receivables related to contracts with customers were $156,817 and $132,016, respectively. Included in the opening balance are receivables related to the January 3, 2018 acquisition of $9,353 (see Note 6 - Acquisitions and Dispositions for more information).
NOTE 5—DISCONTINUED OPERATIONS:
On November 28, 2017, CNX announced that it had completed the tax-free spin-off of its coal business resulting in two independent, publicly traded companies: (i) a coal company, CONSOL Energy, formerly known as CONSOL Mining Corporation and (ii) CNX, a natural gas exploration and production company. Following the separation, CONSOL Energy and its subsidiaries hold the coal assets previously held by CNX, including its Pennsylvania Mining Complex, Baltimore Marine Terminal, its direct and indirect ownership interest in CONSOL Coal Resources LP, formerly known as CNX Coal Resources LP, and other related coal assets previously held by CNX. As of the close of business on November 28, 2017, CNX's shareholders received one share of CONSOL Energy common stock for every eight shares of CNX's common stock held as of November 15, 2017. The coal business has been reclassified to discontinued operations for all periods presented.
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The following table details selected financial information for the divested business included within discontinued operations:

| For the Three Months Ended |  | For the Six Months Ended
| June 30, 2017 |  | June 30, 2017
Coal Revenue | $ | 303,707 |  |  | $ | 620,155 |
Other Outside Sales | 14,856 |  |  | 27,742 |
Freight-Outside Coal | 17,763 |  |  | 30,045 |
Miscellaneous Other Income | 8,934 |  |  | 26,330 |
Gain on Sale of Assets | 5,581 |  |  | 13,536 |
Total Revenue and Other Income | $ | 350,841 |  |  | $ | 717,808 |
Total Costs | 289,790 |  |  | 605,620 |
Income From Operations Before Income Taxes | $ | 61,051 |  |  | $ | 112,188 |
Income Tax Expense | 9,035 |  |  | 2,668 |
Less: Net Income Attributable to Noncontrolling Interest | 4,313 |  |  | 9,777 |
Income From Discontinued Operations, net | $ | 47,703 |  |  | $ | 99,743 |

There were no remaining major classes of assets or liabilities of discontinued operations at June 30, 2018 and December 31, 2017.
NOTE 6—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 19 - 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 the Gain on Asset Sales line of the Consolidated Statements of Income.
On December 14, 2017, CNX Gas entered into a purchase agreement with NBL Midstream, LLC (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 LLC 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 LLC 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 such business combination 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.
15

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 the Gain on Previously Held Equity Interest line of the Consolidated Statements of Income.
The fair values of the previously held equity interests were based on inputs that are not observable in the market and therefore represent Level 3 inputs (See Note 14 - Fair Value of Financial Instruments). These fair values were 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, are still under review, and are subject to change. These inputs have a significant impact on the valuation of the previously held equity interests and future changes may occur.
The estimated 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 estimate of fair value 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 estimated fair value of the midstream facilities and equipment represents a Level 3 fair value measurement.
As part of the preliminary 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 determination of fair value include future revenue estimates, future cost assumptions, and estimated customer retention rates. As a result, the estimated fair value of the identified intangible assets represents a Level 3 fair value measurement. Differences between the preliminary purchase price allocation and the final purchase price allocation may change the amount of intangible assets and goodwill ultimately recognized in conjunction with the Midstream Acquisition.
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 estimated values of assets and liabilities assumed based on the fair value as of January 3, 2018, with any excess of the purchase price over the estimated fair value of the identified net assets acquired recorded as goodwill. The preliminary purchase price allocation will be subject to further refinement, which may result in material changes.
Estimated Fair Value of Consideration Transferred:

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 |

16

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

Fair Value of Assets Acquired: |
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 for the three and six months ended June 30, 2018.

| Three Months Ended |  | Six Months Ended
| June 30, 2018 |  | June 30, 2018
Midstream Revenue | $ | 61,325 |  |  | $ | 125,503 |
Earnings From Continuing Operations Before Income Tax | $ | 27,795 |  |  | $ | 63,329 |

Unaudited Pro Forma Information (Midstream Acquisition)
The following table presents unaudited pro forma combined financial information for the three and six months ended June 30, 2017, which presents the Company’s results as though the Midstream Acquisition had been completed at January 1, 2017. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the acquisition been completed at January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.

| Pro Forma
(in thousands, except per share data) (unaudited) | Three Months Ended June 30, 2017 |  | Six Months Ended June 30, 2017
Pro Forma Total Revenue and Other Operating Income | $ | 395,774 |  |  | $ | 740,411 |
Pro Forma Net Income from Continuing Operations | $ | 150,789 |  |  | $ | 92,979 |
Less: Pro Forma Net income Attributable to Noncontrolling Interests | $ | 18,720 |  |  | $ | 38,134 |
Pro Forma Net Income from Continuing Operations Attributable to CNX | $ | 132,069 |  |  | $ | 54,845 |
Pro Forma Income per Share from Continuing Operations (Basic) | $ | 0.58 |  |  | $ | 0.24 |
Pro Forma Income per Share from Continuing Operations (Diluted) | $ | 0.58 |  |  | $ | 0.24 |

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NOTE 7—COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COST:
Components of Net Periodic Benefit Cost are as follows:

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
| 2018 |  | 2017 |  | 2018 |  | 2017
Service Cost | $ | 96 |  |  | $ | 149 |  |  | $ | 193 |  |  | $ | 193 |
Interest Cost | 300 |  |  | 476 |  |  | 600 |  |  | 619 |
Amortization of Prior Service Credits | (90 | ) |  | (143 | ) |  | (181 | ) |  | (186 | )
Recognized Net Actuarial Loss | 373 |  |  | 604 |  |  | 746 |  |  | 786 |
Curtailment Gain | (416 | ) |  | — |  |  | (416 | ) |  | — |
Net Periodic Benefit Cost | $ | 263 |  |  | $ | 1,086 |  |  | $ | 942 |  |  | $ | 1,412 |

During June 2018, a plan amendment was announced that freezes the benefits for the Defined Contribution Restoration Plan effective July 1, 2018. Employees hired after this date will not be eligible for this benefit plan. In addition, current participants will receive no further compensation credits after that date, with the last award year being 2017. Annual interest credits will continue to be made in accordance with the terms of the plan. This amendment triggered a curtailment gain of $416. The curtailment resulted in a plan remeasurement, decreasing the plan liabilities by $2,235 at June 30, 2018.
NOTE 8—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 tax 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.
The effective tax rates for the three and six months ended June 30, 2017 were 32.2% and 25.5%, respectively. The effective rate for the six months ended June 30, 2017 differs from the U.S. federal statutory rate of 35% primarily due to state income taxes and equity compensation.
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the "Act") which, among other things, lowered the U.S. Federal corporate income tax rate from 35% to 21%, repealed the corporate alternative minimum tax ("AMT"), and provided for a refund of previously accrued AMT credits. The Company recorded a net tax benefit to reflect the impact of the Act as of December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. Largely, the benefits recorded in the period ending December 31, 2017 related to the Act are in recognition of the revaluation of deferred tax assets and liabilities, a benefit of $115,291, and a benefit for the reversal of a valuation allowance previously recorded against a deferred tax asset for AMT credits which are now refundable, a benefit of $154,384.
The net benefits for the Act, as recorded as provisional amounts, as of June 30, 2018 represent the Company's best estimate using information available to the Company as of June 30, 2018. The Company anticipates U.S. regulatory agencies will issue further regulations over the next year which may alter this estimate. The Company is still evaluating, among other things, the application of limitations for executive compensation related to contracts existing prior to November 2, 2017, and provisions in the Act addressing the deductibility of interest expense after January 1, 2018. The Company will refine its estimates to incorporate new or better information as it comes available through the filing date of its 2017 U.S. income tax returns in the fourth quarter of 2018. During the second quarter, the company filed a Federal NOL carryback resulting in a financial statement benefit of $20,000 through the realization of the Federal NOLs at a 35% tax rate as a carryback versus the current 21% tax rate as a carryforward.
The total amount of uncertain tax positions at June 30, 2018 and December 31, 2017 were $39,953 and $37,813, respectively. If these uncertain tax positions were recognized, approximately $31,516 and $29,376 would affect CNX's effective tax rate at June 30, 2018 and December 31, 2017, respectively. There was a $2,140 change to the unrecognized tax benefits during the six months ended June 30, 2018.
CNX recognizes accrued interest related to uncertain tax positions in interest expense. As of June 30, 2018 and December 31, 2017, the Company reported an accrued interest liability relating to uncertain tax positions of $814 and $644, respectively, in Other Liabilities on the Consolidated Balance Sheets. The accrued interest liability includes $169 of accrued interest expense that is reflected in the Company's Consolidated Statements of Income for the six months ended June 30, 2018.
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CNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of June 30, 2018 and December 31, 2017, 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 states and Canadian 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 years before 2014. The Joint Committee on Taxation concluded its review of the audit of tax year 2015 on March 21, 2018. The audit resulted in a $108,651 reduction to CNX's net operating loss, primarily due to a reduction in the depreciation as an offset to the bonus depreciation taken in the 2010-2013 IRS audit. There was no cash impact from the audit.
NOTE 9—PROPERTY, PLANT AND EQUIPMENT:

| June 30, 2018 |  | December 31, 2017
Property, Plant and Equipment |  |  |
Intangible drilling cost | $ | 3,772,658 |  |  | $ | 3,849,689 |
Proved gas properties | 937,243 |  |  | 1,999,891 |
Gas gathering equipment | 2,017,836 |  |  | 1,182,234 |
Unproved gas properties | 1,093,985 |  |  | 919,733 |
Gas wells and related equipment | 743,752 |  |  | 834,120 |
Surface land and other equipment | 309,894 |  |  | 309,602 |
Other gas assets | 66,058 |  |  | 221,226 |
Total Property, Plant and Equipment | 8,941,426 |  |  | 9,316,495 |
Less: Accumulated Depreciation, Depletion and Amortization | 2,399,555 |  |  | 3,526,742 |
Total Property, Plant and Equipment Assets Held for Sale - Net | 230,593 |  |  | — |
Total Property, Plant and Equipment - Net | $ | 6,772,464 |  |  | $ | 5,789,753 |

Property, Plant and Equipment Held for Sale
CNX is party to an industry participation agreement (referred to as a "joint venture" or "JV") that provided drilling and completion carries for the Company's retained interests. This joint development agreement is with Hess Ohio Developments, LLC (Hess) with respect to approximately 125 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess was obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CNX working interest obligations as the acreage is developed. As of December 31, 2016, Hess' entire carry obligation had been satisfied.
In June 2018, the Company entered into an agreement to sell substantially all of its Ohio Utica joint venture ("JV") assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble counties, which includes approximately 26,000 net undeveloped acres for net cash proceeds of approximately $400,000. CNX received a deposit from the seller of approximately $40,000 in the second quarter, which was included in Assets Held for Sale on the Consolidated Balance Sheet and Proceeds from Asset Sales within the Consolidated Statements of Cash Flow. As part of the required evaluation under the held for sale accounting guidance, the Company determined that the approximate fair value less costs to sell exceeded the carrying value of the net assets and thus no impairment charge was recorded. The Company anticipates completing the sale of these assets during the third quarter of 2018.
Property, Plant and Equipment Impairment
In February 2017, the Company approved a plan to sell subsidiaries Knox Energy LLC and Coalfield Pipeline Company (collectively, "Knox"). Knox met all of the criteria to be classified as held for sale in February 2017. The potential disposal of Knox did not represent a strategic shift that would have a major effect on the Company's operations and financial results and was, therefore, not classified as discontinued operations in accordance with ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360). As part of the required evaluation under the held for sale guidance, the asset's book value was evaluated and adjusted to the lower of its carrying amount or fair value less cost to sell. The Company determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets which resulted in an impairment of $137,865 in February 2017, included in Impairment of Exploration and Production Properties within the Consolidated Statements of Income. The sale of Knox closed in the second quarter of 2017.
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NOTE 10—REVOLVING CREDIT FACILITIES:
CNX Resources Corporation (CNX)
On March 8, 2018, CNX amended and restated its senior secured revolving credit facility, which expires on March 8, 2023.
The amended and restated credit facility increased lenders' commitments from $1,500,000 to $2,100,000 with an accordion feature that allows the Company to increase the commitments to $3,000,000. The initial borrowing base increased from $2,000,000 to $2,500,000, and the letters of credit aggregate sub-limit remained unchanged at $650,000. The credit facility matures on March 8, 2023, provided that if the aggregate principal amount of our existing 5.875% Senior Notes due 2022, 8.00% Senior Notes due 2023 and certain other publicly traded debt securities outstanding 91 days prior to the earliest maturity of such debt (such date, the "Springing Maturity Date") is greater than $500,000, then the credit facility will mature on the Springing Maturity Date.
The 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 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 facility contains a number of affirmative and negative covenants that include, among others, covenants 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 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, 2018.
At June 30, 2018, the $2,100,000 facility had $422,000 of borrowings outstanding and $251,342 of letters of credit outstanding, leaving $1,426,658 of unused capacity. At December 31, 2017, the $1,500,000 facility had no borrowings outstanding and $239,072 of letters of credit outstanding, leaving $1,260,928 of unused capacity.
CNX Midstream Partners LP (CNXM)
On March 8, 2018, CNXM entered into a new $600,000 senior secured revolving credit facility that matures on March 8, 2023. The new revolving credit facility replaced its prior $250,000 senior secured revolving credit facility.
The facility includes restrictions on 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 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; (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 (x) a maximum total leverage ratio of no greater than between 4.75 to 1.00 ranging to no greater than 5.50 to 1.00 in certain circumstances; (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, 2018.
The 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 facility are secured by substantially all of the assets of CNXM and its wholly-owned subsidiaries. CNX is not a guarantor under the facility.
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At June 30, 2018, the $600,000 facility had $11,000 of borrowings outstanding.
NOTE 11—LONG-TERM DEBT:

| June 30, 2018 |  | December 31, 2017
Debt: |  |  |
Senior Notes due April 2022 at 5.875% (Principal of $1,314,307 and $1,705,682 plus Unamortized Premium of $2,416 and $3,544, respectively) | $ | 1,316,723 |  |  | $ | 1,709,226 |
CNX Revolving Credit Facility | 422,000 |  |  | — |
CNX Midstream Partners LP Senior Notes due March 2026 at 6.50% (Principal of $400,000 less Unamortized Discount of $5,750 at June 30, 2018) | 394,250 |  |  | — |
Senior Notes due April 2023 at 8.00% (Principal of $200,000 and $500,000 less Unamortized Discount of $1,720 and $4,751, respectively) | 198,281 |  |  | 495,249 |
CNX Midstream Partners LP Revolving Credit Facility | 11,000 |  |  | — |
Other Note Maturing in 2018 (Principal of $358 less Unamortized Discount of $8 at December 31, 2017) | — |  |  | 350 |
Less: Unamortized Debt Issuance Costs | 11,474 |  |  | 17,536 |
| 2,330,780 |  |  | 2,187,289 |
Less: Amounts Due in One Year* | — |  |  | 263 |
Long-Term Debt | $ | 2,330,780 |  |  | $ | 2,187,026 |

* Excludes current portion of Capital Lease Obligations of $6,915 and $6,848 at June 30, 2018 and December 31, 2017, respectively.
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 (Gain) on Debt Extinguishment on 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 (Gain) on Debt Extinguishment on the Consolidated Statements of Income.
During the three and six months ended June 30, 2017, CNX purchased $19,069 and $119,025, respectively, of its outstanding 5.875% senior notes due in 2022. As part of this transaction, a loss of $36 and a gain of $786, respectively, were included in Loss (Gain) on Debt Extinguishment on the Consolidated Statements of Income.
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, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental 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. The amount claimed against CNX is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case.
The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized:
Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of force-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on allegations that CNX Gas failed either to pay royalties due to conflicting claimants or deemed lessors, or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September
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30, 2013, the District Judge entered an Order certifying the class, and CNX Gas appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order certifying four issues for class treatment: (1) allegedly excessive deductions; (2) royalties based on purported improperly low prices; (3) deduction of severance taxes; and (4) Plaintiffs' request for an accounting. On April 13, 2017, CNX filed a Petition for Allowance of Appeal with the Fourth Circuit, and on May 22, 2017 the Petition was denied. CNX and plaintiffs’ counsel have reached an agreement in principal to settle the certified class claims. On March 20, 2018, the Court preliminarily approved the class settlement, and on August 23, 2018, the Court will conduct a hearing to consider final approval of the proposed Settlement Agreement and Class Counsels’ request for attorneys’ fees. No class member has opted out of, or objected to, the settlement and the time for doing so has passed. The Company has paid the settlement into an escrow account from which it will be disbursed upon final court approval (or returned to CNX).
At June 30, 2018, 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 table. 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 these commitments 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 | $ | 251,057 |  |  | $ | 251,057 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other | 285 |  |  | 285 |  |  | — |  |  | — |  |  | — |
Total Letters of Credit | 251,342 |  |  | 251,342 |  |  | — |  |  | — |  |  | — |
Surety Bonds: |  |  |  |  |  |  |  |  |
Employee-Related | 1,850 |  |  | 1,850 |  |  | — |  |  | — |  |  | — |
Environmental | 25,973 |  |  | 25,914 |  |  | 59 |  |  | — |  |  | — |
Other | 12,315 |  |  | 10,805 |  |  | 1,510 |  |  | — |  |  | — |
Total Surety Bonds | 40,138 |  |  | 38,569 |  |  | 1,569 |  |  | — |  |  | — |
Total Commitments | $ | 291,480 |  |  | $ | 289,911 |  |  | $ | 1,569 |  |  | $ | — |  |  | $ | — |

Excluded from the above table are commitments and guarantees, that relate to discontinued operations, entered into in conjunction with the spin-off of the Company's coal business (See Note 5 - Discontinued Operations). Although CONSOL Energy has agreed to indemnify us to the extent that we are called upon to pay any of these liabilities, there is no assurance that CONSOL Energy will satisfy its obligations to indemnify us in these situations.
CNX uses various leased facilities and equipment in its operations. Future minimum lease payments under operating leases at June 30, 2018 are as follows:

Operating Lease Obligations Due | Amount
Less than 1 year | $ | 9,607 |
1 - 3 years | 13,325 |
3 - 5 years | 10,756 |
More than 5 years | 38,477 |
Total Operating Lease Obligations | $ | 72,165 |

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 on the Consolidated Balance Sheets. As of June 30, 2018, the purchase obligations for each of the next five years and beyond were as follows:
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Obligations Due | Amount
Less than 1 year | $ | 207,148 |
1 - 3 years | 419,091 |
3 - 5 years | 306,479 |
More than 5 years | 620,806 |
Total Purchase Obligations | $ | 1,553,524 |

NOTE 13—DERIVATIVE INSTRUMENTS:
CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. These natural gas and NGL 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 on 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 at June 30, 2018 and December 31, 2017 were as follows:

| June 30, |  | December 31, |  | Forecasted to
| 2018 |  | 2017 |  | Settle Through
Natural Gas Commodity Swaps (Bcf) | 1,064.1 |  |  | 1,067.2 |  |  | 2023
Natural Gas Basis Swaps (Bcf) | 775.5 |  |  | 688.1 |  |  | 2023

The gross fair value of CNX's derivative instruments at June 30, 2018 and December 31, 2017 was as follows:

Asset Derivative Instruments |  | Liability Derivative Instruments
| June 30, |  | December 31, |  |  | June 30, |  | December 31,
| 2018 |  | 2017 |  |  | 2018 |  | 2017
Commodity Swaps: |  |  |  |  |  |  |  |
Prepaid Expense | $ | 27,226 |  |  | $ | 62,369 |  |  | Other Accrued Liabilities | $ | 26,943 |  |  | $ | 5,985 |
Other Assets | 132,594 |  |  | 59,281 |  |  | Other Liabilities | 10,381 |  |  | 42,419 |
Total Asset | $ | 159,820 |  |  | $ | 121,650 |  |  | Total Liability | $ | 37,324 |  |  | $ | 48,404 |
Basis Only Swaps: |  |  |  |  |  |  |  |
Prepaid Expense | $ | 10,932 |  |  | $ | 14,965 |  |  | Other Accrued Liabilities | $ | 26,969 |  |  | $ | 35,306 |
Other Assets | 35,101 |  |  | 24,223 |  |  | Other Liabilities | 20,557 |  |  | 17,179 |
Total Asset | $ | 46,033 |  |  | $ | 39,188 |  |  | Total Liability | $ | 47,526 |  |  | $ | 52,485 |

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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,
| 2018 |  | 2017 |  | 2018 |  | 2017
Cash Received (Paid) in Settlement of Commodity Derivative Instruments: |  |  |  |  |  |  |
Commodity Swaps: |  |  |  |  |  |  |
Natural Gas | $ | 17,058 |  |  | $ | (15,509 | ) |  | $ | 16,624 |  |  | $ | (40,116 | )
Propane | — |  |  | — |  |  | — |  |  | (1,216 | )
Natural Gas Basis Swaps | (374 | ) |  | (16,776 | ) |  | (16,931 | ) |  | (38,056 | )
Total Cash Received (Paid) in Settlement of Commodity Derivative Instruments | 16,684 |  |  | (32,285 | ) |  | (307 | ) |  | (79,388 | )
Unrealized Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |
Commodity Swaps: |  |  |  |  |  |  |
Natural Gas | 46,450 |  |  | 70,282 |  |  | 49,250 |  |  | 232,886 |
Propane | — |  |  | — |  |  | — |  |  | 1,147 |
Natural Gas Basis Swaps | (37,474 | ) |  | 45,791 |  |  | 11,804 |  |  | (93,320 | )
Total Unrealized Gain on Commodity Derivative Instruments | 8,976 |  |  | 116,073 |  |  | 61,054 |  |  | 140,713 |
Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |
Commodity Swaps: |  |  |  |  |  |  |
Natural Gas | 63,508 |  |  | 54,773 |  |  | 65,874 |  |  | 192,770 |
Propane | — |  |  | — |  |  | — |  |  | (69 | )
Natural Gas Basis Swaps | (37,848 | ) |  | 29,015 |  |  | (5,127 | ) |  | (131,376 | )
Total Gain on Commodity Derivative Instruments | $ | 25,660 |  |  | $ | 83,788 |  |  | $ | 60,747 |  |  | $ | 61,325 |

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 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 One - Quoted prices for identical instruments in active markets.
Level Two - 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 Three - 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.
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The financial instruments measured at fair value on a recurring basis are summarized below:

| Fair Value Measurements at June 30, 2018 |  | Fair Value Measurements at December 31, 2017
Description | (Level 1) |  | (Level 2) |  | (Level 3) |  | (Level 1) |  | (Level 2) |  | (Level 3)
Gas Derivatives | $ | — |  |  | $ | 121,003 |  |  | $ | — |  |  | $ | — |  |  | $ | 59,949 |  |  | $ | — |
Put Option | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (3,500 | ) |  | $ | — |

The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:
Cash and cash equivalents: The carrying amount reported in the Consolidated Balance Sheets for cash and cash equivalents approximates its fair value due to the short-term maturity of these instruments.
Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

| June 30, 2018 |  | December 31, 2017
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Cash and Cash Equivalents | $ | 54,846 |  |  | $ | 54,846 |  |  | $ | 509,167 |  |  | $ | 509,167 |
Long-Term Debt | $ | 2,342,254 |  |  | $ | 2,329,810 |  |  | $ | 2,204,825 |  |  | $ | 2,281,282 |

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 approximately 34%, to be a variable interest entity. Upon completion of the Midstream Acquisition (see Note 6 - Acquisitions and Dispositions) through the Company's ownership and control of CNXM's general partner (CNX Midstream GP LLC), the Company has the power 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 consolidates CNXM commencing January 3, 2018.
The risks associated with the operations of CNXM are discussed in its Annual Reports on Form 10-K for the year ended December 31, 2017 filed with the SEC on February 7, 2018.
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The following table presents amounts included in the Company's Consolidated Balance Sheet that were for the use or obligation of CNXM as of June 30, 2018:

| June 30, 2018
Assets: |
Cash | $ | 707 |
Receivables - Related Party | 12,072 |
Receivables - Third Party | 7,546 |
Other Current Assets | 2,726 |
Property, Plant and Equipment, net | 792,513 |
Other Assets | 3,494 |
Total Assets | $ | 819,058 |
Liabilities: |
Accounts Payable | $ | 38,327 |
Accounts Payable - Related Party | 3,211 |
Revolving Credit Facility | 11,000 |
Long-Term Debt | 393,169 |
Total Liabilities | $ | 445,707 |

The following table summarizes CNXM's Consolidated Statements of Operations and Cash Flows for the three and six months ended June 30, 2018, inclusive of affiliate amounts:

| For the Three Months Ended |  | For the Six Months Ended
| June 30, 2018 |  | June 30, 2018
Revenue |  |  |
Gathering Revenue - Related Party | $ | 37,576 |  |  | $ | 75,306 |
Gathering Revenue - Third Party | 23,438 |  |  | 49,577 |
Total Revenue | 61,014 |  |  | 124,883 |
Expenses |  |  |
Operating Expense - Related Party | 5,079 |  |  | 9,514 |
Operating Expense - Third Party | 7,406 |  |  | 15,874 |
General and Administrative Expense - Related Party | 3,619 |  |  | 7,232 |
General and Administrative Expense - Third Party | 2,320 |  |  | 4,868 |
(Gain) Loss on Asset Sales | (254 | ) |  | 2,501 |
Depreciation Expense | 5,443 |  |  | 11,299 |
Interest Expense | 7,119 |  |  | 9,608 |
Total Expense | 30,732 |  |  | 60,896 |
Net Income | $ | 30,282 |  |  | $ | 63,987 |
Net Cash Provided by Operating Activities | $ | 53,674 |  |  | $ | 95,541 |
Net Cash Used in Investing Activities | $ | (24,969 | ) |  | $ | (35,125 | )
Net Cash Used in Financing Activities | $ | (29,964 | ) |  | $ | (62,903 | )

In March 2018, CNXM closed its previously announced 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 6.5% senior notes due 2026 (See Note 11 - Long-Term Debt).
Prior to the acquisition of Noble's interest on January 3, 2018, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment.
The following is a summary of the Company's Investment in Affiliates balances included within the Consolidated Balance Sheets associated with CNX Gathering and CNXM, respectively:
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| CNX Gathering |  | CNXM |  | Total
Balance at December 31, 2016 | $ | 151,075 |  |  | $ | 18,133 |  |  | $ | 169,208 |
Equity in Earnings | 9,823 |  |  | 38,523 |  |  | 48,346 |
Distributions | (17,254 | ) |  | (24,929 | ) |  | (42,183 | )
Asset Transfer | (2,527 | ) |  | 2,527 |  |  | — |
Balance at December 31, 2017 | $ | 141,117 |  |  | $ | 34,254 |  |  | $ | 175,371 |

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

| For the Three Months Ended |  | For the Six Months Ended
| June 30, 2017 |  | June 30, 2017
Other Operating Income: |  |  |
Equity in Earnings of Affiliates - CNX Gathering | $ | 284 |  |  | $ | 2,150 |
Equity in Earnings of Affiliates - CNXM | $ | 9,712 |  |  | $ | 19,784 |
Transportation, Gathering and Compression: |  |  |
Gathering Services - CNX Gathering | $ | 232 |  |  | $ | 485 |
Gathering Services - CNXM | $ | 31,695 |  |  | $ | 65,749 |

At June 30, 2018 and December 31, 2017, CNX had a net payable of $9,495 and $9,982 respectively due to both 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. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, impairment of other intangible assets, as well as various other operating activities assigned to the E&P Division but not allocated to each individual segment.
CNX's Midstream Division is the result of CNX's acquisition of NBL Midstream, LLC's interest in CNX Gathering LLC (See Note 6 - Acquisitions and Dispositions). As part of the acquisition, CNX now has a controlling financial interest and is the primary beneficiary of CNXM, through its approximately 34% ownership of the outstanding limited partner interests (See Note 15 - Variable Interest Entities for more information). The principal activity of the Midstream Division 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. Prior to the acquisition, the Company accounted for its 50% interest in CNX Gathering LLC as an equity method investment.
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.
Prior to the spin-off of the coal business in November 2017 (See Note 5 - Discontinued Operations), CNX had a Pennsylvania (PA) Mining Operations division and an Other division. The PA Mining Operations division principal activities consisted of the mining, preparation and marketing of thermal coal to power plants. The Other division included coal terminal operations, closed and idle mine activities, selling, general and administrative activities and various other non-operated activities.
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.
27

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 |  | (A)
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 |  | (B)
Total Revenue and Other Operating Income | $ | 187,433 |  |  | $ | 113,129 |  |  | $ | 49,037 |  |  | $ | 29,103 |  |  | $ | 378,702 |  |  | $ | 61,325 |  |  | $ | — |  |  | $ | (37,903 | ) |  | $ | 402,124 |  |
Earnings (Loss) From Continuing Operations 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 |  | (C)
Depreciation, Depletion and Amortization |  |  |  |  |  |  |  |  | $ | 111,125 |  |  | $ | 7,962 |  |  | $ | — |  |  | $ | — |  |  | $ | 119,087 |  |
Capital Expenditures |  |  |  |  |  |  |  |  | $ | 238,889 |  |  | $ | 25,285 |  |  | $ | — |  |  | $ | — |  |  | $ | 264,174 |  |

(A) | 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 sales.

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

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

Industry segment results for the three months ended June 30, 2017:

| Marcellus Shale |  | Utica Shale |  | Coalbed Methane |  | Other Gas |  | Total E&P |  | Unallocated |  | Consolidated |
Natural Gas, NGLs and Oil Revenue | $ | 154,424 |  |  | $ | 39,450 |  |  | $ | 51,973 |  |  | $ | 14,459 |  |  | $ | 260,306 |  |  | $ | — |  |  | $ | 260,306 |  | (D)
Purchased Gas Revenue | — |  |  | — |  |  | — |  |  | 10,316 |  |  | 10,316 |  |  | — |  |  | 10,316 |  |
(Loss) Gain on Commodity Derivative Instruments | (21,545 | ) |  | (2,063 | ) |  | (6,788 | ) |  | 114,184 |  |  | 83,788 |  |  | — |  |  | 83,788 |  |
Other Operating Income | — |  |  | — |  |  | — |  |  | 16,658 |  |  | 16,658 |  |  | — |  |  | 16,658 |  |
Total Revenue and Other Operating Income | $ | 132,879 |  |  | $ | 37,387 |  |  | $ | 45,185 |  |  | $ | 155,617 |  |  | $ | 371,068 |  |  | $ | — |  |  | $ | 371,068 |  |
Earnings (Loss) From Continuing Operations Before Income Tax | $ | 16,411 |  |  | $ | 9,063 |  |  | $ | (36 | ) |  | $ | 25,257 |  |  | $ | 50,695 |  |  | $ | 129,070 |  |  | $ | 179,765 |  | (E)
Segment Assets |  |  |  |  |  |  |  |  | $ | 6,194,820 |  |  | $ | 2,830,375 |  |  | $ | 9,025,195 |  | (F)
Depreciation, Depletion and Amortization |  |  |  |  |  |  |  |  | $ | 91,640 |  |  | $ | — |  |  | $ | 91,640 |  |
Capital Expenditures |  |  |  |  |  |  |  |  | $ | 145,839 |  |  | $ | — |  |  | $ | 145,839 |  |

(D) | Included in Total Natural Gas, NGLs and Oil Revenue are sales of $40,273 to Direct Energy Business Marketing LLC and $34,733 to NJR Energy Services Company, each of which comprises over 10% of sales.

(E) | Includes equity in earnings of unconsolidated affiliates of $10,055 for Total E&P.

(F) | Includes investments in unconsolidated equity affiliates of $188,649 for Total E&P.

28

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 |  | (A)
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 |  | (B)
Total Revenue and Other Operating Income | $ | 382,936 |  |  | $ | 238,977 |  |  | $ | 104,108 |  |  | $ | 122,237 |  |  | $ | 848,258 |  |  | $ | 125,503 |  |  | $ | — |  |  | $ | (75,908 | ) |  | $ | 897,853 |  |
Earnings (Loss) From Continuing Operations 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 |  | (C)
Depreciation, Depletion and Amortization |  |  |  |  |  |  |  |  | $ | 226,991 |  |  | $ | 16,763 |  |  | $ | — |  |  | $ | — |  |  | $ | 243,754 |  |
Capital Expenditures |  |  |  |  |  |  |  |  | $ | 455,397 |  |  | $ | 41,262 |  |  | $ | — |  |  | $ | — |  |  | $ | 496,659 |  |

(A) | 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 sales.

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

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

Industry segment results for the six months ended June 30, 2017:

| Marcellus Shale |  | Utica Shale |  | Coalbed Methane |  | Other Gas |  | Total E&P |  | Unallocated |  | Consolidated |
Natural Gas, NGLs and Oil Revenue | $ | 343,599 |  |  | $ | 93,118 |  |  | $ | 110,600 |  |  | $ | 30,752 |  |  | $ | 578,069 |  |  | $ | — |  |  | $ | 578,069 |  | (D)
Purchased Gas Revenue | — |  |  | — |  |  | — |  |  | 19,294 |  |  | 19,294 |  |  | — |  |  | 19,294 |  |
(Loss) Gain on Commodity Derivative Instruments | (54,210 | ) |  | (4,751 | ) |  | (15,987 | ) |  | 136,273 |  |  | 61,325 |  |  | — |  |  | 61,325 |  |
Other Operating Income | — |  |  | — |  |  | — |  |  | 32,308 |  |  | 32,308 |  |  | — |  |  | 32,308 |  |
Total Revenue and Other Operating Income | $ | 289,389 |  |  | $ | 88,367 |  |  | $ | 94,613 |  |  | $ | 218,627 |  |  | $ | 690,996 |  |  | $ | — |  |  | $ | 690,996 |  |
Earnings (Loss) From Continuing Operations Before Income Tax | $ | 46,380 |  |  | $ | 26,870 |  |  | $ | 3,572 |  |  | $ | (165,298 | ) |  | $ | (88,476 | ) |  | $ | 129,813 |  |  | $ | 41,337 |  | (E)
Segment Assets |  |  |  |  |  |  |  |  | $ | 6,194,820 |  |  | $ | 2,830,375 |  |  | $ | 9,025,195 |  | (F)
Depreciation, Depletion and Amortization |  |  |  |  |  |  |  |  | $ | 187,318 |  |  | $ | — |  |  | $ | 187,318 |  |
Capital Expenditures |  |  |  |  |  |  |  |  | $ | 249,962 |  |  | $ | — |  |  | $ | 249,962 |  |

(D) | Included in Total Natural Gas, NGLs and Oil Revenue are sales of $91,763 to NJR Energy Services Company and $86,639 to Direct Energy Business Marketing LLC, each of which comprises over 10% of sales.

(E) | Includes equity in earnings of unconsolidated affiliates of $22,385 for Total E&P.

(F) | Includes investments in unconsolidated equity affiliates of $188,649 for Total E&P.

29

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,
2018 |  | 2017 |  | 2018 |  | 2017
Total Segment Revenue from Contracts with External Customers | $ | 367,930 |  |  | $ | 270,622 |  |  | $ | 817,862 |  |  | $ | 597,363 |
Gain on Commodity Derivative Instruments | 25,660 |  |  | 83,788 |  |  | 60,747 |  |  | 61,325 |
Other Operating Income | 8,534 |  |  | 16,658 |  |  | 19,244 |  |  | 32,308 |
Total Consolidated Revenue and Other Operating Income | $ | 402,124 |  |  | $ | 371,068 |  |  | $ | 897,853 |  |  | $ | 690,996 |

Income From Continuing Operations Before Income Tax:

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
| 2018 |  | 2017 |  | 2018 |  | 2017
Segment Income (Loss) Before Income Taxes for reportable business segments: |  |  |  |  |  |  |
Total E&P | $ | 42,125 |  |  | $ | 50,695 |  |  | $ | 141,935 |  |  | $ | (88,476 | )
Midstream | 27,795 |  |  | — |  |  | 63,329 |  |  | — |
Total Segment Income (Loss) Before Income Taxes for reportable business segments | 69,920 |  |  | 50,695 |  |  | 205,264 |  |  | (88,476 | )
Unallocated Expenses: |  |  |  |  |  |  |
Other (Expense) Income | (575 | ) |  | (5,475 | ) |  | 5,917 |  |  | $ | (9,550 | )
Gain on Certain Asset Sales | 3,010 |  |  | 134,581 |  |  | 12,386 |  |  | 138,577 |
Gain on Previously Held Equity Interest | — |  |  | — |  |  | 623,663 |  |  | — |
(Loss) Gain on Debt Extinguishment | (23,413 | ) |  | (36 | ) |  | (39,048 | ) |  | 786 |
Impairment of Other Intangible Assets | (18,650 | ) |  | — |  |  | (18,650 | ) |  | — |
Income From Continuing Operations Before Income Tax | $ | 30,292 |  |  | $ | 179,765 |  |  | $ | 789,532 |  |  | $ | 41,337 |

Total Assets:

| June 30,
2018 |  | 2017
Segment assets for total reportable business segments |  |  |
E&P | $ | 6,055,545 |  |  | $ | 6,194,820 |
Midstream | 1,830,007 |  |  | — |
Intercompany Eliminations | (11,166 | ) |  | — |
Items excluded from segment assets: |  |  |
Cash and Cash Equivalents | 54,846 |  |  | 291,535 |
Recoverable Income Taxes | 27,780 |  |  | 112,073 |
Deferred Income Taxes | — |  |  | — |
Assets Held for Sale | 250,746 |  |  | — |
Discontinued Operations | — |  |  | 2,426,767 |
Total Consolidated Assets | $ | 8,207,758 |  |  | $ | 9,025,195 |

30

NOTE 17—RELATED PARTY TRANSACTIONS:
CONSOL Energy Inc.
In connection with the spin-off of its coal business, as discussed in Note 5 - Discontinued Operations, CNX and CONSOL Energy entered into several agreements that govern the relationship of the parties following the Distribution, including the following:
•Separation and Distribution Agreement;
•Transition Services Agreement;
•Tax Matters Agreement;
•Employee Matters Agreement;
•Intellectual Property Matters Agreement;
•CNX Resources Corporation to CONSOL Energy Inc. Trademark License Agreement;
•CONSOL Energy Inc. to CNX Resources Corporation Trademark License Agreement; and
•First Amendment to Amended and Restated Omnibus Agreement ("Omnibus Amendment").
As of June 30, 2018, CNX had a payable to CONSOL Energy of $75 recorded in Total Current Liabilities on the Consolidated Balance Sheets. As of December 31, 2017, CNX had a receivable from CONSOL Energy of $12,540 recorded in Total Current Assets on the Consolidated Balance Sheets. At June 30, 2018, CNX also had recorded obligations to CONSOL Energy of $11,351, of which $5,063 was included in Total Current Liabilities and $6,288 was included in Total Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. At December 31, 2017, CNX had recorded obligations to CONSOL Energy of $15,415, of which $4,500 was included in Total Current Liabilities and $10,915 was included in Total Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. These items relate to reimbursement of the one-time transaction costs as well as other reimbursements per the terms of the Separation and Distribution Agreement.
For the periods prior to the spin-off of the coal business, all significant intercompany transactions between CNX and CONSOL Energy have been included in the Consolidated Financial Statements and are considered to have been effectively settled for cash at the time the transaction was recorded. In the Consolidated Statement of Stockholders' Equity, the distribution of CONSOL Energy Inc. is the net of the variety of intercompany transactions including, but not limited to, collection of trade receivables, payment of trade payables and accrued liabilities, settlement of charges for allocated selling, general and administrative costs and payment of taxes by CNX on CONSOL Energy's behalf.
NOTE 18—STOCK REPURCHASE:
In September 2017, CNX's Board of Directors approved a one-year stock repurchase program of up to $200,000. On October 30, 2017, the Board approved an increase to the aggregate amount of the repurchase plan to $450,000. On July 30,2018, the Board approved the extension of the stock repurchase program through December 31, 2018. 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 share repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans. During the six months ended June 30, 2018, 11,086,082 shares were repurchased and retired at an average price of $15.20 per share for a total cost of $168,719.
31

NOTE 19—GOODWILL AND OTHER INTANGIBLE ASSETS:
Goodwill is not amortized, but is evaluated for impairment annually during the fourth quarter, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of its carrying value. The Company may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. To the extent that such indicators exist, a goodwill impairment test is completed. If the carrying value of the goodwill of a reporting unit exceeds its implied fair value, the difference is recognized as an impairment charge. The Company uses a combination of an income and market approach to estimate the fair value of a reporting unit.
As a result of the Midstream Acquisition, CNX recorded $796,359 of goodwill and $128,781 of other intangible assets in conjunction with the preliminary purchase accounting. In May 2018 the Company recognized an impairment on this intangible asset of $18,650 in connection with the AEA with HG Energy (See Note 6 - Acquisitions and Dispositions for more information).
All goodwill is attributed to the Midstream reportable segment. Changes in the carrying amount of goodwill consist of the following activity:

December 31, 2017 | $ | — |
Acquisitions | 796,359 |
June 30, 2018 | $ | 796,359 |

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

| June 30, 2018
Other Intangible Assets |
Customer Relationships | $ | 128,781 |
Less: Impairment of Other Intangible Assets | (18,650 | )
Less: Accumulated Amortization for Customer Relationships | (3,655 | )
Total Other Intangible Assets, net | $ | 106,476 |

Amortization expense for other intangible assets was $1,733 and $3,655 for the three and six months ended June 30, 2018 respectively. There was no amortization expense for the three and six months ended June 30, 2017.
The customer relationships intangible asset category will be amortized on a straight line basis over approximately 17 years. The estimated future annual amortization expense for the next five fiscal years for other intangible assets recorded at June 30, 2018 is as follows:

| 2019 |  | 2020 |  | 2021 |  | 2022 |  | 2023
Estimated Annual Amortization Expense | $ | 6,552 |  |  | $ | 6,552 |  |  | $ | 6,552 |  |  | $ | 6,552 |  |  | $ | 6,552 |

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NOTE 20—RECENT ACCOUNTING PRONOUNCEMENTS:
In February 2018, the FASB issued Update 2018-02 - Income Statement - Reporting Comprehensive Income (Topic 220), which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (the "Act"). Consequently, the amendments eliminate the stranded tax effects resulting from the Act and will improve the usefulness of information reported to financial statement users. However, because the amendments only relate to the reclassification of the income tax effects of the Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. This Update also requires certain disclosures about stranded tax effects. The amendments in this Update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted and the amendments should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Act is recognized. The Company is currently evaluating the impact this guidance may have on CNX's financial statements.
In January 2017, the FASB issued Update 2017-04 - Simplifying the Test of Goodwill Impairment. This Update simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead a company would record an impairment charge based on the excess of a reporting unit's carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This Update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard's provisions prospectively. The Company adopted Update 2017-04 on January 1, 2018 and determined that this standard will not have a material quantitative effect on the financial statements, unless an impairment charge is necessary.
In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position. The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. CNX is currently finalizing a project plan, reviewing all existing leases and agreements that are covered under the standard, assessing the impact to the Consolidated Financial Statements as well as planning for adoption and implementation of this standard, which includes assessing the impact on information systems and internal controls.
33

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

General
During the second quarter of 2018, CNX sold 122.6 Bcfe of natural gas, an increase of 33% from the 92.2 Bcfe sold in the year-earlier quarter, driven primarily from Utica Shale volumes. Total quarterly production costs decreased to $2.00 per Mcfe, compared to the year-earlier quarter of $2.20 per Mcfe, driven primarily by reductions in transportation, gathering, and compression costs, and depreciation, depletion and amortization (DD&A). Capital expenditures increased in the second quarter to 264 million, compared to $146 million spent in the year-earlier quarter.
On May 2, 2018, CNX closed on an Asset Exchange Agreement with HG Energy and received approximately $7 million in cash proceeds and certain undeveloped Marcellus and Utica acreage in its Southwest and Central Pennsylvania operating areas. 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 include an incremental forty-well commitment by CNX.
As previously announced, during the quarter, CNX entered into an agreement with Ascent Resources-Utica, LLC to sell substantially all of its Ohio Utica joint venture ("JV") assets for net cash proceeds of approximately $400 million, of which CNX received a deposit from the seller of approximately $40 million in the second quarter. CNX did not have any additional activity associated with the divested assets in its future development plans. The company continues to evaluate the use of cash proceeds across further reducing debt and share count, investing in drilling and completion activities, and acquiring bolt-on acreage, as it becomes available. CNX will retain all related production and EBITDAX generated prior to closing, which the company expects to be in the third quarter of 2018, subject to customary closing conditions and adjustments.
Marketing Update:
For the second quarter of 2018, CNX's average sales price for natural gas, natural gas liquids (NGLs), oil, and condensate was $2.87 per Mcfe. CNX's average price for natural gas was $2.55 per Mcf for the quarter and, including cash settlements from hedging, was $2.70 per Mcf. The average realized price for all liquids for the second quarter of 2018 was $30.28 per barrel.
CNX's weighted average differential from NYMEX in the second quarter of 2018 was negative $0.40 per MMBtu. CNX's average sales price for natural gas before hedging decreased 14% to $2.55 per Mcf compared with the average sales price of $2.96 per Mcf in the first quarter of 2018. This decrease results primarily from a lower Henry Hub price coupled with a wider differential. Including the impact of cash settlements from hedging, CNX’s average sales price for natural gas was $0.12 per Mcf, or 4%, lower than the first quarter of 2018 and $0.28 per Mcf, or 12%, higher than last year’s second quarter.
CNX Guidance:
CNX reaffirms 2018 production guidance of 490-515 Bcfe
Total hedged natural gas production in the 2018 third quarter is 93.1 Bcf. The annual gas hedge position is shown in the table below:

|  | 2018 |  | 2019
Volumes Hedged (Bcf), as of 7/11/18 |  | 370.9* |  | 333.7 |

*Includes actual settlements of 206.8 Bcf.
CNX's hedged gas volumes include a combination of NYMEX 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.
34

Results of Operations - Three Months Ended June 30, 2018 Compared with Three Months Ended June 30, 2017
Net Income Attributable to CNX Resources Shareholders
CNX reported 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, compared to net income of $170 million, or earnings per diluted share of $0.73, for the three months ended June 30, 2017.

| For the Three Months Ended June 30,
(Dollars in thousands) | 2018 |  | 2017 |  | Variance
Income from Continuing Operations | $ | 61,394 |  |  | $ | 121,807 |  |  | $ | (60,413 | )
Income from Discontinued Operations, net | — |  |  | 47,703 |  |  | (47,703 | )
Net Income | $ | 61,394 |  |  | $ | 169,510 |  |  | $ | (108,116 | )
Less: Net Income Attributable to Noncontrolling Interest | 19,380 |  |  | — |  |  | 19,380 |
Net Income Attributable to CNX Resources Shareholders | $ | 42,014 |  |  | $ | 169,510 |  |  | $ | (127,496 | )

CNX's E&P Division's principal activity 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 from continuing operations of $42 million for the three months ended June 30, 2018, compared to earnings before income tax from continuing operations of $51 million for the three months ended June 30, 2017. Included in the 2018 earnings before income tax was an unrealized gain on commodity derivative instruments of $9 million. Included in the 2017 earnings before income tax an unrealized gain on commodity derivative instruments of $116 million.
CNX's Midstream Division, which is the result of CNX's acquisition of NBL Midstream, LLC's interest in CNX Gathering LLC (See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) on January 3, 2018, had earnings before income tax of $28 million for the three months ended June 30, 2018. As a result of the Midstream Acquisition, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership. Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment and as such a period to period analysis is not meaningful.
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.
35

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) |  | 2018 |  | 2017 |  | Variance |  | Percent Change
LIQUIDS |  |  |  |  |  |  |  |
NGLs: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 8,365 |  |  | 8,140 |  |  | 225 |  |  | 2.8 | %
Sales Volume (Mbbls) |  | 1,394 |  |  | 1,357 |  |  | 37 |  |  | 2.7 | %
Gross Price ($/Bbl) |  | $ | 28.38 |  |  | $ | 15.96 |  |  | $ | 12.42 |  |  | 77.8 | %
Gross Revenue |  | $ | 39,557 |  |  | $ | 21,637 |  |  | $ | 17,920 |  |  | 82.8 | %
Oil: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 69 |  |  | 132 |  |  | (63 | ) |  | (47.7 | )%
Sales Volume (Mbbls) |  | 11 |  |  | 22 |  |  | (11 | ) |  | (50.0 | )%
Gross Price ($/Bbl) |  | $ | 58.32 |  |  | $ | 48.18 |  |  | $ | 10.14 |  |  | 21.0 | %
Gross Revenue |  | $ | 670 |  |  | $ | 1,061 |  |  | $ | (391 | ) |  | (36.9 | )%
Condensate: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 528 |  |  | 682 |  |  | (154 | ) |  | (22.6 | )%
Sales Volume (Mbbls) |  | 88 |  |  | 114 |  |  | (26 | ) |  | (22.8 | )%
Gross Price ($/Bbl) |  | $ | 56.82 |  |  | $ | 34.14 |  |  | $ | 22.68 |  |  | 66.4 | %
Gross Revenue |  | $ | 4,996 |  |  | $ | 3,885 |  |  | $ | 1,111 |  |  | 28.6 | %
GAS |  |  |  |  |  |  |  |
Sales Volume (MMcf) |  | 113,599 |  |  | 83,266 |  |  | 30,333 |  |  | 36.4 | %
Sales Price ($/Mcf) |  | $ | 2.55 |  |  | $ | 2.81 |  |  | $ | (0.26 | ) |  | (9.3 | )%
Gross Revenue |  | $ | 289,294 |  |  | $ | 233,723 |  |  | $ | 55,571 |  |  | 23.8 | %
Hedging Impact ($/Mcf) |  | $ | 0.15 |  |  | $ | (0.39 | ) |  | $ | 0.54 |  |  | (138.5 | )%
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement |  | $ | 16,684 |  |  | $ | (32,285 | ) |  | $ | 48,969 |  |  | (151.7 | )%

Natural gas, NGLs, and oil revenue was $335 million for the three months ended June 30, 2018, compared to $260 million for the three months ended June 30, 2017. The increase was primarily due to 33.0% increase in total sales volumes and a higher impact from commodity derivative instruments, offset in part by the 9.3% decrease in average gas sales price per Mcf without the impact of derivative instruments. The decrease in average sales price was the result of the overall decrease in general market prices.
Sales volumes, average sales price (including the effects of derivative instruments), and average costs for the E&P Division were as follows:

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Sales Volumes (Bcfe) | 122.6 |  |  | 92.2 |  |  | 30.4 |  |  | 33.0 | %
Average Sales Price (per Mcfe) | $ | 2.87 |  |  | $ | 2.47 |  |  | $ | 0.40 |  |  | 16.2 | %
Average Costs (per Mcfe) | 2.00 |  |  | 2.20 |  |  | (0.20 | ) |  | (9.1 | )%
Average Margin | $ | 0.87 |  |  | $ | 0.27 |  |  | $ | 0.60 |  |  | 222.2 | %

The increase in average sales price was the result of the $0.54 per Mcf increase in the realized gain (loss) on commodity derivative instruments related to the Company's hedging program as well as an overall increase in NGLs pricing offset, in part, by a $0.26 per Mcf decrease in general natural gas market prices in the Appalachian basin during the current period.
36

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

• | Transportation, gathering, and compression expense decreased on a per-unit basis primarily due to the 33.0% increase in sales volumes, the shift towards dry Utica Shale production which has lower gathering costs and no processing costs, and a decrease in pipeline facility maintenance expense.

• | Depreciation, depletion and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus and Utica rates as a result of an increase in the Company's associated reserves.

• | Lease operating expense decreased on a per-unit basis due to the overall increase in sales volumes, primarily Utica, in the 2018 period.

Selling, General and Administrative
Selling, general and administrative (SG&A) costs include costs such as overhead, including employee wages 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 noncash equity-based compensation expense.
SG&A costs were $35 million for the three months ended June 30, 2018, compared to $22 million for the three months ended June 30, 2017. SG&A costs increased primarily due to an increase in short-term incentive compensation expense and the Midstream Acquisition in January 2018. See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. Prior to the acquisition, CNX accounted for its interests in CNX Gathering as an equity-method investment.
Certain costs and expenses such as other expense, gain on asset sales 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 Expense

| For the Three Months Ended June 30,
(in millions) | 2018 |  | 2017 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Interest Income | $ | — |  |  | $ | 6 |  |  | $ | (6 | ) |  | (100.0 | )%
Right of Way Sales | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Royalty Income | 3 |  |  | 1 |  |  | 2 |  |  | 200.0 | %
Other | 2 |  |  | 2 |  |  | — |  |  | — | %
Total Other Income | $ | 6 |  |  | $ | 9 |  |  | $ | (3 | ) |  | (33.3 | )%
Other Expense |  |  |  |  |  |  |
Professional Services | $ | 1 |  |  | $ | 10 |  |  | $ | (9 | ) |  | (90.0 | )%
Bank Fees | 3 |  |  | 3 |  |  | — |  |  | — | %
Other Land Rental Expense | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Other Corporate Expense | 2 |  |  | 1 |  |  | 1 |  |  | 100.0 | %
Total Other Expense | $ | 7 |  |  | $ | 14 |  |  | $ | (7 | ) |  | (50.0 | )%
Total Other Expense | $ | 1 |  |  | $ | 5 |  |  | $ | (4 | ) |  | (80.0 | )%

Gain on Asset Sales
Gain on asset sales of $3 million were recognized in the three months ended June 30, 2018 compared to a gain of $135 million in the three months ended June 30, 2017. The $132 million decrease was due to the sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale in Pennsylvania and the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in Ohio in the three months ended June 30, 2017. The net gain on the sale of these assets was $131 million and is included in the Gain on Asset Sales in the Consolidated Statements of Income. The remaining decrease in the period-to-period comparison is due to various items that occurred throughout both periods, none of which were individually
37

material. See Note 6 - 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 $23 million was recognized in the three months ended June 30, 2018 due to the purchase of a portion of the 8.00% senior notes due in April 2023 at an average price equal to 106.0% of the principal amount. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Impairment of Other Intangible Assets
Intangible assets are tested for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized when the carrying amount of the asset exceeds the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. The impairment loss to be recorded would be the excess of the asset's carrying value over its fair value.
In connection with the AEA with HG Energy (See Note 6 - 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 prior period.
Income Taxes
The effective income tax rate for continuing operations was (102.7)% for the three months ended June 30, 2018 compared to 32.2% to for the three months ended June 30, 2017. 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. The effective rate for the three months ended June 30, 2017 differs from the U.S. federal statutory rate of 35% primarily due to state income taxes and equity compensation. The U.S. federal tax rate was lowered from 35% to 21% as a result of the Tax Cuts and Jobs Act (the "Act") enacted on December 22, 2017.
See Note 8 - 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) | 2018 |  | 2017 |  | Variance |  | Percent Change
Total Company Earnings Before Income Tax | $ | 30 |  |  | $ | 180 |  |  | $ | (150 | ) |  | (83.3 | )%
Income Tax (Benefit) Expense | $ | (31 | ) |  | $ | 58 |  |  | $ | (89 | ) |  | (153.7 | )%
Effective Income Tax Rate | (102.7 | )% |  | 32.2 | % |  | (134.9 | )% |  |

38

TOTAL E&P DIVISION ANALYSIS for the three months ended June 30, 2018 compared to the three months ended June 30, 2017:
The E&P division had earnings before income tax of $42 million for the three months ended June 30, 2018 compared to earnings before income tax of $51 million for the three months ended June 30, 2017. Variances by individual E&P segment are discussed below.

| For the Three Months Ended |  | Difference to Three Months Ended
| June 30, 2018 |  | June 30, 2017
(in millions) | Marcellus |  | Utica |  | CBM |  | Other Gas |  | Total E&P |  | Marcellus |  | Utica |  | CBM |  | Other Gas |  | Total E&P
Natural Gas, NGLs and Oil Revenue | $ | 178 |  |  | $ | 108 |  |  | $ | 47 |  |  | $ | 2 |  |  | $ | 335 |  |  | $ | 23 |  |  | $ | 69 |  |  | $ | (5 | ) |  | $ | (12 | ) |  | $ | 75 |
Gain (Loss) on Commodity Derivative Instruments | 9 |  |  | 5 |  |  | 2 |  |  | 10 |  |  | 26 |  |  | 31 |  |  | 7 |  |  | 9 |  |  | (105 | ) |  | (58 | )
Purchased Gas Revenue | — |  |  | — |  |  | — |  |  | 10 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other Operating Income | — |  |  | — |  |  | — |  |  | 8 |  |  | 8 |  |  | — |  |  | — |  |  | — |  |  | (9 | ) |  | (9 | )
Total Revenue and Other Operating Income | 187 |  |  | 113 |  |  | 49 |  |  | 30 |  |  | 379 |  |  | 54 |  |  | 76 |  |  | 4 |  |  | (126 | ) |  | 8 |
Lease Operating Expense | 11 |  |  | 9 |  |  | 5 |  |  | — |  |  | 25 |  |  | 4 |  |  | 4 |  |  | (1 | ) |  | (3 | ) |  | 4 |
Production, Ad Valorem, and Other Fees | 5 |  |  | 2 |  |  | 2 |  |  | (1 | ) |  | 8 |  |  | 2 |  |  | 3 |  |  | — |  |  | (2 | ) |  | 3 |
Transportation, Gathering and Compression | 73 |  |  | 16 |  |  | 11 |  |  | 1 |  |  | 101 |  |  | 17 |  |  | 6 |  |  | (6 | ) |  | (3 | ) |  | 14 |
Depreciation, Depletion and Amortization | 51 |  |  | 40 |  |  | 19 |  |  | 1 |  |  | 111 |  |  | — |  |  | 26 |  |  | (1 | ) |  | (6 | ) |  | 19 |
Exploration and Production Related Other Costs | — |  |  | — |  |  | — |  |  | 4 |  |  | 4 |  |  | — |  |  | — |  |  | — |  |  | (16 | ) |  | (16 | )
Purchased Gas Costs | — |  |  | — |  |  | — |  |  | 10 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other Operating Expense | — |  |  | — |  |  | — |  |  | 18 |  |  | 18 |  |  | — |  |  | — |  |  | — |  |  | (4 | ) |  | (4 | )
Selling, General and Administrative Costs | — |  |  | — |  |  | — |  |  | 29 |  |  | 29 |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | 7 |
Total Operating Costs and Expenses | 140 |  |  | 67 |  |  | 37 |  |  | 62 |  |  | 306 |  |  | 23 |  |  | 39 |  |  | (8 | ) |  | (27 | ) |  | 27 |
Interest Expense | — |  |  | — |  |  | — |  |  | 31 |  |  | 31 |  |  | — |  |  | — |  |  | — |  |  | (10 | ) |  | (10 | )
Total E&P Division Costs | 140 |  |  | 67 |  |  | 37 |  |  | 93 |  |  | 337 |  |  | 23 |  |  | 39 |  |  | (8 | ) |  | (37 | ) |  | 17 |
Earnings (Loss) Before Income Tax | $ | 47 |  |  | $ | 46 |  |  | $ | 12 |  |  | $ | (63 | ) |  | $ | 42 |  |  | $ | 31 |  |  | $ | 37 |  |  | $ | 12 |  |  | $ | (89 | ) |  | $ | (9 | )

39

MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $47 million for the three months ended June 30, 2018 compared to earnings before income tax of $16 million for the three months ended June 30, 2017.

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Marcellus Gas Sales Volumes (Bcf) | 58.0 |  |  | 51.1 |  |  | 6.9 |  |  | 13.5 | %
NGLs Sales Volumes (Bcfe)* | 6.3 |  |  | 5.4 |  |  | 0.9 |  |  | 16.7 | %
Condensate Sales Volumes (Bcfe)* | 0.4 |  |  | 0.4 |  |  | — |  |  | — | %
Total Marcellus Sales Volumes (Bcfe)* | 64.7 |  |  | 56.9 |  |  | 7.8 |  |  | 13.7 | %
Average Sales Price - Gas (per Mcf) | $ | 2.47 |  |  | $ | 2.71 |  |  | $ | (0.24 | ) |  | (8.9 | )%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | 0.16 |  |  | $ | (0.42 | ) |  | $ | 0.58 |  |  | 138.1 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 4.95 |  |  | $ | 2.56 |  |  | $ | 2.39 |  |  | 93.4 | %
Average Sales Price - Condensate (per Mcfe)* | $ | 9.32 |  |  | $ | 5.91 |  |  | $ | 3.41 |  |  | 57.7 | %
Total Average Marcellus Sales Price (per Mcfe) | $ | 2.90 |  |  | $ | 2.34 |  |  | $ | 0.56 |  |  | 23.9 | %
Average Marcellus Lease Operating Expenses (per Mcfe) | 0.16 |  |  | 0.12 |  |  | 0.04 |  |  | 33.3 | %
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe) | 0.07 |  |  | 0.04 |  |  | 0.03 |  |  | 75.0 | %
Average Marcellus Transportation, Gathering and Compression costs (per Mcfe) | 1.13 |  |  | 0.98 |  |  | 0.15 |  |  | 15.3 | %
Average Marcellus Depreciation, Depletion and Amortization costs (per Mcfe) | 0.81 |  |  | 0.91 |  |  | (0.10 | ) |  | (11.0 | )%
Total Average Marcellus Costs (per Mcfe) | $ | 2.17 |  |  | $ | 2.05 |  |  | $ | 0.12 |  |  | 5.9 | %
Average Margin for Marcellus (per Mcfe) | $ | 0.73 |  |  | $ | 0.29 |  |  | $ | 0.44 |  |  | 151.7 | %

* 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 $178 million for the three months ended June 30, 2018 compared to $155 million for the three months ended June 30, 2017. The $23 million increase was primarily due to a 13.7% increase in total Marcellus sales volumes, partially offset by a 8.9% decrease in average gas sales price. The increase in sales volumes was primarily due to additional wells being turned in line in the second half of 2017 and in the current period.
The increase in the total average Marcellus sales price was primarily due to a $0.58 per Mcf increase in the realized gain (loss) on commodity derivative instruments resulting from the Company's hedging program. A $2.39 per Mcfe increase in NGL prices also contributed to the increase. The notional amounts associated with these financial hedges represented approximately 47.4 Bcf of the Company's produced Marcellus gas sales volumes for the three months ended June 30, 2018 at an average gain of $0.20 per Mcf. For the three months ended June 30, 2017, these financial hedges represented approximately 52.4 Bcf at an average loss of $0.41 per Mcf.
Total operating costs and expenses for the Marcellus segment were $140 million for the three months ended June 30, 2018 compared to $117 million for the three months ended June 30, 2017. The increase in total dollars was due to the items discussed below. The increase s in unit costs for the Marcellus segment were due to the increase d total dollars, partially offset by the 13.7% increase in total Marcellus sales volumes.
•Marcellus lease operating expenses were $11 million for the three months ended June 30, 2018 compared to $7 million for the three months ended June 30, 2017. The increase in total dollars was primarily due to an increase in water disposal costs in the current period.
•Marcellus production, ad valorem, and other fees were $5 million for the three months ended June 30, 2018 compared to $3 million for the three months ended June 30, 2017. The increase in total dollars was primarily related to an increase in severance taxes from the increased West Virginia based sales volume in the current period.
•Marcellus transportation, gathering and compression costs were $73 million for the three months ended June 30, 2018 compared to $56 million for the three months ended June 30, 2017. The increase in total dollars was primarily related to increased
40

processing costs due to a change in production mix to higher cost wet gas and increased gathering costs related to the overall production increase.
•Depreciation, depletion and amortization costs attributable to the Marcellus segment remained consistent at $51 million for each of the three months ended June 30, 2018 and June 30, 2017. These amounts included depletion on a unit of production basis of $0.79 per Mcfe and $0.89 per Mcfe, respectively. 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 $46 million for the three months ended June 30, 2018 compared to earnings before income tax of $9 million for the three months ended June 30, 2017.

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Utica Gas Sales Volumes (Bcf) | 40.4 |  |  | 10.7 |  |  | 29.7 |  |  | 277.6 | %
NGLs Sales Volumes (Bcfe)* | 2.1 |  |  | 2.7 |  |  | (0.6 | ) |  | (22.2 | )%
Oil Sales Volumes (Bcfe)* | — |  |  | 0.1 |  |  | (0.1 | ) |  | (100.0 | )%
Condensate Sales Volumes (Bcfe)* | 0.1 |  |  | 0.3 |  |  | (0.2 | ) |  | (66.7 | )%
Total Utica Sales Volumes (Bcfe)* | 42.6 |  |  | 13.8 |  |  | 28.8 |  |  | 208.7 | %
Average Sales Price - Gas (per Mcf) | $ | 2.43 |  |  | $ | 2.75 |  |  | $ | (0.32 | ) |  | (11.6 | )%
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | 0.13 |  |  | $ | (0.19 | ) |  | $ | 0.32 |  |  | 168.4 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 4.05 |  |  | $ | 2.84 |  |  | $ | 1.21 |  |  | 42.6 | %
Average Sales Price - Oil (per Mcfe)* | $ | 9.37 |  |  | $ | 7.64 |  |  | $ | 1.73 |  |  | 22.6 | %
Average Sales Price - Condensate (per Mcfe)* | $ | 9.92 |  |  | $ | 5.45 |  |  | $ | 4.47 |  |  | 82.0 | %
Total Average Utica Sales Price (per Mcfe) | $ | 2.66 |  |  | $ | 2.70 |  |  | $ | (0.04 | ) |  | (1.5 | )%
Average Utica Lease Operating Expenses (per Mcfe) | 0.21 |  |  | 0.36 |  |  | (0.15 | ) |  | (41.7 | )%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe) | 0.03 |  |  | (0.04 | ) |  | 0.07 |  |  | 175.0 | %
Average Utica Transportation, Gathering and Compression Costs (per Mcfe) | 0.38 |  |  | 0.73 |  |  | (0.35 | ) |  | (47.9 | )%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.95 |  |  | 0.99 |  |  | (0.04 | ) |  | (4.0 | )%
Total Average Utica Costs (per Mcfe) | $ | 1.57 |  |  | $ | 2.04 |  |  | $ | (0.47 | ) |  | (23.0 | )%
Average Margin for Utica (per Mcfe) | $ | 1.09 |  |  | $ | 0.66 |  |  | $ | 0.43 |  |  | 65.2 | %

*NGLs, Oil 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 $108 million for the three months ended June 30, 2018 compared to $39 million for the three months ended June 30, 2017. The $69 million increase was primarily due to the 208.7% increase in total Utica sales volumes. The increase in total Utica sales volumes was primarily due to additional wells being turned in line in the second half of 2017 and in the current period.
The decrease in the total average Utica sales price was primarily due to lower priced gas making up a larger percentage of the production mix. Average gas sales price decrease d $0.32 per Mcf, but was offset by a $0.32 per Mcf increase in the realized gain (loss) on commodity derivative instruments in the current period. The notional amounts associated with these financial hedges represented approximately 29.6 Bcf of the Company's produced Utica gas sales volumes for the three months ended June 30, 2018 at an average gain of $0.15 per Mcf. For the three months ended June 30, 2017, these financial hedges represented approximately 4.7 Bcf at an average loss of $0.44 per Mcf.
Total operating costs and expenses for the Utica segment were $67 million for the three months ended June 30, 2018 compared to $28 million for the three months ended June 30, 2017. The increase in total dollars and decrease in unit costs for the Utica segment were due to the following items:
41

•Utica lease operating expense was $9 million for the three months ended June 30, 2018 compared to $5 million for the three months ended June 30, 2017. The increase in total dollars was primarily due to an increase in water disposal costs in the current period associated with the increase in sales volumes. The decrease in unit costs was due to the 208.7% increase in total Utica sales volumes, partially offset by the increase in total dollars described above.
•Utica production, ad valorem, and other fees were $2 million for the three months ended June 30, 2018 compared to a credit of $1 million for the three months ended June 30, 2017. The credit in the previous period was the result of an adjustment related to the Company's proportionate share of ad valorem taxes in our joint venture partner's operated area. The increase in unit costs is due the increase in total dollars.
•Utica transportation, gathering and compression costs were $16 million for the three months ended June 30, 2018 compared to $10 million for the three months ended June 30, 2017. The $6 million increase in total dollars was primarily related to the overall increase in production in the current period. The decrease in unit costs was due to the increase in predominantly dry Utica sales volumes that do not require processing, offset in part, by the increase in total dollars.
•Depreciation, depletion and amortization costs attributable to the Utica segment were $40 million for the three months ended June 30, 2018 compared to $14 million for the three months ended June 30, 2017. These amounts included depletion on a unit of production basis of $0.93 per Mcfe and $1.00 per Mcfe, respectively. 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 $12 million for the three months ended June 30, 2018 compared to no earnings or loss before income tax for the three months ended June 30, 2017.

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 14.8 |  |  | 16.5 |  |  | (1.7 | ) |  | (10.3 | )%
Average Sales Price - Gas (per Mcf) | $ | 3.17 |  |  | $ | 3.15 |  |  | $ | 0.02 |  |  | 0.6 | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | 0.15 |  |  | $ | (0.41 | ) |  | $ | 0.56 |  |  | 136.6 | %
Total Average CBM Sales Price (per Mcf) | $ | 3.31 |  |  | $ | 2.74 |  |  | $ | 0.57 |  |  | 20.8 | %
Average CBM Lease Operating Expenses (per Mcf) | 0.36 |  |  | 0.37 |  |  | (0.01 | ) |  | (2.7 | )%
Average CBM Production, Ad Valorem, and Other Fees (per Mcf) | 0.11 |  |  | 0.11 |  |  | — |  |  | — | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 0.77 |  |  | 1.01 |  |  | (0.24 | ) |  | (23.8 | )%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.23 |  |  | 1.25 |  |  | (0.02 | ) |  | (1.6 | )%
Total Average CBM Costs (per Mcf) | $ | 2.47 |  |  | $ | 2.74 |  |  | $ | (0.27 | ) |  | (9.9 | )%
Average Margin for CBM (per Mcf) | $ | 0.84 |  |  | $ | — |  |  | $ | 0.84 |  |  | 100.0 | %

The CBM segment had natural gas revenue of $47 million for the three months ended June 30, 2018 compared to $52 million for the three months ended June 30, 2017. The $5 million decrease was primarily due to the 10.3% decrease in total CBM sales volumes. The decrease in CBM sales volumes was primarily due to normal well declines, less drilling activity and the sale of certain CBM assets that were sold along with the majority of CNX's shallow oil and gas assets (See Note 6 - Acquisitions and Dispositions of 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 increase d $0.57 per Mcf, due primarily to a $0.56 per Mcf increase in the realized gain (loss) on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 11.4 Bcf of the Company's produced CBM sales volumes for the three months ended June 30, 2018 at an average gain of $0.21 per Mcf. For the three months ended June 30, 2017, these financial hedges represented approximately 16.1 Bcf at an average loss of $0.42 per Mcf.
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Total operating costs and expenses for the CBM segment were $37 million for the three months ended June 30, 2018 compared to $45 million for the three months ended June 30, 2017. 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 $5 million for the three months ended June 30, 2018 compared to $6 million for the three months ended June 30, 2017. The $1 million decrease was primarily due to reductions to contractor services. Unit costs were also positively impacted by the decrease in total dollars, partially offset by the decrease in CBM sales volumes.
•CBM production, ad valorem, and other fees remained consistent at $2 million for the three months ended June 30, 2018 and June 30, 2017. Unit costs also remained consistent.
•CBM transportation, gathering and compression costs were $11 million for the three months ended June 30, 2018 compared to $17 million for the three months ended June 30, 2017. The $6 million decrease was primarily related to a decrease in utilized firm transportation expense as well as a decrease in repairs and maintenance expense. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in CBM sales volumes.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $19 million for the three months ended June 30, 2018 compared to $20 million for the three months ended June 30, 2017. These amounts included depletion on a unit of production basis of $0.70 per Mcfe and $0.79 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER GAS SEGMENT
The Other Gas segment had a loss before income tax of $63 million for the three months ended June 30, 2018 compared to earnings before income tax of $26 million for the three months ended June 30, 2017.

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Other Gas Sales Volumes (Bcf) | 0.4 |  |  | 4.9 |  |  | (4.5 | ) |  | (91.8 | )%
Oil Sales Volumes (Bcfe)* | 0.1 |  |  | 0.1 |  |  | — |  |  | — | %
Total Other Sales Volumes (Bcfe)* | 0.5 |  |  | 5.0 |  |  | (4.5 | ) |  | (90.0 | )%
Average Sales Price - Gas (per Mcf) | $ | 2.66 |  |  | $ | 2.83 |  |  | $ | (0.17 | ) |  | (6.0 | )%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | 0.08 |  |  | $ | (0.38 | ) |  | $ | 0.46 |  |  | 121.1 | %
Average Sales Price - Oil (per Mcfe)* | $ | 9.79 |  |  | $ | 8.55 |  |  | $ | 1.24 |  |  | 14.5 | %
Total Average Other Sales Price (per Mcfe) | $ | 3.65 |  |  | $ | 2.51 |  |  | $ | 1.14 |  |  | 45.4 | %
Average Other Lease Operating Expenses (per Mcfe) | 1.01 |  |  | 0.60 |  |  | 0.41 |  |  | 68.3 | %
Average Other Production, Ad Valorem, and Other Fees (per Mcfe) | (0.71 | ) |  | 0.14 |  |  | (0.85 | ) |  | (607.1 | )%
Average Other Transportation, Gathering and Compression Costs (per Mcfe) | 0.41 |  |  | 0.83 |  |  | (0.42 | ) |  | (50.6 | )%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.72 |  |  | 0.99 |  |  | (0.27 | ) |  | (27.3 | )%
Total Average Other Costs (per Mcfe) | $ | 1.43 |  |  | $ | 2.56 |  |  | $ | (1.13 | ) |  | (44.1 | )%
Average Margin for Other (per Mcfe) | $ | 2.22 |  |  | $ | (0.05 | ) |  | $ | 2.27 |  |  | 4,540.0 | %

*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, impairment of other intangible assets and other operational activity not assigned to a specific segment.
Other Gas sales volumes are primarily related to shallow oil and gas production. CNX entered into an agreement to sell substantially all of these assets on March 30, 2018 (See Note 6 - Acquisitions and Dispositions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). Natural gas, NGLs and oil revenue related to the Other Gas segment were $2 million for the three months ended June 30, 2018 compared to $14 million for the three months ended June 30, 2017. The decrease in natural gas, NGLs and oil revenue primarily related to the 90.0% decrease in total
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Other Gas sales volumes relating to the asset sale and a $0.17 per Mcf decrease in the average gas sales price. Total exploration and production costs related to these other sales were $1 million for the three months ended June 30, 2018 compared to $15 million for the three months ended June 30, 2017.
The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $9 million as well as cash settlements received of $1 million for the three months ended June 30, 2018. For the three months ended June 30, 2017, the Company recognized an unrealized gain on commodity derivative instruments of $116 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. Purchased gas revenues and costs both remained consistent at $10 million for each of the three months ended June 30, 2018 and 2017.

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Purchased Gas Sales Volumes (in Bcfe) | 3.5 |  |  | 3.3 |  |  | 0.2 |  |  | 6.1 | %
Average Sales Price (per Mcfe) | $ | 2.82 |  |  | $ | 3.14 |  |  | $ | (0.32 | ) |  | (10.2 | )%
Average Cost (per Mcfe) | $ | 2.77 |  |  | $ | 3.11 |  |  | $ | (0.34 | ) |  | (10.9 | )%

Other Operating Income
Other operating income was $8 million for the three months ended June 30, 2018 compared to $17 million for the three months ended June 30, 2017. The $9 million decrease was due to the following items:

| For the Three Months Ended June 30,
(in millions) | 2018 |  | 2017 |  | Variance |  | Percent Change
Equity in Earnings of Affiliates | $ | 2 |  |  | $ | 10 |  |  | $ | (8 | ) |  | (80.0 | )%
Gathering Income | 2 |  |  | 3 |  |  | (1 | ) |  | (33.3 | )%
Water Income | 4 |  |  | 1 |  |  | 3 |  |  | 300.0 | %
Other | — |  |  | 3 |  |  | (3 | ) |  | (100.0 | )%
Total Other Operating Income | $ | 8 |  |  | $ | 17 |  |  | $ | (9 | ) |  | (52.9 | )%

• | Equity in Earnings of Affiliates decreased $8 million primarily due to the acquisition and consolidation of CNXM in the current year. See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

• | Water income increased $3 million due to increased sales of freshwater to third parties for hydraulic fracturing.

Exploration and Production Related Other Costs
Exploration and production related other costs were $4 million for the three months ended June 30, 2018 compared to $20 million for the three months ended June 30, 2017. The $16 million decrease was due to the following items:

| For the Three Months Ended June 30,
(in millions) | 2018 |  | 2017 |  | Variance |  | Percent Change
Lease Expiration Costs | $ | 1 |  |  | $ | 19 |  |  | $ | (18 | ) |  | (94.7 | )%
Land Rentals | 1 |  |  | 1 |  |  | — |  |  | — | %
Other | 2 |  |  | — |  |  | 2 |  |  | 100.0 | %
Total Exploration and Production Other Costs | $ | 4 |  |  | $ | 20 |  |  | $ | (16 | ) |  | (80.0 | )%

• | Lease Expiration Costs relate to leases where the primary term expired. The $18 million decrease in the three months ended June 30, 2018 was primarily due to leases in both Monroe and Noble County, Ohio that were no longer in the Company's future drilling plans therefore were not renewed in the 2017 period.

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Other Operating Expense
Other operating expenses were $18 million for the three months ended June 30, 2018 compared to $22 million for the three months ended June 30, 2017. The $4 million decrease is due to the following items:

| For the Three Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Idle Rig Expense | $ | 1 |  |  | $ | 4 |  |  | $ | (3 | ) |  | (75.0 | )%
Unutilized Firm Transportation and Processing Fees | 10 |  |  | 12 |  |  | (2 | ) |  | (16.7 | )%
Insurance Expense | 1 |  |  | 1 |  |  | — |  |  | — | %
Other | 6 |  |  | 5 |  |  | 1 |  |  | 20.0 | %
Total Other Operating Expense | $ | 18 |  |  | $ | 22 |  |  | $ | (4 | ) |  | (18.2 | )%

• | 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 decrease in the period-to-period comparison was primarily due to the increase in the utilization of capacity. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Gathering Income in other operating income above.

• | Idle Rig Expense relates to the temporary idling of some of the Company's natural gas rigs. The total idle rig expense incurred by the Company decreased $3 million for the current quarter compared to the prior year quarter due to contacts that expired in the current period.

Selling, General and Administrative
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 $29 million for the three months ended June 30, 2018 compared to $22 million for the three months ended June 30, 2017. 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 $31 million was recognized in the three months ended June 30, 2018 compared to $41 million in the three months ended June 30, 2017. The $10 million decrease was primarily due to the reduction of higher cost long-term debt as a result of the $391 million purchase of the outstanding 5.875% senior notes due in April 2022 and the $300 million purchase of the outstanding 8% senior notes due in April 2023. In the three months ended June 30, 2017, CNX purchased $19 million of its outstanding 5.875% senior notes due in April 2022.
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TOTAL MIDSTREAM DIVISION ANALYSIS for the three months ended June 30, 2018:
CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets, of CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM.
On January 3, 2018, CNX completed the acquisition of Noble Energy's interest in CNX Gathering LLC (See Note 6 - Acquisitions and Dispositions). 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 consolidates commencing on January 3, 2018. Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment and as such a period-to-period analysis is not meaningful.

| For the Three Months Ended
(in millions) | June 30, 2018
Midstream Revenue - Related Party | $ | 38 |
Midstream Revenue - Third Party | 23 |
Total Revenue | $ | 61 |
Transportation, Gathering and Compression | $ | 12 |
Depreciation, Depletion and Amortization | 8 |
Selling, General, and Administrative Costs | 6 |
Total Operating Costs and Expenses | 26 |
Interest Expense | 7 |
Total Midstream Division Costs | 33 |
Earnings Before Income Tax | $ | 28 |

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 on delivery point and may change dynamically depending on commodity prices at time of shipment.
The table below summaries volumes gathered by gas type for the three months ended June 30, 2018.

| TOTAL
Dry Gas (BBtu/d) (**) | 698 |
Wet Gas (BBtu/d) (**) | 653 |
Condensate (MMcfe/d) | 9 |
Total Gathered Volumes | 1,360 |

(**) 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. Although there were no such instances in the period presented above, this remains a possibility in future periods.
Transportation, Gathering and Compression
Transportation, Gathering and Compression costs were $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 electrical compression, repairs and maintenance, supplies, treating and contract services.
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Selling, General and Administrative Expense
Selling, general and administrative expense is comprised of direct charges for the management and operation of CNXM assets. 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 revolving credit facility. Interest expense was $7 million for the three months ended June 30, 2018.
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Results of Operations - Six Months Ended June 30, 2018 Compared with Six Months Ended June 30, 2017
Net Income Attributable to CNX Resources Shareholders
CNX reported 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, compared to net income of $131 million, or earnings per diluted share of $0.56, for the six months ended June 30, 2017.

| For the Six Months Ended June 30,
(Dollars in thousands) | 2018 |  | 2017 |  | Variance
Income from Continuing Operations | $ | 606,940 |  |  | $ | 30,801 |  |  | $ | 576,139 |
Income from Discontinued Operations, net | — |  |  | 99,743 |  |  | (99,743 | )
Net Income | $ | 606,940 |  |  | $ | 130,544 |  |  | $ | 476,396 |
Less: Net Income Attributable to Noncontrolling Interest | 37,363 |  |  | — |  |  | 37,363 |
Net Income Attributable to CNX Resources Shareholders | $ | 569,577 |  |  | $ | 130,544 |  |  | $ | 439,033 |

CNX's E&P Division's principal activity 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 from continuing operations of $142 million for the six months ended June 30, 2018, compared to a loss before income tax from continuing operations of $88 million for the six months ended June 30, 2017. Included in the 2018 earnings before income tax was an unrealized gain on commodity derivative instruments of $61 million. Included in the 2017 net loss before income tax was $138 million of expense relating to the impairment in carrying value of Knox Energy LLC and Coalfield Pipeline Company (collectively, "Knox Energy") and an unrealized gain on commodity derivative instruments of $140 million. See Note 9 - Property, Plant and Equipment in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
CNX's Midstream Division, which is the result of the Midstream Acquistion (See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information) on January 3, 2018, had earnings before income tax of $63 million for the period from January 3, 2018 through June 30, 2018. As a result of this transaction, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership. Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment and as such a period to period analysis is not meaningful. The resulting gain on remeasurement to fair value of the previously held equity interest in the CNX Gathering and CNXM of $624 million has been included in the Gain on Previously Held Equity Interest line of the Consolidated Statements of Income and is part of CNX's unallocated expenses.
CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets, of CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM.
The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s natural gas production and sales portfolio.
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|  | For the Six Months Ended June 30,
in thousands (unless noted) |  | 2018 |  | 2017 |  | Variance |  | Percent Change
LIQUIDS |  |  |  |  |  |  |  |
NGLs: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 19,474 |  |  | 16,219 |  |  | 3,255 |  |  | 20.1 | %
Sales Volume (Mbbls) |  | 3,246 |  |  | 2,703 |  |  | 543 |  |  | 20.1 | %
Gross Price ($/Bbl) |  | $ | 27.84 |  |  | $ | 22.56 |  |  | $ | 5.28 |  |  | 23.4 | %
Gross Revenue |  | $ | 90,441 |  |  | $ | 60,920 |  |  | $ | 29,521 |  |  | 48.5 | %
Oil: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 163 |  |  | 217 |  |  | (54 | ) |  | (24.9 | )%
Sales Volume (Mbbls) |  | 27 |  |  | 36 |  |  | (9 | ) |  | (25.0 | )%
Gross Price ($/Bbl) |  | $ | 57.24 |  |  | $ | 46.68 |  |  | $ | 10.56 |  |  | 22.6 | %
Gross Revenue |  | $ | 1,558 |  |  | $ | 1,690 |  |  | $ | (132 | ) |  | (7.8 | )%
Condensate: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 1,319 |  |  | 1,445 |  |  | (126 | ) |  | (8.7 | )%
Sales Volume (Mbbls) |  | 220 |  |  | 241 |  |  | (21 | ) |  | (8.7 | )%
Gross Price ($/Bbl) |  | $ | 52.32 |  |  | $ | 34.02 |  |  | $ | 18.30 |  |  | 53.8 | %
Gross Revenue |  | $ | 11,499 |  |  | $ | 8,189 |  |  | $ | 3,310 |  |  | 40.4 | %
GAS |  |  |  |  |  |  |  |
Sales Volume (MMcf) |  | 231,114 |  |  | 169,364 |  |  | 61,750 |  |  | 36.5 | %
Sales Price ($/Mcf) |  | $ | 2.75 |  |  | $ | 3.00 |  |  | $ | (0.25 | ) |  | (8.3 | )%
Gross Revenue |  | $ | 636,642 |  |  | $ | 507,270 |  |  | $ | 129,372 |  |  | 25.5 | %
Hedging Impact ($/Mcf) |  | $ | — |  |  | $ | (0.47 | ) |  | $ | 0.47 |  |  | (100.0 | )%
Loss on Commodity Derivative Instruments - Cash Settlement |  | $ | (307 | ) |  | $ | (79,388 | ) |  | $ | 79,081 |  |  | (99.6 | )%

Natural gas, NGLs, and oil revenue was $740 million for the six months ended June 30, 2018, compared to $578 million for the six months ended June 30, 2017. The increase was primarily due to 34.7% increase in total sales volumes and a higher impact from commodity derivative instruments, offset in part by the 8.3% decrease in average gas sales price per Mcf without the impact of derivative instruments. The decrease in average sales price was the result of the overall decrease in general market prices.
Sales volumes, average sales price (including the effects of derivative instruments), and average costs for the E&P Division were as follows:

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Sales Volumes (Bcfe) | 252.1 |  |  | 187.2 |  |  | 64.9 |  |  | 34.7 | %
Average Sales Price (per Mcfe) | $ | 2.94 |  |  | $ | 2.66 |  |  | $ | 0.28 |  |  | 10.5 | %
Average Costs (per Mcfe) | 2.05 |  |  | 2.26 |  |  | (0.21 | ) |  | (9.3 | )%
Average Margin | $ | 0.89 |  |  | $ | 0.40 |  |  | $ | 0.49 |  |  | 122.5 | %

The increase in average sales price was the result of the $0.47 per Mcf decrease in the realized loss on commodity derivative instruments related to the Company's hedging program as well as an overall increase in NGLs pricing offset, in part, by a $0.25 per Mcf decrease in general natural gas market prices in the Appalachian basin during the current period.
Changes in the average costs per Mcfe were primarily related to the following items:

• | Transportation, gathering, and compression expense decreased on a per-unit basis primarily due to the 34.7% increase in sales volumes, as well as the shift towards dry Utica Shale production which has lower gathering costs and no processing costs, and a decrease in pipeline facility maintenance expense.

• | Depreciation, depletion and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus and Utica rates as a result of an increase in the Company's associated reserves.

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• | Lease operating expense increased on a per-unit basis primarily due to an increase in water disposal costs in the period-to-period comparison associated with the increase in sales volumes.

Selling, General and Administrative
SG&A costs include costs such as overhead, including employee wages 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 noncash equity-based compensation expense.
SG&A costs were $66 million for the six months ended June 30, 2018, compared to $44 million for the six months ended June 30, 2017. SG&A costs increased primarily due to an increase in short-term incentive compensation expense and the Midstream Acquisition in January 2018. See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. Prior to the acquisition, CNX accounted for its interests in CNX Gathering as an equity-method investment.
Certain costs and expenses such as other (income) expense, impairment of other intangible assets, gain on asset sales related to non-core assets, gain on previously held equity interest, loss (gain) on debt extinguishment 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) | 2018 |  | 2017 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Royalty Income | $ | 10 |  |  | $ | 6 |  |  | $ | 4 |  |  | 66.7 | %
Right of Way Sales | 4 |  |  | 1 |  |  | 3 |  |  | 300.0 | %
Interest Income | — |  |  | 7 |  |  | (7 | ) |  | (100.0 | )%
Other | 4 |  |  | 3 |  |  | 1 |  |  | 33.3 | %
Total Other Income | $ | 18 |  |  | $ | 17 |  |  | $ | 1 |  |  | 5.9 | %
Other Expense |  |  |  |  |  |  |
Professional Services | $ | 5 |  |  | $ | 16 |  |  | $ | (11 | ) |  | (68.8 | )%
Bank Fees | 5 |  |  | 6 |  |  | (1 | ) |  | (16.7 | )%
Other Land Rental Expense | 2 |  |  | 1 |  |  | 1 |  |  | 100.0 | %
Other Corporate Expense | — |  |  | 4 |  |  | (4 | ) |  | (100.0 | )%
Total Other Expense | $ | 12 |  |  | $ | 27 |  |  | $ | (15 | ) |  | (55.6 | )%
Total Other (Income) Expense | $ | (6 | ) |  | $ | 10 |  |  | $ | (16 | ) |  | (160.0 | )%

Gain on Asset Sales
Gain on asset sales of $15 million were recognized in the six months ended June 30, 2018 compared to a gain of $139 million in the six months ended June 30, 2017. During the six months ended June 30, 2018, CNX sold substantially all of its shallow oil and gas assets and certain CBM assets in Pennsylvania and West Virginia for $89 million in cash consideration. The net gain on the sale was $5 million and is included in the the Gain on Asset Sales line of the Consolidated Statements of Income. During the six months ended June 30, 2017, the Company closed on the sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale in Pennsylvania and the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in Ohio. The net gain on the sale was $131 million and is included in the Gain on Asset Sales in the Consolidated Statements of Income. The remaining decrease in the period-to-period comparison is due to various items that occurred throughout both periods, none of which were individually material. See Note 6 - Acquisitions and Dispositions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
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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 six months ended June 30, 2017. See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Loss (Gain) on Debt Extinguishment
Loss on debt extinguishment of $39 million was recognized in the six months ended June 30, 2018 compared to a gain on debt extinguishment of $1 million in the six months ended June 30, 2017. The $40 million decrease was due to the purchase of a portion of the 5.875% senior notes due April 2022 at an average price equal to 103.8% of the principal amount and the purchase of a portion of the 8.00% senior notes due in April 2023 at an average price equal to 106.0% of the principal amount in the six months ended June 30, 2018 compared to the purchase of a portion of the 5.875% senior notes due in April 2022 at an average price equal to 98.7% of the principal amount in the six months ended June 30, 2017. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Impairment of Other Intangible Assets
Intangible assets are tested for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized when the carrying amount of the asset exceeds the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. The impairment loss to be recorded would be the excess of the asset's carrying value over its fair value.
In connection with the AEA with HG Energy (See Note 6 - 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 prior period.
Income Taxes
The effective income tax rate for continuing operations was 23.1% for the six months ended June 30, 2018 compared to 25.5% to for the six months ended June 30, 2017. 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. The effective rate for the six months ended June 30, 2017 differs from the U.S. federal statutory rate of 35% primarily due to state income taxes and equity compensation. The U.S. federal tax rate was lowered from 35% to 21% as a result of the Tax Cuts and Jobs Act (the "Act") enacted on December 22, 2017.
See Note 8 - 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) | 2018 |  | 2017 |  | Variance |  | Percent Change
Total Company Earnings Before Income Tax | $ | 790 |  |  | $ | 41 |  |  | $ | 749 |  |  | 1,826.8 | %
Income Tax (Benefit) Expense | $ | 183 |  |  | $ | 11 |  |  | $ | 172 |  |  | 1,563.6 | %
Effective Income Tax Rate | 23.1 | % |  | 25.5 | % |  | (2.4 | )% |  |

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TOTAL E&P DIVISION ANALYSIS for the six months ended June 30, 2018 compared to the six months ended June 30, 2017:
The E&P division had earnings before income tax of $142 million for the six months ended June 30, 2018 compared to a loss before income tax of $88 million for the six months ended June 30, 2017. Variances by individual E&P segment are discussed below.

| For the Six Months Ended |  | Difference to Six Months Ended
| June 30, 2018 |  | June 30, 2017
(in millions) | Marcellus |  | Utica |  | CBM |  | Other Gas |  | Total E&P |  | Marcellus |  | Utica |  | CBM |  | Other Gas |  | Total E&P
Natural Gas, NGLs and Oil Revenue | $ | 383 |  |  | $ | 238 |  |  | $ | 104 |  |  | $ | 15 |  |  | $ | 740 |  |  | $ | 40 |  |  | $ | 145 |  |  | $ | (7 | ) |  | $ | (16 | ) |  | $ | 162 |
Gain (Loss) on Commodity Derivative Instruments | — |  |  | 1 |  |  | — |  |  | 60 |  |  | 61 |  |  | 54 |  |  | 6 |  |  | 16 |  |  | (76 | ) |  | — |
Purchased Gas Revenue | — |  |  | — |  |  | — |  |  | 28 |  |  | 28 |  |  | — |  |  | — |  |  | — |  |  | 9 |  |  | 9 |
Other Operating Income | — |  |  | — |  |  | — |  |  | 19 |  |  | 19 |  |  | — |  |  | — |  |  | — |  |  | (14 | ) |  | (14 | )
Total Revenue and Other Operating Income | 383 |  |  | 239 |  |  | 104 |  |  | 122 |  |  | 848 |  |  | 94 |  |  | 151 |  |  | 9 |  |  | (97 | ) |  | 157 |
Lease Operating Expense | 27 |  |  | 21 |  |  | 12 |  |  | 2 |  |  | 62 |  |  | 12 |  |  | 12 |  |  | — |  |  | (5 | ) |  | 19 |
Production, Ad Valorem, and Other Fees | 10 |  |  | 3 |  |  | 4 |  |  | — |  |  | 17 |  |  | 3 |  |  | 1 |  |  | — |  |  | (1 | ) |  | 3 |
Transportation, Gathering and Compression | 150 |  |  | 32 |  |  | 26 |  |  | 4 |  |  | 212 |  |  | 33 |  |  | 11 |  |  | (7 | ) |  | (6 | ) |  | 31 |
Depreciation, Depletion and Amortization | 104 |  |  | 80 |  |  | 36 |  |  | 7 |  |  | 227 |  |  | — |  |  | 51 |  |  | (6 | ) |  | (5 | ) |  | 40 |
Impairment of Exploration and Production Properties | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (138 | ) |  | (138 | )
Exploration and Production Related Other Costs | — |  |  | — |  |  | — |  |  | 6 |  |  | 6 |  |  | — |  |  | — |  |  | — |  |  | (24 | ) |  | (24 | )
Purchased Gas Costs | — |  |  | — |  |  | — |  |  | 27 |  |  | 27 |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | 8 |
Other Operating Expense | — |  |  | — |  |  | — |  |  | 34 |  |  | 34 |  |  | — |  |  | — |  |  | — |  |  | (7 | ) |  | (7 | )
Selling, General and Administrative Costs | — |  |  | — |  |  | — |  |  | 54 |  |  | 54 |  |  | — |  |  | — |  |  | — |  |  | 10 |  |  | 10 |
Total Operating Costs and Expenses | 291 |  |  | 136 |  |  | 78 |  |  | 134 |  |  | 639 |  |  | 48 |  |  | 75 |  |  | (13 | ) |  | (168 | ) |  | (58 | )
Interest Expense | — |  |  | — |  |  | — |  |  | 67 |  |  | 67 |  |  | — |  |  | — |  |  | — |  |  | (15 | ) |  | (15 | )
Total E&P Division Costs | 291 |  |  | 136 |  |  | 78 |  |  | 201 |  |  | 706 |  |  | 48 |  |  | 75 |  |  | (13 | ) |  | (183 | ) |  | (73 | )
Earnings (Loss) Before Income Tax | $ | 92 |  |  | $ | 103 |  |  | $ | 26 |  |  | $ | (79 | ) |  | $ | 142 |  |  | $ | 46 |  |  | $ | 76 |  |  | $ | 22 |  |  | $ | 86 |  |  | $ | 230 |

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MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $92 million for the six months ended June 30, 2018 compared to earnings before income tax of $46 million for the six months ended June 30, 2017.

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Marcellus Gas Sales Volumes (Bcf) | 114.1 |  |  | 104.0 |  |  | 10.1 |  |  | 9.7 | %
NGLs Sales Volumes (Bcfe)* | 15.5 |  |  | 10.2 |  |  | 5.3 |  |  | 52.0 | %
Condensate Sales Volumes (Bcfe)* | 1.0 |  |  | 0.7 |  |  | 0.3 |  |  | 42.9 | %
Total Marcellus Sales Volumes (Bcfe)* | 130.6 |  |  | 114.9 |  |  | 15.7 |  |  | 13.7 | %
Average Sales Price - Gas (per Mcf) | $ | 2.66 |  |  | $ | 2.92 |  |  | $ | (0.26 | ) |  | (8.9 | )%
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | — |  |  | $ | (0.52 | ) |  | $ | 0.52 |  |  | 100.0 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 4.60 |  |  | $ | 3.50 |  |  | $ | 1.10 |  |  | 31.4 | %
Average Sales Price - Condensate (per Mcfe)* | $ | 8.73 |  |  | $ | 5.67 |  |  | $ | 3.06 |  |  | 54.0 | %
Total Average Marcellus Sales Price (per Mcfe) | $ | 2.93 |  |  | $ | 2.52 |  |  | $ | 0.41 |  |  | 16.3 | %
Average Marcellus Lease Operating Expenses (per Mcfe) | 0.20 |  |  | 0.13 |  |  | 0.07 |  |  | 53.8 | %
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe) | 0.08 |  |  | 0.06 |  |  | 0.02 |  |  | 33.3 | %
Average Marcellus Transportation, Gathering and Compression costs (per Mcfe) | 1.15 |  |  | 1.02 |  |  | 0.13 |  |  | 12.7 | %
Average Marcellus Depreciation, Depletion and Amortization costs (per Mcfe) | 0.80 |  |  | 0.91 |  |  | (0.11 | ) |  | (12.1 | )%
Total Average Marcellus Costs (per Mcfe) | $ | 2.23 |  |  | $ | 2.12 |  |  | $ | 0.11 |  |  | 5.2 | %
Average Margin for Marcellus (per Mcfe) | $ | 0.70 |  |  | $ | 0.40 |  |  | $ | 0.30 |  |  | 75.0 | %

* 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 $383 million for the six months ended June 30, 2018 compared to $343 million for the six months ended June 30, 2017. The $40 million increase was primarily due to a 13.7% increase in total Marcellus sales volumes, partially offset by a 8.9% decrease in average gas sales price. The increase in sales volumes was primarily due to additional wells being turned in line in the second half of 2017 and the current period.
The increase in the total average Marcellus sales price was primarily due to a $0.52 per Mcf decrease in the loss on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 95.0 Bcf of the Company's produced Marcellus gas sales volumes for the six months ended June 30, 2018 at a nominal loss. For the six months ended June 30, 2017, these financial hedges represented approximately 102.8 Bcf at an average loss of $0.52 per Mcf.
Total operating costs and expenses for the Marcellus segment were $291 million for the six months ended June 30, 2018 compared to $243 million for the six months ended June 30, 2017. The increase in total dollars and increase in unit costs for the Marcellus segment were due to the following items:
•Marcellus lease operating expenses were $27 million for the six months ended June 30, 2018 compared to $15 million for the six months ended June 30, 2017. The increase in total dollars was primarily due to an increase in water disposal costs in the current period. The increase in unit costs was driven by the increase d total dollars, partially offset by the 13.7% increase in total Marcellus sales volumes.
•Marcellus production, ad valorem, and other fees were $10 million for the six months ended June 30, 2018 compared to $7 million for the six months ended June 30, 2017. The increase in total dollars was primarily related to an increase in severance taxes from the increased West Virginia based sales volume in the current period.
•Marcellus transportation, gathering and compression costs were $150 million for the six months ended June 30, 2018 compared to $117 million for the six months ended June 30, 2017. The increase in total dollars was primarily related to increased
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processing costs due to a change in production mix to higher cost wet gas. The increase in unit costs was due to the increase d total dollars described above, partially offset by the 13.7% increase in total Marcellus sales volumes.
•Depreciation, depletion and amortization costs attributable to the Marcellus segment remained consistent at $104 million for the six months ended June 30, 2018 and 2017. These amounts included depletion on a unit of production basis of $0.79 per Mcfe and $0.89 per Mcfe, respectively. 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 $103 million for the six months ended June 30, 2018 compared to earnings before income tax of $27 million for the six months ended June 30, 2017.

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Utica Gas Sales Volumes (Bcf) | 81.9 |  |  | 22.3 |  |  | 59.6 |  |  | 267.3 | %
NGLs Sales Volumes (Bcfe)* | 3.9 |  |  | 6.0 |  |  | (2.1 | ) |  | (35.0 | )%
Oil Sales Volumes (Bcfe)* | — |  |  | 0.1 |  |  | (0.1 | ) |  | (100.0 | )%
Condensate Sales Volumes (Bcfe)* | 0.3 |  |  | 0.7 |  |  | (0.4 | ) |  | (57.1 | )%
Total Utica Sales Volumes (Bcfe)* | 86.1 |  |  | 29.1 |  |  | 57.0 |  |  | 195.9 | %
Average Sales Price - Gas (per Mcf) | $ | 2.64 |  |  | $ | 2.83 |  |  | $ | (0.19 | ) |  | (6.7 | )%
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) | $ | 0.01 |  |  | $ | (0.21 | ) |  | $ | 0.22 |  |  | 104.8 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 4.83 |  |  | $ | 4.20 |  |  | $ | 0.63 |  |  | 15.0 | %
Average Sales Price - Oil (per Mcfe)* | $ | 8.60 |  |  | $ | 7.67 |  |  | $ | 0.93 |  |  | 12.1 | %
Average Sales Price - Condensate (per Mcfe)* | $ | 8.68 |  |  | $ | 5.66 |  |  | $ | 3.02 |  |  | 53.4 | %
Total Average Utica Sales Price (per Mcfe) | $ | 2.78 |  |  | $ | 3.03 |  |  | $ | (0.25 | ) |  | (8.3 | )%
Average Utica Lease Operating Expenses (per Mcfe) | 0.25 |  |  | 0.31 |  |  | (0.06 | ) |  | (19.4 | )%
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe) | 0.04 |  |  | 0.06 |  |  | (0.02 | ) |  | (33.3 | )%
Average Utica Transportation, Gathering and Compression Costs (per Mcfe) | 0.37 |  |  | 0.71 |  |  | (0.34 | ) |  | (47.9 | )%
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.93 |  |  | 1.03 |  |  | (0.10 | ) |  | (9.7 | )%
Total Average Utica Costs (per Mcfe) | $ | 1.59 |  |  | $ | 2.11 |  |  | $ | (0.52 | ) |  | (24.6 | )%
Average Margin for Utica (per Mcfe) | $ | 1.19 |  |  | $ | 0.92 |  |  | $ | 0.27 |  |  | 29.3 | %

*NGLs, Oil 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 $238 million for the six months ended June 30, 2018 compared to $93 million for the six months ended June 30, 2017. The $145 million increase was primarily due to the 195.9% increase in total Utica sales volumes. The increase in total Utica sales volumes was primarily due to additional wells being turned in line during the second half of 2017 and in the current period.
The decrease in the total average Utica sales price was primarily due to a $0.23 per Mcfe decrease in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging, as well as a $0.19 per Mcf decrease in average gas sales price, offset, in part, by a $0.22 per Mcf increase in the realized gain (loss) on commodity derivative instruments in the current period. The notional amounts associated with these financial hedges represented approximately 55.6 Bcf of the Company's produced Utica gas sales volumes for the six months ended June 30, 2018 at a nominal gain. For the six months ended June 30, 2017, these financial hedges represented approximately 8.4 Bcf at an average loss of $0.56 per Mcf.
Total operating costs and expenses for the Utica segment were $136 million for the six months ended June 30, 2018 compared to $61 million for the six months ended June 30, 2017. The increase in total dollars and decrease in unit costs for the Utica segment were due to the following items:
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•Utica lease operating expense was $21 million for the six months ended June 30, 2018 compared to $9 million for the six months ended June 30, 2017. The increase in total dollars was primarily due to an increase in water disposal costs in the current period associated with the additional sales volumes. The decrease in unit costs was due to the 195.9% increase in total Utica sales volumes.
•Utica production, ad valorem, and other fees were $3 million for the six months ended June 30, 2018 compared to $2 million for the six months ended June 30, 2017. The increase in total dollars was due to additional properties subject to property tax from the increased number of wells turned-in-line. The decrease in unit costs is due to the increase in production volumes.
•Utica transportation, gathering and compression costs were $32 million for the six months ended June 30, 2018 compared to $21 million for the six months ended June 30, 2017. The $11 million increase in total dollars was primarily related to the gathering costs associated with the increase d production in the current period. The decrease in unit costs was due to the increase in total Utica sales volumes, predominantly dry Utica which does not require processing.
•Depreciation, depletion and amortization costs attributable to the Utica segment were $80 million for the six months ended June 30, 2018 compared to $29 million for the six months ended June 30, 2017. These amounts included depletion on a unit of production basis of $0.93 per Mcfe and $1.01 per Mcfe, respectively. 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 $26 million for the six months ended June 30, 2018 compared to a earnings before income tax of $4 million for the six months ended June 30, 2017.

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 30.7 |  |  | 33.2 |  |  | (2.5 | ) |  | (7.5 | )%
Average Sales Price - Gas (per Mcf) | $ | 3.40 |  |  | $ | 3.34 |  |  | $ | 0.06 |  |  | 1.8 | %
Loss on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | (0.01 | ) |  | $ | (0.48 | ) |  | $ | 0.47 |  |  | 97.9 | %
Total Average CBM Sales Price (per Mcf) | $ | 3.39 |  |  | $ | 2.85 |  |  | $ | 0.54 |  |  | 18.9 | %
Average CBM Lease Operating Expenses (per Mcf) | 0.39 |  |  | 0.37 |  |  | 0.02 |  |  | 5.4 | %
Average CBM Production, Ad Valorem, and Other Fees (per Mcf) | 0.12 |  |  | 0.12 |  |  | — |  |  | — | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 0.84 |  |  | 1.00 |  |  | (0.16 | ) |  | (16.0 | )%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.21 |  |  | 1.25 |  |  | (0.04 | ) |  | (3.2 | )%
Total Average CBM Costs (per Mcf) | $ | 2.56 |  |  | $ | 2.74 |  |  | $ | (0.18 | ) |  | (6.6 | )%
Average Margin for CBM (per Mcf) | $ | 0.83 |  |  | $ | 0.11 |  |  | $ | 0.72 |  |  | 654.5 | %

The CBM segment had natural gas revenue of $104 million for the six months ended June 30, 2018 compared to $111 million for the six months ended June 30, 2017. The $7 million decrease was primarily due to the 7.5% decrease in total CBM sales volumes, partially offset by the 1.8% increase in average gas sales price and a $0.47 per Mcf decrease in the loss on commodity derivative instruments. The decrease in CBM sales volumes was primarily due to normal well declines, less drilling activity and the sale of certain CBM assets that were sold along with the majority of CNX's shallow oil and gas assets (See Note 6 - Acquisitions and Dispositions of 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 increase d $0.54 per Mcf, due primarily to a $0.47 per Mcf decrease in the loss on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 23.0 Bcf of the Company's produced CBM sales volumes for the six months ended June 30, 2018 at a nominal loss. For the six months ended June 30, 2017, these financial hedges represented approximately 30.6 Bcf at an average loss of $0.51 per Mcf.
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Total operating costs and expenses for the CBM segment were $78 million for the six months ended June 30, 2018 compared to $91 million for the six months ended June 30, 2017. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:
•CBM lease operating expense remained consistent at $12 million for each of the six months ended June 30, 2018 and June 30, 2017. Unit costs were negatively impacted by the decrease in CBM sales volumes.
•CBM production, ad valorem, and other fees remained consistent at $4 million for each of the six months ended June 30, 2018 and June 30, 2017.
•CBM transportation, gathering and compression costs were $26 million for the six months ended June 30, 2018 compared to $33 million for the six months ended June 30, 2017. The $7 million decrease was primarily related to a decrease in utilized firm transportation expense as well as a decrease in repairs and maintenance expense. Unit costs were also positively impacted by the decrease in total dollars offset, in part, by the decrease in CBM sales volumes.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $36 million for the six months ended June 30, 2018 compared to $42 million for the six months ended June 30, 2017. These amounts included depletion on a unit of production basis of $0.70 per Mcfe and $0.78 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER GAS SEGMENT
The Other Gas segment had a loss before income tax of $79 million for the six months ended June 30, 2018 compared to a loss before income tax of $165 million for the six months ended June 30, 2017.

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Other Gas Sales Volumes (Bcf) | 4.6 |  |  | 9.9 |  |  | (5.3 | ) |  | (53.5 | )%
Oil Sales Volumes (Bcfe)* | 0.1 |  |  | 0.1 |  |  | — |  |  | — | %
Total Other Sales Volumes (Bcfe)* | 4.7 |  |  | 10.0 |  |  | (5.3 | ) |  | (53.0 | )%
Average Sales Price - Gas (per Mcf) | $ | 2.89 |  |  | $ | 3.01 |  |  | $ | (0.12 | ) |  | (4.0 | )%
Loss on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) | $ | (0.12 | ) |  | $ | (0.45 | ) |  | $ | 0.33 |  |  | 73.3 | %
Average Sales Price - Oil (per Mcfe)* | $ | 9.86 |  |  | $ | 7.86 |  |  | $ | 2.00 |  |  | 25.4 | %
Total Average Other Sales Price (per Mcfe) | $ | 2.96 |  |  | $ | 2.63 |  |  | $ | 0.33 |  |  | 12.5 | %
Average Other Lease Operating Expenses (per Mcfe) | 0.52 |  |  | 0.62 |  |  | (0.10 | ) |  | (16.1 | )%
Average Other Production, Ad Valorem, and Other Fees (per Mcfe) | 0.03 |  |  | 0.14 |  |  | (0.11 | ) |  | (78.6 | )%
Average Other Transportation, Gathering and Compression Costs (per Mcfe) | 0.90 |  |  | 0.95 |  |  | (0.05 | ) |  | (5.3 | )%
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.64 |  |  | 1.03 |  |  | (0.39 | ) |  | (37.9 | )%
Total Average Other Costs (per Mcfe) | $ | 2.09 |  |  | $ | 2.74 |  |  | $ | (0.65 | ) |  | (23.7 | )%
Average Margin for Other (per Mcfe) | $ | 0.87 |  |  | $ | (0.11 | ) |  | $ | 0.98 |  |  | 890.9 | %

*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.
The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, unrealized gain on commodity derivative instruments, exploration and production related other costs, impairment of other intangible assets and other operational activity not assigned to a specific segment.
Other Gas sales volumes are primarily related to shallow oil and gas production. CNX entered into an agreement to sell substantially all of these assets on March 30, 2018 (See Note 6 - Acquisitions and Dispositions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). Natural gas, NGLs and oil revenue related to the Other Gas segment were $15 million for the six months ended June 30, 2018 compared to $31 million for the six months ended June 30, 2017. The decrease in natural gas, NGLs and oil revenue primarily related to the 53.0% decrease in total
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Other Gas sales volumes. Total exploration and production costs related to these other sales were $13 million for the six months ended June 30, 2018 compared to $30 million for the six months ended June 30, 2017.
The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $61 million as well as cash settlements paid of $1 million for the six months ended June 30, 2018. For the six months ended June 30, 2017, the Company recognized an unrealized gain on commodity derivative instruments of $140 million as well as cash settlements paid of $4 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. Purchased gas revenues were $28 million for the six months ended June 30, 2018 compared to $19 million for the six months ended June 30, 2017. Purchased gas costs were $27 million for the six months ended June 30, 2018 compared to $19 million for the six months ended June 30, 2017. The period-to-period increase in purchased gas revenue was due to the increase in purchased gas sales volumes.

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Purchased Gas Sales Volumes (in Bcfe) | 8.8 |  |  | 5.9 |  |  | 2.9 |  |  | 49.2 | %
Average Sales Price (per Mcfe) | $ | 3.19 |  |  | $ | 3.28 |  |  | $ | (0.09 | ) |  | (2.7 | )%
Average Cost (per Mcfe) | $ | 3.05 |  |  | $ | 3.25 |  |  | $ | (0.20 | ) |  | (6.2 | )%

Other Operating Income
Other operating income was $19 million for the six months ended June 30, 2018 compared to $33 million for the six months ended June 30, 2017. The $14 million decrease was due to the following items:

| For the Six Months Ended June 30,
(in millions) | 2018 |  | 2017 |  | Variance |  | Percent Change
Equity in Earnings of Affiliates | $ | 3 |  |  | $ | 22 |  |  | $ | (19 | ) |  | (86.4 | )%
Gathering Income | 5 |  |  | 6 |  |  | (1 | ) |  | (16.7 | )%
Water Income | 11 |  |  | 1 |  |  | 10 |  |  | 1,000.0 | %
Other | — |  |  | 4 |  |  | (4 | ) |  | (100.0 | )%
Total Other Operating Income | $ | 19 |  |  | $ | 33 |  |  | $ | (14 | ) |  | (42.4 | )%

• | Equity in Earnings of Affiliates decreased $19 million primarily due to the acquisition and consolidation of CNXM in the current year. See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

• | Water income increased $10 million due to increased sales of freshwater to third parties for hydraulic fracturing.

Impairment of Exploration and Production Related Properties
Impairment of exploration and production related properties of $138 million for the six months ended June 30, 2017 related to an impairment in the carrying value of Knox Energy in the first quarter of 2017. See Note 9 - Property, Plant and Equipment in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such impairments occurred in the current period.
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Exploration and Production Related Other Costs
Exploration and production related other costs were $6 million for the six months ended June 30, 2018 compared to $30 million for the six months ended June 30, 2017. The $24 million decrease was due to the following items:

| For the Six Months Ended June 30,
(in millions) | 2018 |  | 2017 |  | Variance |  | Percent Change
Lease Expiration Costs | $ | 2 |  |  | $ | 27 |  |  | $ | (25 | ) |  | (92.6 | )%
Land Rentals | 2 |  |  | 2 |  |  | — |  |  | — | %
Other | 2 |  |  | 1 |  |  | 1 |  |  | 100.0 | %
Total Exploration and Production Other Costs | $ | 6 |  |  | $ | 30 |  |  | $ | (24 | ) |  | (80.0 | )%

• | Lease Expiration Costs relate to leases where the primary term expired. The $25 million decrease in the six months ended June 30, 2018 was primarily due to leases in both Monroe and Noble County, Ohio that were no longer in the Company's future drilling plans so they were not renewed in the 2017 period.

Other Operating Expenses
Other operating expenses were $34 million for the six months ended June 30, 2018 compared to $41 million for the six months ended June 30, 2017. The $7 million decrease was due to the following items:

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Variance |  | Percent Change
Unutilized Firm Transportation and Processing Fees | $ | 18 |  |  | $ | 27 |  |  | $ | (9 | ) |  | (33.3 | )%
Idle Rig Expense | 4 |  |  | 5 |  |  | (1 | ) |  | (20.0 | )%
Insurance Expense | 2 |  |  | 1 |  |  | 1 |  |  | 100.0 | %
Severance Expense | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Other | 9 |  |  | 8 |  |  | 1 |  |  | 12.5 | %
Total Other Operating Expense | $ | 34 |  |  | $ | 41 |  |  | $ | (7 | ) |  | (17.1 | )%

• | Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The decrease in the period-to-period comparison was primarily due to the increase in the utilization of capacity. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Gathering Income in other 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 $54 million for the six months ended June 30, 2018 compared to $44 million for the six months ended June 30, 2017. Refer to the discussion of total company selling, general and administrative 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 $67 million was recognized in the six months ended June 30, 2018 compared to $82 million in the six months ended June 30, 2017. The $15 million decrease was primarily due to reduced high cost long-term debt, resulting from the $391 million purchase of the outstanding 5.875% senior notes due in April 2022 and the $300 million purchase of the outstanding 8% senior notes due in April 2023 in the six months ended June 30, 2018. In the six months ended June 30, 2017, CNX purchased $119 million of its outstanding 5.875% senior notes due in April 2022.
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TOTAL MIDSTREAM DIVISION ANALYSIS for the period January 3, 2018 through June 30, 2018:
CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets, of CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third parties in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM.
On January 3, 2018, CNX completed the Midstream Acquisition (See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q). 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 consolidates commencing on January 3, 2018. Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment and as such a period to period analysis is not meaningful.

(in millions) | For the period January 3, 2018 through June 30, 2018
Midstream Revenue - Related Party | $ | 76 |
Midstream Revenue - Third Party | 50 |
Total Revenue | $ | 126 |
Transportation, Gathering and Compression | $ | 26 |
Depreciation, Depletion and Amortization | 17 |
Selling, General, and Administrative Costs | 12 |
Total Operating Costs and Expenses | 55 |
Gain on Asset Sales | (2 | )
Interest Expense | 10 |
Total Midstream Division Costs | 63 |
Earnings Before Income Tax | $ | 63 |

Midstream Revenue
Midstream revenue consists of revenue related to volumes gathered on behalf of CNX and other third-party natural gas producers. CNXM charges a higher fee for natural gas that is shipped on its wet system compared to gas shipped through its dry system. CNXM revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon delivery point and may change dynamically depending on commodity prices at time of shipment.
The table below summaries volumes gathered by gas type for the period January 3, 2018 through June 30, 2018.

| TOTAL
Dry Gas (BBtu/d) (**) | 703 |
Wet Gas (BBtu/d) (**) | 682 |
Condensate (MMcfe/d) | 17 |
Total Gathered Volumes | 1,402 |

(**) 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. Although there were no such instances in the period presented above, this remains a possibility in future periods.
Transportation, Gathering and Compression
Transportation, Gathering and Compression costs were $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 electrical compression, repairs and maintenance, supplies, treating and contract services.
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Selling, General and Administrative Expense
SG&A expense is comprised of direct charges for the management and operation of CNXM assets. Refer to the discussion of total Company selling, general and administrative 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 on Asset Sales
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 revolving credit facility. Interest expense was $10 million for the period January 3, 2018 through June 30, 2018.
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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. On March 8, 2018, CNX amended and restated its senior secured revolving credit facility, which expires on March 8, 2023. The amended and restated credit facility increased lenders' commitments from $1.5 billion to $2.1 billion with an accordion feature that allows the Company to increase the commitments to $3 billion. The initial borrowing base increased from $2 billion to $2.5 billion, and the letters of credit aggregate sub-limit remained unchanged at $650 million. The credit facility matures on March 8, 2023, provided that if the aggregate principal amount of our existing 5.875% Senior Notes due 2022, 8.00% Senior Notes due 2023 and certain other publicly traded debt securities outstanding 91 days prior to the earliest maturity of such debt (such date, the "Springing Maturity Date") is greater than $500 million, then the credit facility will mature on the Springing Maturity Date.
The 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 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 facility contains a number of affirmative and negative covenants that include, among others, covenants 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 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 short-term borrowings under the revolver, measured quarterly. The calculation of all of the ratios exclude CNXM. CNX was in compliance of all financial covenants as of June 30, 2018.
At June 30, 2018, the facility had $422 million of borrowings outstanding and $251 million of letters of credit outstanding, leaving $1,427 million of unused capacity. 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.
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.
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 and NGL swap and option transactions, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $121 million at June 30, 2018 and a net asset of $60 million at December 31, 2017. 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.
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Cash Flows (in millions)

| For the Six Months Ended June 30,
| 2018 |  | 2017 |  | Change
Cash Provided by Operating Activities | $ | 451 |  |  | $ | 300 |  |  | $ | 151 |
Cash (Used) Provided by in Investing Activities | $ | (639 | ) |  | $ | 97 |  |  | $ | (736 | )
Cash Used in Financing Activities | $ | (266 | ) |  | $ | (152 | ) |  | $ | (114 | )

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

• | Net income increased $476 million in the period-to-period comparison.

• | Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $624 million gain on previously held equity interest, a $179 million change in deferred income taxes, a $138 million decrease in impairment of exploration and production properties, a $128 million change in discontinued operations (See Note 5 - Discontinued Operations in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for more information), a $80 million net change in commodity derivative instruments, a $40 million increase in the loss (gain) on debt extinguishment, and a $124 million change in gain on the sale of assets.

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

• | Capital expenditures increased $247 million in the period-to-period comparison primarily due to increased expenditures in both the Marcellus and Utica Shale plays resulting from increased drilling and completions activity.

• | In January 2018, CNX acquired Noble Energy's interest in CNX Gathering for a net payment of $299 million. See Note 6 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

• | Proceeds from the sale of assets decreased $175 million primarily due to the sale of approximately 32,900 net undeveloped acres in Ohio, Pennsylvania, and West Virginia during the six months ended June 2017. This was partially offset by the proceeds received from the 2018 sale of our shallow oil and gas and CBM assets in Pennsylvania and West Virginia.

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

• | In the six months ended June 30, 2018, CNX repurchased $405 million of the 2022 bonds and $318 million of the 2023 bonds. CNXM also received proceeds of $394 million from long-term borrowings. In the six months ended June 30, 2017, CNX repurchased $117 million of the 2022 bonds. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

• | In the six months ended June 30, 2018, CNX repurchased $167 million of its common stock on the open market. No repurchases were made in the six months ended June 30, 2017.

• | In the six months ended June 30, 2018, there were $422 million of borrowings on the CNX credit facility.

• | In the six months ended June 30, 2018, there were $139 million of net payments on the CNXM credit facility.

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

• | In the six months ended June 30, 2018, there were $20 million in debt issuance and financing fees. These fees were negligible in the six months ended June 30, 2017.

• | Financing activities of discontinued operations changed $22 million. See Note 5 - Discontinued Operations in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for more information.

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The following is a summary of the Company's significant contractual obligations at June 30, 2018 (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 | $ | 57,788 |  |  | $ | 122,130 |  |  | $ | 41,202 |  |  | $ | — |  |  | $ | 221,120 |
Gas Firm Transportation and Processing | 149,360 |  |  | 296,961 |  |  | 265,277 |  |  | 620,806 |  |  | 1,332,404 |
Long-Term Debt | — |  |  | — |  |  | 1,948,003 |  |  | 394,251 |  |  | 2,342,254 |
Interest on Long-Term Debt | 136,036 |  |  | 272,072 |  |  | 192,467 |  |  | 78,000 |  |  | 678,575 |
Capital (Finance) Lease Obligations | 6,915 |  |  | 13,882 |  |  | 2,964 |  |  | — |  |  | 23,761 |
Interest on Capital (Finance) Lease Obligations | 1,491 |  |  | 1,517 |  |  | 51 |  |  | — |  |  | 3,059 |
Operating Lease Obligations | 9,607 |  |  | 13,325 |  |  | 10,756 |  |  | 38,477 |  |  | 72,165 |
Long-Term Liabilities—Employee Related (a) | 1,870 |  |  | 3,940 |  |  | 4,318 |  |  | 25,636 |  |  | 35,764 |
Other Long-Term Liabilities (b) | 185,887 |  |  | 29,604 |  |  | — |  |  | 7,606 |  |  | 223,097 |
Total Contractual Obligations (c) | $ | 548,954 |  |  | $ | 753,431 |  |  | $ | 2,465,038 |  |  | $ | 1,164,776 |  |  | $ | 4,932,199 |

_________________________

(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, 2018, CNX had total long-term debt and capital lease obligations of $2,365 million outstanding, including the current portion of long-term debt of $7 million. This long-term debt consisted of:

• | An aggregate principal amount of $1,314 million of 5.875% Senior Notes due in April 2022 plus $2 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.

• | An aggregate principal amount of $400 million of 6.50% Senior Notes due in March 2026 issued by CNXM, less $6 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 $200 million of 8.00% Senior Notes due in April 2023 less $2 million of unamortized bond discount. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX’s subsidiaries.

• | An aggregate principal amount of $11 million in outstanding borrowings under the CNXM revolver. CNX is not a guarantor of CNXM's revolving credit facility.

• | An aggregate principal amount of $24 million of capital leases with a weighted average interest rate of 7.11% per annum.

At June 30, 2018, CNX had $422 million borrowings outstanding and approximately $251 million of letters of credit outstanding under the $2.1 billion senior secured revolving credit facility.
Total Equity and Dividends
CNX had total equity of $5,039 million at June 30, 2018 compared to $3,900 million at December 31, 2017. See the Consolidated Statement 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 leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to a cumulative credit calculation set forth in the facility. The total leverage ratio was 2.36 to 1.00 and the cumulative credit was approximately $348 million at June 30, 2018. The credit facility does not permit dividend payments in the event of default. The indentures to the 2022 and 2023 notes limit dividends to $0.50 per share annually unless several conditions are met.
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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, 2018.
On July 27, 2018 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 $0.3361 per unit with respect to the second quarter of 2018. The distribution will be made on August 14, 2018 to unitholders of record as of the close of business on August 7, 2018. The distribution, which equates to an annual rate of $1.3444 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 2017.
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 on the Consolidated Balance Sheet at June 30, 2018 . 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.
Critical Accounting Policies
The Company’s significant accounting policies are described in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q (See Note 20 - Recent Accounting Pronouncements in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.
As a result of our acquisition of the 50% interest in CNX Gathering in the first quarter of 2018, we acquired approximately $923 million of goodwill and other intangible assets. As such, the following critical accounting policy could be materially impacted by judgments assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Goodwill and Other Intangible Asset Impairment
Goodwill and other intangible assets are evaluated for impairment at least annually, or whenever events or changes in circumstances indicate a potential impairment in the carrying value. A significant amount of judgment is involved in making this qualitative assessment, and events and circumstances the Company will consider include, but are not limited to, the overall financial performance including adverse changes to forecasts of operating results, movement in the Company's stock price and changes in assumptions related to weighted-average cost of capital, terminal growth rates and industry multiples.
The Company evaluates goodwill and other intangible assets for impairment by first assessing qualitative factors to determine whether the existence of certain events or circumstances leads to a determination that it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Estimated fair values could change if, for example, there are changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market capitalization. If the carrying value of the goodwill of a reporting unit exceeds its implied fair value, the difference is recognized as an impairment charge. The Company uses a combination of an income and market approach to estimate the fair value.
Business Combinations
Accounting for the acquisition of a business requires the identifiable assets and liabilities acquired to be recorded at fair value. The most significant assumptions in a business combination include those used to estimate the fair value of the oil and gas properties acquired. The fair value of proved natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant assumptions including commodity prices; projections of estimated quantities of reserves;
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projections of future rates of production; timing and amount of future development and operating costs; projected reserve recovery factors; and a weighted average cost of capital.
The Company utilizes the guideline transaction method to estimate the fair value of unproved properties acquired in a business combination which requires the Company to use judgment in considering the value per undeveloped acre in recent comparable transactions to estimate the value of unproved properties.
The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach, which incorporates assumptions about the replacement costs for similar assets, the relative age of assets and any potential economic or functional obsolescence.
The fair values of the intangible assets are estimated using the multi-period excess earnings model which estimates revenues and cash flows derived from the intangible asset and then deducts portions of the cash flow that can be attributed to supporting assets otherwise recognized. The Company’s intangible assets are comprised of customer relationships and non-compete agreements.
The Company believes that the accounting estimates related to business combinations are “critical accounting estimates” because the Company must, in determining the fair value of assets acquired, make assumptions about future commodity prices; projections of estimated quantities of reserves; projections of future rates of production; projections regarding the timing and amount of future development and operating costs; and projections of reserve recovery factors, per-acre values of undeveloped property, replacement cost of and future cash flows from midstream assets, cash flow from customer relationships and non-compete agreements and the pre-and post-modification value of stock based awards. Different assumptions may result in materially different values for these assets which would impact the Company’s financial position and future results of operations.
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 CNXM and others;

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

• | the high-risk nature of drilling 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;

• | 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 introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;

• | the risks inherent in natural gas operations, including our reliance upon third-party contractors, being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions that could impact financial results;

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• | decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials to support our operations;

• | if natural gas prices remain depressed or drilling efforts are unsuccessful, we may be required to record writedowns of our proved natural gas properties;

• | a loss of our competitive position because of the competitive nature of the natural gas industry or overcapacity in this industry impairing 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;

• | our inability to collect payments from customers if their creditworthiness declines or if they fail to honor their contracts;

• | existing and future government laws, regulations and other legal requirements 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 and related facility integrity management program testing and any related pipeline repair or preventative or remedial measures;

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

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

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

• | risks associated with our debt;

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

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

• | 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;

• | changes in federal or state income tax laws;

• | 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;

• | terrorist attacks or cyber-attacks 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;

• | we may not achieve some or all of the expected benefits of the separation of CONSOL Energy;

• | CONSOL Energy may fail to perform under various transaction agreements that were executed as part of the separation;

• | 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;

• | with respect to the sale of the Ohio JV Utica assets, disruption of our business, risks that the conditions to closing may not be satisfied, and the impact of the transaction on our future operating and financial results; and

• | other factors discussed in the 2017 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file at the Securities and Exchange Commission.

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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. However, the use of derivative instruments without other risk assessment procedures could materially affect the Company's results of operations depending on market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.
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 2017 Form 10-K.
At June 30, 2018 and December 31, 2017, our open derivative instruments were in a net asset position with a fair value of $121 million and $60 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at June 30, 2018 and December 31, 2017. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $307 million and $323 million at June 30, 2018 and December 31, 2017, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by $322 million and $321 million at June 30, 2018 and December 31, 2017, respectively.
The Company’s interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2018 and December 31, 2017, CNX had $1,922 million and $2,214 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $11 million and $18 million, respectively. At June 30, 2018, CNX had $433 million of debt outstanding under variable-rate instruments, and had no debt outstanding under variable-rate instruments at December 31, 2017. CNX’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were $422 million of borrowings at June 30, 2018 and no borrowings at December 31, 2017, and CNXM's revolving credit facility, under which there were $11 million of borrowings at June 30, 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 by $4.3 million at June 30, 2018. There would be no impact on pre-tax future earnings at December 31, 2017.
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.
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Natural Gas Hedging Volumes
As of July 11, 2018, 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
2018 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | N/A |  | N/A |  | 95.4 |  |  | 95.6 |  |  | 191.0 |
Weighted Average Hedge Price per Mcf | N/A |  | N/A |  | $ | 2.81 |  |  | $ | 2.85 |  |  | $ | 2.83 |
2019 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 82.3 |  |  | 83.2 |  |  | 84.1 |  |  | 84.1 |  |  | 333.7 |
Weighted Average Hedge Price per Mcf | $ | 2.72 |  |  | $ | 2.71 |  |  | $ | 2.71 |  |  | $ | 2.72 |  |  | $ | 2.72 |
2020 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 59.8 |  |  | 58.4 |  |  | 59.0 |  |  | 59.0 |  |  | 234.9* |
Weighted Average Hedge Price per Mcf | $ | 2.79 |  |  | $ | 2.71 |  |  | $ | 2.71 |  |  | $ | 2.70 |  |  | $ | 2.72 |
2021 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 49.2 |  |  | 49.8 |  |  | 50.3 |  |  | 48.9 |  |  | 198.0* |
Weighted Average Hedge Price per Mcf | $ | 2.55 |  |  | $ | 2.55 |  |  | $ | 2.55 |  |  | $ | 2.53 |  |  | $ | 2.54 |
2022 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 41.3 |  |  | 41.8 |  |  | 42.3 |  |  | 42.3 |  |  | 167.7 |
Weighted Average Hedge Price per Mcf | $ | 2.50 |  |  | $ | 2.50 |  |  | $ | 2.50 |  |  | $ | 2.50 |  |  | $ | 2.50 |
2023 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 9.4 |  | 9.5 |  | 9.6 |  | 9.6 |  | 38.1
Weighted Average Hedge Price per Mcf | $ | 2.48 |  |  | $ | 2.48 |  |  | $ | 2.48 |  |  | $ | 2.48 |  |  | $ | 2.48 |

*Quarterly volumes do not add to annual volumes in as much 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, 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, 2018 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 through the third paragraphs 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.
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ITEM 1A. RISK FACTORS
Information regarding risk factors is discussed in Item 1A, "Risk Factors" of the Company's Annual Report on Form10-K for the year ended December 31, 2017 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may adversely affect our business, financial condition, cash flows, or results of operations. With the exception of the update below, there have been no material changes from the risk factors previously disclosed by the Company.
If natural gas prices remain depressed or drilling efforts are unsuccessful, we may be required to record writedowns of our proved natural gas properties. Additionally, changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in the Company's 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.
Lower natural gas prices or wells that produce less than expected quantities of natural gas may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management's plans change with respect to those assets. For example, in the second quarter of 2015, we had an impairment charge of approximately $829 million for certain of our natural gas assets, primarily shallow oil and gas assets. We may incur impairment charges in the future, which could have an adverse effect on our results of operations in the period taken.
As a result of our acquisition of the 50% interest in CNX Gathering in the first quarter of 2018, we acquired approximately $923 million of goodwill and other intangible assets. Future acquisitions may also lead to the acquisition of additional goodwill or other intangible assets. At least annually, or whenever events or changes in circumstances indicate a potential impairment in the carrying value as defined by GAAP, we will evaluate this goodwill and other intangible assets for impairment by first assessing qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Estimated fair values could change if, for example, there are changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market capitalization. The future impairment of these assets could require material non-cash charges to our results of operations, which could have a material adverse effect on our reported earnings and results of operations for the affected periods.
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, 2018:

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, 2018- April 30, 2018 | 1,047,682 |  | $ | 15.30 |  | 6,833,582 |  | $ | 247,038 |
May 1, 2018- May 31, 2018 | 2,757,800 |  | $ | 15.68 |  | 9,591,382 |  | $ | 203,786 |
June 1, 2018- June 30, 2018 | 1,494,700 |  | $ | 16.97 |  | 11,086,082 |  | $ | 178,421 |
Total | 5,300,182 |  | $ | 15.97 |  |  |

(1) Includes shares withheld from employees to satisfy minimum tax withholding obligations associated with the vesting of restricted stock during the period.
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(2) Shares repurchased as part of the company’s previously announced one-year $450 million share repurchase program authorized by the Board of Directors in September 2017, as amended on October 30, 2017.

ITEM 6. | EXHIBITS

10.1 |  | * | Amendment, dated as of July 1, 2018, to the CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, as amended and restated effective November 28, 2017, 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, 2018 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: August 2, 2018

CNX RESOURCES CORPORATION
| By: |  | /s/ N ICHOLAS J. D EIULIIS
|  |  | Nicholas J. DeIuliis
|  |  | Chief Executive Officer and President and Director (Duly Authorized Officer and Principal Executive Officer)
| By: |  | /S/ D ONALD W. R USH
|  |  | Donald W. Rush
|  |  | Chief Financial Officer and Executive Vice President (Duly Authorized Officer and Principal Financial Officer)
| By: |  | /S/ J ASON L. M UMFORD
|  |  | Jason L. Mumford
|  |  | Controller (Duly Authorized Officer and Principal Accounting Officer)

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