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2022-01-01 2022-12-31

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

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

For the quarterly period ended June 30, 2023
OR

☐ | 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 Horizon Vue Drive
Canonsburg, PA 15317-6506
(724) 485-4000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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

__________________________________________________
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller Reporting Company ☐
Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class |  | Shares outstanding as of July 14, 2023
Common stock, $0.01 par value |  | 161,464,938

TABLE OF CONTENTS

|  | Page
PART I FINANCIAL INFORMATION |
ITEM 1. | Unaudited Condensed Consolidated Financial Statements |
| Consolidated Statements of Income for the three and six months ended June 30, 2023 and 2022 | 5
| Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2023 and 2022 | 6
| Consolidated Balance Sheets at June 30, 2023 and December 31, 2022 | 7
| Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2023 and 2022 | 10
| Consolidated Statements of Cash Flows for the six months ended June 30, 2023 and 2022 | 11
| Notes to Unaudited Consolidated Financial Statements | 12
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 30
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk | 56
ITEM 4. | Controls and Procedures | 57
PART II OTHER INFORMATION |
ITEM 1. | Legal Proceedings | 58
ITEM 1A. | Risk Factors | 58
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 58
ITEM 5. | Other Information | 58
ITEM 6. | Exhibits | 60

GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are certain terms and abbreviations commonly used in the oil and gas industry and included within this Form 10-Q:
Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf - One billion cubic feet of natural gas.
Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Btu - One British Thermal Unit.
BBtu - One billion British Thermal Units.
Mbbls - One thousand barrels of oil or other liquid hydrocarbons.
Mcf - One thousand cubic feet of natural gas.
Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
MMBtu - One million British Thermal Units.
MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.
NGL - natural gas liquids - those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation or other methods in gas processing plants.
net - "net" natural gas or "net" acres are determined by adding the fractional ownership working interests the Company has in gross wells or acres.
TIL - turn-in-line; a well turned to sales.
NYMEX - New York Mercantile Exchange.
basis - when referring to commodity pricing, the difference between the price for a commodity at a primary trading hub and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location, transportation capacity availability and contract pricing.
blending - process of mixing dry and damp gas in order to meet downstream pipeline specifications.
condensate - a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
conventional play - a term used in the oil and natural gas industry to refer to an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps utilizing conventional recovery methods.
developed reserves - developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
development well - a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
exploratory well - a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
exploration costs - costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) costs of topographical, geographical and geophysical studies and the rights to access the properties in order to conduct those studies, (ii) costs of carrying and retaining undeveloped properties, such as delay rentals and the maintenance of land and lease records, (iii) dry hole contributions (iv) costs of drilling and equipping exploratory wells, and (v) costs of drilling exploratory-type stratigraphic test wells.
gob well - a well drilled or vent hole converted to a well which produces or is capable of producing coalbed methane or other natural gas from a distressed zone created above and below a mined-out coal seam by any prior full seam extraction of the coal.
gross acres - the total acres in which a working interest is owned.
gross wells - the total wells in which a working interest is owned.
lease operating expense - costs of operating wells and equipment on a producing lease, many of which are recurring. Includes items such as water disposals, repairs and maintenance, equipment rental and operating supplies, among others.
net acres - the number of acres an owner has out of a particular number of gross acres.
net wells - the percentage ownership interest in a well that an owner has based on the working interest.
play - a proven geological formation that contains commercial amounts of hydrocarbons.

production costs - costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities, which become part of the cost of oil and natural gas produced.
proved reserves - quantities of oil, natural gas, and natural gas liquids (NGLs) which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
proved developed reserves (PDPs) - proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
proved undeveloped reserves (PUDs) - proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
reservoir - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
royalty interest - an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowners' royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
throughput - the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period.
transportation, gathering and compression - cost incurred related to transporting natural gas to the ultimate point of sale. These costs also include costs related to physically preparing natural gas, natural gas liquids and condensate for ultimate sale which include costs related to processing, compressing, dehydrating and fractionating, among others.
service well - a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.
unconventional formations - a term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to achieve economic flow rates.
undeveloped reserves - undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
unproved properties - properties with no proved reserves.
working interest - an interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.
wet gas - natural gas that contains significant heavy hydrocarbons, such as propane, butane and other liquid hydrocarbons.

PART I : FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data) | Three Months Ended |  | Six Months Ended
(Unaudited) | June 30, |  | June 30,
Revenue and Other Operating Income (Loss): | 2023 |  | 2022 |  | 2023 |  | 2022
Natural Gas, NGLs and Oil Revenue | $ | 257,061 |  |  | $ | 1,003,406 |  |  | $ | 712,700 |  |  | $ | 1,748,030 |
Gain (Loss) on Commodity Derivative Instruments | 542,472 |  |  | (652,643) |  |  | 1,304,639 |  |  | (2,379,036) |
Purchased Gas Revenue | 9,355 |  |  | 46,552 |  |  | 46,167 |  |  | 92,393 |
Other Revenue and Operating Income | 30,812 |  |  | 23,103 |  |  | 52,170 |  |  | 45,933 |
Total Revenue and Other Operating Income (Loss) | 839,700 |  |  | 420,418 |  |  | 2,115,676 |  |  | (492,680) |
Costs and Expenses: |  |  |  |  |  |  |
Operating Expense |  |  |  |  |  |  |
Lease Operating Expense | 13,092 |  |  | 14,282 |  |  | 29,566 |  |  | 29,680 |
Production, Ad Valorem and Other Fees | 5,419 |  |  | 9,958 |  |  | 15,060 |  |  | 19,885 |
Transportation, Gathering and Compression | 87,872 |  |  | 88,357 |  |  | 185,968 |  |  | 176,644 |
Depreciation, Depletion and Amortization | 103,682 |  |  | 116,180 |  |  | 208,904 |  |  | 234,803 |
Exploration and Production Related Other Costs | 1,727 |  |  | 4,712 |  |  | 6,831 |  |  | 6,400 |
Purchased Gas Costs | 8,794 |  |  | 46,041 |  |  | 43,140 |  |  | 90,858 |
Selling, General, and Administrative Costs | 30,017 |  |  | 30,454 |  |  | 66,593 |  |  | 62,014 |
Other Operating Expense | 21,031 |  |  | 20,539 |  |  | 36,169 |  |  | 32,709 |
Total Operating Expense | 271,634 |  |  | 330,523 |  |  | 592,231 |  |  | 652,993 |
Other Expense |  |  |  |  |  |  |
Other Expense | 2,510 |  |  | 5,179 |  |  | 3,679 |  |  | 4,441 |
Gain on Asset Sales and Abandonments, net | (105,986) |  |  | (6,240) |  |  | (115,468) |  |  | (19,634) |
Loss on Debt Extinguishment | — |  |  | 12,981 |  |  | — |  |  | 12,981 |
Interest Expense | 34,820 |  |  | 31,051 |  |  | 70,556 |  |  | 58,121 |
Total Other (Income) Expense | (68,656) |  |  | 42,971 |  |  | (41,233) |  |  | 55,909 |
Total Costs and Expenses | 202,978 |  |  | 373,494 |  |  | 550,998 |  |  | 708,902 |
Income (Loss) Before Income Tax | 636,722 |  |  | 46,924 |  |  | 1,564,678 |  |  | (1,201,582) |
Income Tax Expense (Benefit) | 161,767 |  |  | 13,567 |  |  | 379,328 |  |  | (311,997) |
Net Income (Loss) | $ | 474,955 |  |  | $ | 33,357 |  |  | $ | 1,185,350 |  |  | $ | (889,585) |
Earnings (Loss) per Share |  |  |  |  |  |  |
Basic | $ | 2.89 |  |  | $ | 0.17 |  |  | $ | 7.13 |  |  | $ | (4.52) |
Diluted | $ | 2.47 |  |  | $ | 0.15 |  |  | $ | 6.09 |  |  | $ | (4.52) |
Dividends Declared | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

| Three Months Ended |  | Six Months Ended
(Dollars in thousands) | June 30, |  | June 30,
(Unaudited) | 2023 |  | 2022 |  | 2023 |  | 2022
Net Income (Loss) | $ | 474,955 |  |  | $ | 33,357 |  |  | $ | 1,185,350 |  |  | $ | (889,585) |
Other Comprehensive Income: |  |  |  |  |  |  |
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $(27), $(48),$(54), $(96)) | 72 |  |  | 135 |  |  | 144 |  |  | 270 |
Comprehensive Income (Loss) | $ | 475,027 |  |  | $ | 33,492 |  |  | $ | 1,185,494 |  |  | $ | (889,315) |

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| (Unaudited) |  |
(Dollars in thousands) | June 30, 2023 |  | December 31, 2022
ASSETS |  |  |
Current Assets: |  |  |
Cash and Cash Equivalents | $ | 22,765 |  |  | $ | 21,321 |
Accounts and Notes Receivable: |  |  |
Trade, net | 97,702 |  |  | 348,458 |
Other Receivables, net | 11,370 |  |  | 6,184 |
Supplies Inventories | 26,470 |  |  | 27,156 |
Derivative Instruments | 227,012 |  |  | 154,474 |
Prepaid Expenses | 14,504 |  |  | 16,211 |
Total Current Assets | 399,823 |  |  | 573,804 |
Property, Plant and Equipment: |  |  |
Property, Plant and Equipment | 12,247,858 |  |  | 11,907,698 |
Less—Accumulated Depreciation, Depletion and Amortization | 5,008,026 |  |  | 4,811,189 |
Total Property, Plant and Equipment—Net | 7,239,832 |  |  | 7,096,509 |
Other Non-Current Assets: |  |  |
Operating Lease Right-of-Use Assets | 164,503 |  |  | 174,849 |
Derivative Instruments | 305,887 |  |  | 244,931 |
Goodwill | 323,314 |  |  | 323,314 |
Other Intangible Assets | 73,714 |  |  | 76,990 |
Other | 24,782 |  |  | 25,376 |
Total Other Non-Current Assets | 892,200 |  |  | 845,460 |
TOTAL ASSETS | $ | 8,531,855 |  |  | $ | 8,515,773 |

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

| (Unaudited) |  |
(Dollars in thousands, except per share data) | June 30, 2023 |  | December 31, 2022
LIABILITIES AND EQUITY |  |  |
Current Liabilities: |  |  |
Accounts Payable | $ | 164,177 |  |  | $ | 191,343 |
Derivative Instruments | 240,874 |  |  | 782,653 |
Current Portion of Finance Lease Obligations | 1,379 |  |  | 881 |
Current Portion of Operating Lease Obligations | 53,166 |  |  | 47,436 |
Other Accrued Liabilities | 232,417 |  |  | 290,491 |
Total Current Liabilities | 692,013 |  |  | 1,312,804 |
Non-Current Liabilities: |  |  |
Long-Term Debt | 2,154,093 |  |  | 2,205,735 |
Finance Lease Obligations | 3,732 |  |  | 1,970 |
Operating Lease Obligations | 114,998 |  |  | 132,105 |
Derivative Instruments | 812,744 |  |  | 1,517,021 |
Deferred Income Taxes | 609,133 |  |  | 232,280 |
Asset Retirement Obligations | 87,987 |  |  | 89,079 |
Other | 73,968 |  |  | 74,318 |
Total Non-Current Liabilities | 3,856,655 |  |  | 4,252,508 |
TOTAL LIABILITIES | 4,548,668 |  |  | 5,565,312 |
Stockholders’ Equity: |  |  |
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 162,071,479 Issued and Outstanding at June 30, 2023; 170,841,164 Issued and Outstanding at December 31, 2022 | 1,625 |  |  | 1,712 |
Capital in Excess of Par Value | 2,440,895 |  |  | 2,506,269 |
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding | — |  |  | — |
Retained Earnings | 1,547,036 |  |  | 448,993 |
Accumulated Other Comprehensive Loss | (6,369) |  |  | (6,513) |
TOTAL STOCKHOLDERS' EQUITY | 3,983,187 |  |  | 2,950,461 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 8,531,855 |  |  | $ | 8,515,773 |

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands) (Unaudited) | Common Stock |  | Capital in Excess of Par Value |  | Retained Earnings (Accumulated Deficit) |  | Accumulated Other Comprehensive Loss |  |  |  |  |  | Total Equity
March 31, 2023 | $ | 1,663 |  |  | $ | 2,468,079 |  |  | $ | 1,103,995 |  |  | $ | (6,441) |  |  |  |  |  |  | $ | 3,567,296 |
Net Income | — |  |  | — |  |  | 474,955 |  |  | — |  |  |  |  |  |  | 474,955 |
Issuance of Common Stock | — |  |  | 129 |  |  | — |  |  | — |  |  |  |  |  |  | 129 |
Purchase and Retirement of Common Stock | (38) |  |  | (31,855) |  |  | (31,874) |  |  | — |  |  |  |  |  |  | (63,767) |
Shares Withheld for Taxes | — |  |  | — |  |  | (40) |  |  | — |  |  |  |  |  |  | (40) |
Amortization of Stock-Based Compensation Awards | — |  |  | 4,542 |  |  | — |  |  | — |  |  |  |  |  |  | 4,542 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 72 |  |  |  |  |  |  | 72 |
June 30, 2023 | $ | 1,625 |  |  | $ | 2,440,895 |  |  | $ | 1,547,036 |  |  | $ | (6,369) |  |  |  |  |  |  | $ | 3,983,187 |
(Dollars in thousands) (Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
March 31, 2022 | $ | 1,955 |  |  | $ | 2,691,950 |  |  | $ | (110,005) |  |  | $ | (14,388) |  |  |  |  |  |  | $ | 2,569,512 |
Net Income | — |  |  | — |  |  | 33,357 |  |  | — |  |  |  |  |  |  | 33,357 |
Issuance of Common Stock | 1 |  |  | 374 |  |  | — |  |  | — |  |  |  |  |  |  | 375 |
Purchase and Retirement of Common Stock | (38) |  |  | (30,606) |  |  | (39,350) |  |  | — |  |  |  |  |  |  | (69,994) |
Shares Withheld for Taxes | — |  |  | — |  |  | (83) |  |  | — |  |  |  |  |  |  | (83) |
Amortization of Stock-Based Compensation Awards | — |  |  | 3,722 |  |  | — |  |  | — |  |  |  |  |  |  | 3,722 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 135 |  |  |  |  |  |  | 135 |
June 30, 2022 | $ | 1,918 |  |  | $ | 2,665,440 |  |  | $ | (116,081) |  |  | $ | (14,253) |  |  |  |  |  |  | $ | 2,537,024 |

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

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands) | Common Stock |  | Capital in Excess of Par Value |  | Retained Earnings (Accumulated Deficit) |  | Accumulated Other Comprehensive Loss |  |  |  |  |  | Total Equity
December 31, 2022 | $ | 1,712 |  |  | $ | 2,506,269 |  |  | $ | 448,993 |  |  | $ | (6,513) |  |  |  |  |  |  | $ | 2,950,461 |
(Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income | — |  |  | — |  |  | 1,185,350 |  |  | — |  |  |  |  |  |  | 1,185,350 |
Issuance of Common Stock | 1 |  |  | 737 |  |  | — |  |  | — |  |  |  |  |  |  | 738 |
Purchase and Retirement of Common Stock | (97) |  |  | (79,282) |  |  | (77,923) |  |  | — |  |  |  |  |  |  | (157,302) |
Shares Withheld for Taxes | — |  |  | — |  |  | (9,384) |  |  | — |  |  |  |  |  |  | (9,384) |
Amortization of Stock-Based Compensation Awards | 9 |  |  | 13,171 |  |  | — |  |  | — |  |  |  |  |  |  | 13,180 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 144 |  |  |  |  |  |  | 144 |
June 30, 2023 | $ | 1,625 |  |  | $ | 2,440,895 |  |  | $ | 1,547,036 |  |  | $ | (6,369) |  |  |  |  |  |  | $ | 3,983,187 |
(Dollars in thousands) |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2021 | $ | 2,039 |  |  | $ | 2,834,863 |  |  | $ | 877,894 |  |  | $ | (14,523) |  |  |  |  |  |  | $ | 3,700,273 |
(Unaudited) |  |  |  |  |  |  |  |  |  |  |  |  |
Net Loss | — |  |  | — |  |  | (889,585) |  |  | — |  |  |  |  |  |  | (889,585) |
Issuance of Common Stock | 2 |  |  | 981 |  |  | — |  |  | — |  |  |  |  |  |  | 983 |
Purchase and Retirement of Common Stock | (129) |  |  | (103,167) |  |  | (117,672) |  |  | — |  |  |  |  |  |  | (220,968) |
Shares Withheld for Taxes | — |  |  | — |  |  | (5,665) |  |  | — |  |  |  |  |  |  | (5,665) |
Amortization of Stock-Based Compensation Awards | 6 |  |  | 11,047 |  |  | — |  |  | — |  |  |  |  |  |  | 11,053 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 270 |  |  |  |  |  |  | 270 |
Cumulative Effect of Adoption of New Accounting Standard | — |  |  | (78,284) |  |  | 18,947 |  |  | — |  |  |  |  |  |  | (59,337) |
June 30, 2022 | $ | 1,918 |  |  | $ | 2,665,440 |  |  | $ | (116,081) |  |  | $ | (14,253) |  |  |  |  |  |  | $ | 2,537,024 |

The accompanying notes are an integral part of these financial statements.
10

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) | Six Months Ended
Dollars in Thousands | June 30,
Cash Flows from Operating Activities: | 2023 |  | 2022
Net Income (Loss) | $ | 1,185,350 |  |  | $ | (889,585) |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities: |  |  |
Depreciation, Depletion and Amortization | 208,904 |  |  | 234,803 |
Amortization of Deferred Financing Costs | 4,614 |  |  | 4,115 |
Stock-Based Compensation | 13,180 |  |  | 11,053 |
Gain on Asset Sales and Abandonments, net | (115,468) |  |  | (19,634) |
Loss on Debt Extinguishment | — |  |  | 12,981 |
(Gain) Loss on Commodity Derivative Instruments | (1,304,639) |  |  | 2,379,036 |
Loss (Gain) on Other Derivative Instruments | 1,137 |  |  | (7,353) |
Net Cash Paid in Settlement of Commodity Derivative Instruments | (76,048) |  |  | (800,971) |
Deferred Income Taxes | 376,799 |  |  | (319,814) |
Other | (1,448) |  |  | 2,323 |
Changes in Operating Assets: |  |  |
Accounts and Notes Receivable | 245,783 |  |  | (118,619) |
Recoverable Income Taxes | — |  |  | 72 |
Supplies Inventories | 685 |  |  | (8,343) |
Prepaid Expenses | 1,707 |  |  | 3,407 |
Changes in Other Assets | 345 |  |  | 1,843 |
Changes in Operating Liabilities: |  |  |
Accounts Payable | (36,224) |  |  | 28,508 |
Accrued Interest | 18,490 |  |  | (1,466) |
Other Operating Liabilities | (75,450) |  |  | 16,820 |
Changes in Other Liabilities | (251) |  |  | (814) |
Net Cash Provided by Operating Activities | 447,466 |  |  | 528,362 |
Cash Flows from Investing Activities: |  |  |
Capital Expenditures | (366,013) |  |  | (258,984) |
Proceeds from Asset Sales | 142,809 |  |  | 26,530 |
Net Cash Used in Investing Activities | (223,204) |  |  | (232,454) |
Cash Flows from Financing Activities: |  |  |
Payments on Long-Term Notes | — |  |  | (26,969) |
Proceeds from CNXM Revolving Credit Facility Borrowings | 133,300 |  |  | 177,400 |
Repayments of CNXM Revolving Credit Facility Borrowings | (187,500) |  |  | (174,100) |
Proceeds from CNX Revolving Credit Facility Borrowings | 907,300 |  |  | 1,492,725 |
Repayments of CNX Revolving Credit Facility Borrowings | (907,300) |  |  | (1,551,075) |
Payments on Other Debt | (710) |  |  | (311) |
Proceeds from Issuance of Common Stock | 738 |  |  | 983 |
Shares Withheld for Taxes | (9,384) |  |  | (5,665) |
Purchases of Common Stock | (158,906) |  |  | (211,967) |
Debt Issuance and Financing Fees | (356) |  |  | (256) |
Net Cash Used in Financing Activities | (222,818) |  |  | (299,235) |
Net Increase (Decrease) in Cash, Cash Equivalents | 1,444 |  |  | (3,327) |
Cash and Cash Equivalents at Beginning of Period | 21,321 |  |  | 3,565 |
Cash and Cash Equivalents at End of Period | $ | 22,765 |  |  | $ | 238 |

The accompanying notes are an integral part of these financial statements.
11

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 ("GAAP") 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, 2023 are not necessarily indicative of the results that may be expected for future periods.
The Consolidated Balance Sheet at December 31, 2022 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, 2022 included in CNX Resources Corporation's ("CNX," "CNX Resources," the "Company," "we," "us," or "our") Annual Report on Form 10-K as filed with the Securities and Exchange Commission (SEC) on February 9, 2023.
Certain amounts in prior periods have been reclassified to conform to the current period presentation.
Cash & Cash Equivalents
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Receivables
As of June 30, 2023 and December 31, 2022, Accounts Receivable - Trade were $97,702 and $348,458, respectively, and Other Receivables were $11,370 and $6,184, respectively.
The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. Management records an allowance for credit losses related to the collectability of third-party customers' receivables using the historical aging of the customer receivable balance. The collectability is determined based on past events, including historical experience, customer credit rating, as well as current market conditions. CNX monitors customer ratings and collectability on an on-going basis. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.
The following represents activity related to the allowance for credit losses for the six months ended:

| June 30,
| 2023 |  | 2022
Allowance for Credit Losses - Trade, Beginning of Year | $ | 84 |  |  | $ | 84 |
Provision for Expected Credit Losses | — |  |  | — |
Allowance for Credit Losses - Trade, End of Period | $ | 84 |  |  | $ | 84 |
Allowance for Credit Losses - Other Receivables, Beginning of Year | $ | 2,937 |  |  | $ | 3,322 |
Provision for Expected Credit Losses | (96) |  |  | (376) |
Write-off of Uncollectible Accounts | (93) |  |  | (178) |
Allowance for Credit Losses - Other Receivables, End of Period | $ | 2,748 |  |  | $ | 2,768 |

NOTE 2—EARNINGS PER SHARE:
Basic earnings per share is computed by dividing net income or net loss by the weighted average shares outstanding during the reporting period. Diluted earnings per share is computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include, if dilutive, additional shares from stock options, restricted stock
12

units, performance share units and shares issuable upon conversion of CNX's outstanding 2.25% convertible senior notes due May 2026 (the "Convertible Notes") (See Note 10 – Long-Term Debt). The number of additional shares is calculated by assuming that outstanding stock options were exercised, that outstanding restricted stock units and performance share units were released, that the shares that are issuable from the conversion of the Convertible Notes are issued (subject to the considerations discussed further in the paragraph below), and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In periods when CNX recognizes a net loss, the impact of outstanding stock awards and the potential share settlement impact related to CNX's Convertible Notes are excluded from the diluted loss per share calculation as their inclusion would have an anti-dilutive effect.
The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive:

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
| 2023 |  | 2022 |  | 2023 |  | 2022
Anti-Dilutive Options | 21,232 |  |  | 6,796 |  |  | 16,070 |  |  | 2,303,516 |
Anti-Dilutive Restricted Stock Units | 113,149 |  |  | 57,050 |  |  | 513,294 |  |  | 2,524,803 |
Anti-Dilutive Performance Share Units | — |  |  | — |  |  | — |  |  | 2,119,458 |
| 134,381 |  |  | 63,846 |  |  | 529,364 |  |  | 6,947,777 |

The Convertible Notes, if converted by the holder, may be settled in cash, shares of the Company's common stock or a combination thereof, at the Company's election. The Company expects to settle the principal amount of the Convertible Notes in cash. Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity ("ASU 2020-06") amended the diluted earnings per share calculation for convertible instruments by requiring the use of the if-converted method (See Note 10 – Long-Term Debt for more information). The if-converted method assumes the conversion of convertible instruments occurs at the beginning of the reporting period and diluted weighted average shares outstanding includes the common shares issuable upon conversion of the convertible instruments. In periods where CNX recognizes net income, the conversion spread has a dilutive impact on diluted earnings per share when the average market price of the Company's common stock for a given period exceeds the initial conversion price of $12.84 per share for the Convertible Notes. In connection with the Convertible Notes' issuance, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls" and "Capped Call Transactions"), which were not included in calculating the number of diluted shares outstanding, as their effect would have been anti-dilutive.
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,
| 2023 |  | 2022 |  | 2023 |  | 2022
Options | 17,636 |  |  | 53,180 |  |  | 73,629 |  |  | 136,604 |
Restricted Stock Units | 19,698 |  |  | 43,241 |  |  | 896,785 |  |  | 959,162 |
Performance Share Units | 8,897 |  |  | — |  |  | 576,421 |  |  | 72,353 |
| 46,231 |  |  | 96,421 |  |  | 1,546,835 |  |  | 1,168,119 |

13

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

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
| 2023 |  | 2022 |  | 2023 |  | 2022
Net Income (Loss) | $ | 474,955 |  |  | $ | 33,357 |  |  | $ | 1,185,350 |  |  | $ | (889,585) |
Basic Earnings (Loss) Available to Shareholders | $ | 474,955 |  |  | $ | 33,357 |  |  | $ | 1,185,350 |  |  | $ | (889,585) |
Effect of Dilutive Securities: |  |  |  |  |  |  |
Add Back Interest on Convertible Notes (Net of Tax) | $ | 1,409 |  |  | $ | 1,376 |  |  | $ | 2,818 |  |  | $ | — |
Diluted Earnings (Loss) Available to Shareholders | $ | 476,364 |  |  | $ | 34,733 |  |  | $ | 1,188,168 |  |  | $ | (889,585) |
Weighted-Average Shares of Common Stock Outstanding | 164,139,583 |  |  | 194,021,639 |  |  | 166,283,932 |  |  | 196,921,836 |
Effect of Diluted Shares:* |  |  |  |  |  |  |
Options | 1,046,210 |  |  | 1,349,984 |  |  | 1,041,479 |  |  | — |
Restricted Stock Units | 1,073,001 |  |  | 1,603,876 |  |  | 1,028,799 |  |  | — |
Performance Share Units | 980,923 |  |  | 1,681,326 |  |  | 981,350 |  |  | — |
Convertible Notes | 25,751,869 |  |  | 25,751,869 |  |  | 25,751,869 |  |  | — |
Weighted-Average Diluted Shares of Common Stock Outstanding | 192,991,586 |  |  | 224,408,694 |  |  | 195,087,429 |  |  | 196,921,836 |
Earning (Loss) per Share: |  |  |  |  |  |  |
Basic | $ | 2.89 |  |  | $ | 0.17 |  |  | $ | 7.13 |  |  | $ | (4.52) |
Diluted | $ | 2.47 |  |  | $ | 0.15 |  |  | $ | 6.09 |  |  | $ | (4.52) |

*During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards and the potential share settlement impact related to CNX's Convertible Notes are antidilutive.
NOTE 3—REVENUE FROM CONTRACTS WITH CUSTOMERS:
Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to exclude all taxes from the measurement of transaction price.
For natural gas, NGL and oil, and purchased gas revenue, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company’s efforts to satisfy the performance obligations. A portion of the contracts contain fixed consideration (i.e., fixed price contracts or contracts with a fixed differential to NYMEX or index prices). The fixed consideration is allocated to each performance obligation on a relative standalone selling price basis. 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, NGL and oil as presented on the accompanying Consolidated Statements of Income represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling natural gas, NGL and oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.
Included in Other Revenue and Operating Income in the Consolidated Statements of Income and in the below table are revenues generated from natural gas gathering services provided to third parties. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric based fees are based on actual volumes gathered. The Company generally considers the interruptible gathering of each unit (MMBtu) of natural gas as a separate performance obligation. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered.
14

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

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
2023 |  | 2022 |  | 2023 |  | 2022
Revenue from Contracts with Customers: |  |  |  |  |  |  |
Natural Gas Revenue | $ | 223,222 |  |  | $ | 934,127 |  |  | $ | 627,032 |  |  | $ | 1,609,401 |
NGL Revenue | 30,763 |  |  | 63,774 |  |  | 76,819 |  |  | 128,569 |
Oil/Condensate Revenue | 3,076 |  |  | 5,505 |  |  | 8,849 |  |  | 10,060 |
Total Natural Gas, NGL and Oil Revenue | 257,061 |  |  | 1,003,406 |  |  | 712,700 |  |  | 1,748,030 |
Purchased Gas Revenue | 9,355 |  |  | 46,552 |  |  | 46,167 |  |  | 92,393 |
Other Sources of Revenue and Other Operating Income (Loss): |  |  |  |  |  |  |
Gain (Loss) on Commodity Derivative Instruments | 542,472 |  |  | (652,643) |  |  | 1,304,639 |  |  | (2,379,036) |
Other Revenue and Operating Income | 30,812 |  |  | 23,103 |  |  | 52,170 |  |  | 45,933 |
Total Revenue and Other Operating Income (Loss) | $ | 839,700 |  |  | $ | 420,418 |  |  | $ | 2,115,676 |  |  | $ | (492,680) |

The disaggregated revenue information corresponds with the Company’s segment reporting found in Note 14 – Segment Information.
Contract Balances
CNX invoices its customers once a performance obligation has been satisfied, at which point payment is unconditional. Accordingly, CNX's contracts with customers do not give rise to material contract assets or liabilities under Accounting Standards Codification (ASC) 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer.
Transaction Price Allocated to Remaining Performance Obligations
ASC 606 requires that the Company disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement, including when variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a series.
A significant portion of CNX's natural gas, NGL and oil and purchased gas revenue is short-term in nature with a contract term of one year or less. For those contracts, CNX has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For revenue associated with contract terms greater than one year, a significant portion of the consideration in those contracts is variable in nature and the Company allocates the variable consideration in its contract entirely to each specific performance obligation to which it relates. Therefore, any remaining variable consideration in the transaction price is allocated entirely to wholly unsatisfied performance obligations. As such, the Company has not disclosed the value of unsatisfied performance obligations pursuant to the practical expedient.
For natural gas, NGL and oil revenue associated with contract terms greater than one year with a fixed price component, the aggregate amount of the transaction price allocated to remaining performance obligations was $31,332 as of June 30, 2023. The Company expects to recognize net revenue of $20,133 in the next 12 months and $9,013 over the following 12 months, with the remainder recognized thereafter.
For revenue associated with CNX's midstream contracts, which also have terms greater than one year, the interruptible gathering of each unit of natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
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Prior-Period Performance Obligations
CNX records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas, NGL and oil revenue may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. CNX records the differences between the estimate and the actual amounts received in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and the related accruals, and any identified differences between its revenue estimates and the actual revenue received historically have not been significant. For the three and six months ended June 30, 2023 and 2022, revenue recognized in the current reporting period related to performance obligations satisfied in a prior reporting period was not material.
NOTE 4—ACQUISITIONS AND DISPOSITIONS:
On June 29, 2023, CNX closed on the sale of various non-operated producing oil and gas assets primarily located in the Appalachian Basin to a third party. The net cash proceeds of $119,918 are included in Proceeds from Asset Sales in the Consolidated Statements of Cash Flows and the net gain on the transaction of $102,420 is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
Additionally, Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income for the three and six months ended June 30, 2023 and 2022 and Proceeds from Asset Sales in the Consolidated Statements of Cash Flows for the six months ended June 30, 2023 and 2022 include the sale of various non-core assets (rights-of-way, surface acreage and other non-care oil and gas interests), none of which were individually material.
NOTE 5—INCOME TAXES:
The effective tax rates for the three and six months ended June 30, 2023 were 25.4% and 24.2%, respectively. The effective tax rates for the three and six months ended June 30, 2022 were 28.9% and 26.0%, respectively. The effective tax rate for the three and six months ended June 30, 2023 differs from the U.S. federal statutory rate of 21.0% primarily due to the impact of equity compensation, federal tax credits and state taxes primarily due to state taxes and West Virginia tax law change. The effective tax rate for the three and six months ended June 30, 2022 differs from the U.S. federal statutory rate of 21.0% primarily due to the impact of certain permanent differences related to the repurchase of the Convertible Notes (See Note 10 – Long-Term Debt for more information), equity compensation and state taxes.
The total amount of uncertain tax positions at June 30, 2023 and December 31, 2022 was $89,341 and $82,245, respectively. If these uncertain tax positions were recognized, approximately $89,341 and $82,245 would affect CNX's effective tax rate at June 30, 2023 and December 31, 2022, respectively. In 2023, CNX recognized an increase in uncertain tax positions of $7,096 for tax benefits resulting from tax positions anticipated to be taken on our 2023 federal tax return for additional federal tax credits.
CNX recognizes accrued interest and penalties related to uncertain tax positions in interest expense and income tax expense, respectively. As of June 30, 2023 and December 31, 2022, CNX had no accrued liabilities for interest and penalties related to uncertain tax positions.
CNX and its subsidiaries file federal income tax returns with the United States and tax returns within various states. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2019.
West Virginia enacted legislation in March 2023 for public companies which allows for a deduction for the deferred tax adjustment as of January 1, 2022 resulting from the change in state apportionment methodology from three factor to single sales factor and elimination of the throw-out rule if the change results in an aggregate increase in net deferred tax liabilities, decrease in net deferred tax assets, or change from a net deferred tax asset to a net deferred tax liability. The deduction is available over a ten-year period beginning with the first tax year on or after January 1, 2033. The Company has recorded a discrete income tax benefit of approximately $15,983 in the Consolidated Statements of Income to reflect the recent legislative change resulting in a decrease to deferred tax liabilities in the Consolidated Balance Sheets.
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NOTE 6—PROPERTY, PLANT AND EQUIPMENT:

| June 30, 2023 |  | December 31, 2022
Intangible Drilling Cost | $ | 5,749,646 |  |  | $ | 5,554,021 |
Gas Gathering Equipment | 2,576,681 |  |  | 2,542,587 |
Gas Wells and Related Equipment | 1,440,999 |  |  | 1,342,719 |
Proved Gas Properties | 1,368,079 |  |  | 1,345,114 |
Unproved Gas Properties | 720,697 |  |  | 734,890 |
Surface Land and Other Equipment | 191,123 |  |  | 193,153 |
Other | 200,633 |  |  | 195,214 |
Total Property, Plant and Equipment | 12,247,858 |  |  | 11,907,698 |
Less: Accumulated Depreciation, Depletion and Amortization | 5,008,026 |  |  | 4,811,189 |
Total Property, Plant and Equipment - Net | $ | 7,239,832 |  |  | $ | 7,096,509 |

NOTE 7—GOODWILL AND OTHER INTANGIBLE ASSETS:
Goodwill:
All goodwill is attributed to the Midstream reporting unit within the Shale segment. Goodwill is evaluated for impairment at least annually and whenever events or changes in circumstance indicate that the fair value of a reporting unit is less than its carrying amount.
The accumulated impairment loss on goodwill is $473,045, resulting in a carrying value of $323,314 at both June 30, 2023 and December 31, 2022.
Other Intangible Assets:
The carrying amount and accumulated amortization of other intangible assets consist of the following:

| June 30, 2023 |  | December 31, 2022
Other Intangible Assets: |  |  |
Gross Amortizable Asset - Customer Relationships | $ | 109,752 |  |  | $ | 109,752 |
Less: Accumulated Amortization - Customer Relationships | 36,038 |  |  | 32,762 |
Total Other Intangible Assets, net | $ | 73,714 |  |  | $ | 76,990 |

The customer relationship intangible asset is being amortized on a straight-line basis over approximately 17 years. Amortization expense related to other intangible assets for the three and six months ended June 30, 2023 was $1,638 and $3,276, respectively. Amortization expense related to other intangible assets for the three and six months ended June 30, 2022 was $1,638 and $3,277, respectively. The estimated annual amortization expense is expected to approximate $6,552 per year for each of the next five years.
NOTE 8—REVOLVING CREDIT FACILITIES:
CNX:
On May 10, 2023 and May 5, 2022, CNX amended its Third Amended and Restated Credit Agreement dated October 6, 2021, which provides for a senior secured revolving credit facility (as amended, the "CNX Credit Agreement"). In 2022, revisions were made to replace LIBOR as a benchmark interest rate with SOFR, or the secured overnight financing rate. In 2023, the elected commitments of the CNX Credit Agreement were increased from $1,300,000 to $1,350,000. Following the amendments, CNX remains the borrower and certain of its subsidiaries (not including CNX Midstream Partners LP (CNXM), its subsidiaries or general partner) as guarantor loan parties on the CNX Credit Agreement. The CNX Credit Agreement replaced the prior CNX revolving credit facility and remains subject to semi-annual redetermination. The CNX Credit Agreement has a $2,250,000 borrowing base and $1,350,000 in elected commitments, including borrowings and letters of credit. The CNX Credit Agreement matures on October 6, 2026, provided that if at any time on or after January 30, 2026 availability under the CNX Credit Agreement minus the aggregate principal amount of any and all such outstanding
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Convertible Notes is less than 20% of the aggregate commitments under the CNX Credit Agreement (the first such date, the "Springing Maturity Date"), then the CNX Credit Agreement will mature on the Springing Maturity Date.
In addition to refinancing all outstanding amounts under the prior CNX revolving credit facility, borrowings under the CNX Credit Agreement may be used by CNX for general corporate purposes.
Under the terms of the CNX Credit Agreement, borrowings will bear interest at CNX's option at either:
•the highest of (i) PNC Bank, National Association’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month SOFR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or
•the one-month SOFR rate plus a margin ranging from 1.85% to 2.85%.
The availability under the CNX Credit Agreement, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of the Company’s proved reserves.
The CNX Credit Agreement also requires that CNX maintain a maximum net leverage ratio of no greater than 3.50 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 derivative asset/liability position, and convertible note liability until one year prior to maturity, and borrowings under the revolver, measured quarterly. The calculation of all of the ratios excludes CNX Gathering and CNXM and its subsidiaries. CNX was in compliance with all financial covenants as of June 30, 2023.
At June 30, 2023, the CNX Credit Agreement had no borrowings outstanding and $94,535 of letters of credit outstanding, leaving $1,255,465 of unused capacity. At December 31, 2022, the CNX Credit Agreement had no borrowings outstanding and $171,272 of letters of credit outstanding, leaving $1,128,728 of unused capacity.
CNXM:
On May 5, 2022 CNXM amended its Amended and Restated Credit Agreement dated October 6, 2021, which provides for a $600,000 senior secured revolving credit facility (as amended, the "CNXM Credit Agreement") that matures on October 6, 2026. Revisions were made to replace LIBOR as a benchmark interest rate with SOFR. CNXM remains the borrower and certain of its subsidiaries remain as guarantor loan parties on the CNXM Credit Agreement. The CNXM Credit Agreement replaced the prior CNXM revolving credit facility and is not subject to semi-annual redetermination. CNX is not a guarantor under the CNXM Credit Agreement.
In addition to refinancing all outstanding amounts under the prior CNXM revolving credit facility, borrowings under the CNXM Credit Agreement may be used by CNXM for general corporate purposes.
Interest on outstanding indebtedness under the CNXM Credit Agreement currently accrues, at CNXM's option, at a rate based on either:
•the highest of (i) PNC Bank, National Association’s prime rate, (ii) the federal funds open rate plus 0.50%, and (iii) the one-month SOFR rate plus 1.0%, in each case, plus a margin ranging from 1.00% to 2.00%; or
•the one-month SOFR rate plus a margin ranging from 2.10% to 3.10%.
In addition, CNXM is obligated to maintain at the end of each fiscal quarter (x) a maximum net leverage ratio of no greater than between 5.00 to 1.00 ranging to no greater than 5.25 to 1.00 in certain circumstances; (y) a maximum secured leverage ratio of no greater than 3.25 to 1.00; and (z) a minimum interest coverage ratio of no less than 2.50 to 1.00; in each case as calculated in accordance with the terms and definitions determining such ratios contained in the CNXM Credit Agreement. CNXM was in compliance with all financial covenants as of June 30, 2023.
At June 30, 2023, the CNXM Credit Agreement had $99,500 of borrowings outstanding, with a weighted average interest rate of 7.27% and no letters of credit outstanding, leaving $500,500 of unused capacity. At December 31, 2022, the CNXM Credit Agreement had $153,700 of borrowings outstanding, with a weighted average interest rate of 6.45%, and $30 of letters of credit outstanding, leaving $446,270 of unused capacity.
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NOTE 9—OTHER ACCRUED LIABILITIES:

| June 30, 2023 |  | December 31, 2022
Royalties | $ | 88,568 |  |  | $ | 144,482 |
Accrued Interest | 55,234 |  |  | 36,744 |
Transportation Charges | 21,123 |  |  | 12,808 |
Deferred Revenue | 20,856 |  |  | 22,095 |
Accrued Other Taxes | 8,916 |  |  | 14,067 |
Accrued Payroll & Benefits | 6,874 |  |  | 6,318 |
Short-Term Incentive Compensation | 6,404 |  |  | 18,956 |
Purchased Gas Payable | 1,057 |  |  | 5,266 |
Other | 11,734 |  |  | 18,142 |
Current Portion of Long-Term Liabilities: |  |  |
Asset Retirement Obligations | 9,735 |  |  | 9,735 |
Salary Retirement | 1,916 |  |  | 1,878 |
Total Other Accrued Liabilities | $ | 232,417 |  |  | $ | 290,491 |

NOTE 10—LONG-TERM DEBT:

| June 30, 2023 |  | December 31, 2022
Senior Notes due January 2029 at 6.00%, Issued at Par Value | $ | 500,000 |  |  | $ | 500,000 |
Senior Notes due January 2031 at 7.375% (Principal of $500,000 less Unamortized Discount of $5,685 and $6,061, respectively) | 494,315 |  |  | 493,939 |
CNX Midstream Partners LP Senior Notes due April 2030 at 4.75% (Principal of $400,000 less Unamortized Discount of $3,942 and $4,231, respectively)* | 396,058 |  |  | 395,769 |
Senior Notes due March 2027 at 7.25% (Principal of $350,000 plus Unamortized Premium of $1,997 and $2,266, respectively) | 351,997 |  |  | 352,266 |
Convertible Senior Notes due May 2026 at 2.25% (Principal of $330,654 less Unamortized Discount and Issuance Costs of $5,530 and $6,460, respectively) | 325,124 |  |  | 324,194 |
CNX Midstream Partners LP Revolving Credit Facility* | 99,500 |  |  | 153,700 |
Less: Unamortized Debt Issuance Costs | 12,901 |  |  | 14,133 |
Long-Term Debt | $ | 2,154,093 |  |  | $ | 2,205,735 |

*CNX is not a guarantor of CNXM's 4.75% Senior Notes due April 2030 or CNXM's Credit Facility.
In April 2020, CNX issued $345,000 in aggregate principal amount of Convertible Notes due May 2026 ("Convertible Notes") in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, including $45,000 aggregate principal amount of Convertible Notes issued pursuant to the exercise in full of the initial purchasers’ option to purchase additional Convertible Notes. The Convertible Notes are senior, unsecured obligations of the Company. The Convertible Notes bear interest at a fixed rate of 2.25% per annum, payable semi-annually in arrears on May 1 and November 1 of each year, commencing on November 1, 2020. Proceeds from the issuance of the Convertible Notes totaled $334,650, net of initial purchaser discounts and issuance costs. The Convertible Notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
The initial conversion rate is 77.8816 shares of CNX's common stock per $1,000 principal amount of Convertible Notes, which represents an initial conversion price of approximately $12.84 per share, subject to adjustment upon the occurrence of specified events.
The Convertible Notes will mature on May 1, 2026, unless earlier repurchased, redeemed or converted. Before February 1, 2026, note holders will have the right to convert their Convertible Notes only upon the occurrence of the following events:
•during any calendar quarter (and only during such calendar quarter) commencing after June 30, 2020, if the Last Reported Sale Price per share of Common Stock exceeds one hundred and thirty percent (130%) of the Conversion Price for each of at least twenty (20) Trading Days (whether or not consecutive) during the thirty (30) consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter;
•during the five (5) consecutive Business Days immediately after any ten (10) consecutive trading day period (such ten
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(10) consecutive Trading Day period, the "Measurement Period") if the trading Price per $1,000 principal amount of Notes, as determined following a request by a Holder in accordance with the procedures set forth in the indenture, for each trading day of the Measurement Period was less than ninety eight percent (98%) of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day;
•if CNX calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or
•upon the occurrence of certain specified corporate events as set forth in the indenture governing the Convertible Notes.
From and after February 1, 2026, note holders may convert their Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date.
Upon conversion, the Company may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture governing the Convertible Notes. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the Convertible Notes, that occur prior to the maturity date, the Company will increase the conversion rate, in certain circumstances, for a holder who elects to convert its Convertible Notes in connection with such a corporate event.
The Company’s current intent is to settle the principal amount of the Convertible Notes in cash upon conversion.
If certain corporate events that constitute a “Fundamental Change” (as defined in the indenture governing the Convertible Notes) occur, then noteholders may require the Company to repurchase their Convertible Notes at a cash repurchase price equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock. At June 30, 2023, the conditions allowing holders of the Convertible Notes to exercise their conversion right were not met and as of June 30, 2023, the Convertible Notes were not convertible. The Convertible Notes are therefore classified as long-term debt at June 30, 2023.
On January 1, 2022, the Company adopted ASU 2020-06 using the modified transition approach with the cumulative effect recognized as an adjustment to the opening balance of retained earnings. This guidance is applicable to the Convertible Notes, for which the embedded conversion option was required to be separately accounted for as a component of stockholders’ equity. Upon adoption on January 1, 2022, long-term debt increased by $82,327 representing the net impact of two adjustments: (1) the $107,260 value of the embedded conversion, which is net of allocated offering costs, previously classified in additional paid-in-capital in stockholders’ equity, and (2) a $24,933 increase to retained earnings for the cumulative effect of adoption primarily related to the non-cash interest expense recorded for the amortization of the portion of the Convertible Notes allocated to stockholders’ equity. In addition, there was a decrease of $22,990 to deferred income taxes, a $5,986 decrease to retained earnings, and a $78,284 decrease in stockholders' equity in the Consolidated Balance Sheet. Prospectively, the reported interest expense for the Convertible Notes will no longer include the non-cash interest expense of the equity component as required under prior accounting standards and will be equal to the 2.25% cash coupon rate. Also, as required by the new accounting guidance, the Company will use the if-converted method instead of the treasury stock method for the assumed conversion of the Convertible Notes on a prospective basis when calculating diluted earnings per share.
Prior to the adoption of ASU 2020-06, the Convertible Notes were separated into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of a similar debt instrument that does not have an associated conversion feature. The fair value was based on market data available for publicly traded, senior, unsecured corporate bonds with similar maturity, which represent Level 2 observable inputs. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes and was recorded in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity and was not remeasured as long as it continued to meet the conditions for equity classification. The excess of the principal amount of the Convertible Notes over the liability component and the debt issuance costs was amortized to interest expense over the contractual term of the Convertible Notes using the effective interest method.
In accounting for the debt issuance costs of $10,350, the Company allocated the total amount incurred to the liability and equity components using the same proportions as the proceeds of the Convertible Notes. Issuance costs attributable to the liability component were $7,024 and were being amortized to interest expense using the effective interest method over the contractual term of the Convertible Notes. Issuance costs attributable to the equity component were $3,326 and were netted with the equity component in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity.
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The net carrying amount of the liability and equity components of the Convertible Notes was as follows:

| June 30, 2023 |  | December 31, 2022
Liability Component: |  |  |
Principal | $ | 330,654 |  |  | $ | 330,654 |
Unamortized Issuance Costs | (5,530) |  |  | (6,460) |
Net Carrying Amount | $ | 325,124 |  |  | $ | 324,194 |
Fair Value | $ | 489,103 |  |  | $ | 483,581 |
Fair Value Hierarchy | Level 2 |  | Level 2

Interest expense related to the Convertible Notes is as follows:

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
| 2023 |  | 2022 |  | 2023 |  | 2022
Contractual Interest Expense | $ | 1,860 |  |  | $ | 1,918 |  |  | $ | 3,720 |  |  | $ | 3,857 |
Amortization of Issuance Costs | 467 |  |  | 483 |  |  | 930 |  |  | 954 |
Total Interest Expense | $ | 2,327 |  |  | $ | 2,401 |  |  | $ | 4,650 |  |  | $ | 4,811 |

In connection with the offering of the Convertible Notes, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls"). The Capped Calls each have an initial strike price of $12.84 per share, subject to certain adjustments, which correspond to the initial conversion price of the Convertible Notes. The Capped Calls have an initial cap price of $18.19 per share, subject to certain adjustments. The Capped Calls cover, subject to anti-dilution adjustments, the aggregate number of shares of the Company’s common stock that initially underlie the Convertible Notes, and are expected generally to reduce potential dilution to the Company’s common stock upon any conversion of Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of converted Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap, based on the cap price of the Capped Call Transactions. The conditions that cause adjustments to the initial strike price of the Capped Calls mirror the conditions that result in corresponding adjustments for the Convertible Notes. For accounting purposes, the Capped Calls are separate transactions, and not part of the terms of the Convertible Notes. As these transactions meet certain accounting criteria, the Capped Calls are recorded in stockholders’ equity and are not accounted for as derivatives. The cost of $35,673 incurred in connection with the Capped Calls was recorded as a reduction to Capital in Excess of Par Value.
During the three months ended June 30, 2022, CNX purchased $14,346 of its outstanding Convertible Notes. As part of this transaction a loss of $12,981 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income during the three and six months ended June 30, 2022. No purchases were made during the three and six months ended June 30, 2023.
NOTE 11—COMMITMENTS AND CONTINGENT LIABILITIES:
CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, royalty accounting, damage to property, climate change, governmental regulations including environmental violations and remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CNX; however, such amounts cannot be reasonably estimated.
The 1992 Coal Industry Retiree Health Benefit Act ("Coal Act"), in Section 9711, requires coal companies that were providing health benefits to United Mine Workers of America ("UMWA") retirees as of February 1993 to continue providing health benefits to such individuals, in substantially the same coverages, for as long as the last signatory operator remains in business. Section 9711 also requires any "related person" to be joint and severally liable for the provision of these health benefits. On May 1, 2020, the court in the Murray Energy Corporation ("Murray") bankruptcy proceedings approved a settlement agreement between Murray and the UMWA that transferred to the UMWA 1992 Benefit Plan the Coal Act liabilities for retirees in Murray’s Section 9711 plan. The retirees transferred by Murray to the 1992 Benefit Plan include approximately
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2,159 retirees allegedly traced to the December 2013 sale by CONSOL Energy Inc. to Murray Energy of the following possible last signatory operators: Consolidation Coal Company, McElroy Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Keystone Coal Mining Corp., and Eight-Four Coal Mining Company (the "Sold Subsidiaries"). On May 2, 2020, the Trustees of the UMWA 1992 Benefit Plan sued CNX and CONSOL Energy Inc. ("CONSOL'") in federal court contending that the Sold Subsidiaries were last signatory operators and that CNX and CONSOL are related persons to the Sold Subsidiaries and, as such, CNX and CONSOL are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The 1992 Plan seeks, among other relief, a declaration that CNX and CONSOL are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 Plan; that CNX and CONSOL are liable to post the security required by Section 9712; and, that CNX and CONSOL are liable to pay per beneficiary premiums until the eligible retirees are enrolled in a Section 9711 plan, and other fees, costs and disbursements under the Coal Act. On March 29, 2022, the Court denied the Defendants’ Motions to Dismiss and we are now defending this action on the merits. Further, under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, CONSOL agreed to indemnify CNX for all coal-related liabilities, including this lawsuit. With respect to this matter, although a loss is possible, it is not probable, and accordingly no accrual has been recognized.
On July 22, 2021, CNX received a letter from the UMWA 1974 Pension Plan requesting information related to the facts and circumstances surrounding the 2013 sale of certain of its coal subsidiaries to Murray Energy. The letter indicates that litigation related to potential withdrawal liabilities from the plan created by the 2019 bankruptcy of Murray Energy is reasonably foreseeable. At this time, no liability has been assessed. Under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, CONSOL agreed to indemnify CNX for all coal-related liabilities including any potential withdrawal liabilities.
At June 30, 2023, CNX has provided the following financial guarantees, unconditional purchase obligations, and letters of credit to certain third-parties as described by major category in the following tables. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management believes that the commitments in the following table will expire without being funded, and therefore will not have a material adverse effect on CNX's 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 | $ | 91,448 |  |  | $ | 91,448 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other | 3,087 |  |  | 3,087 |  |  | — |  |  | — |  |  | — |
Total Letters of Credit | 94,535 |  |  | 94,535 |  |  | — |  |  | — |  |  | — |
Surety Bonds: |  |  |  |  |  |  |  |  |
Employee-Related | 2,250 |  |  | 2,250 |  |  | — |  |  | — |  |  | — |
Environmental | 11,509 |  |  | 11,451 |  |  | 58 |  |  | — |  |  | — |
Firm Transportation | 76,336 |  |  | 76,336 |  |  | — |  |  | — |  |  | — |
Financial Guarantees | 81,270 |  |  | 81,270 |  |  | — |  |  | — |  |  | — |
Other | 8,603 |  |  | 7,119 |  |  | 1,484 |  |  | — |  |  | — |
Total Surety Bonds | 179,968 |  |  | 178,426 |  |  | 1,542 |  |  | — |  |  | — |
Total Commitments | $ | 274,503 |  |  | $ | 272,961 |  |  | $ | 1,542 |  |  | $ | — |  |  | $ | — |

Excluded from the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business in November 2017. Although CONSOL has agreed to indemnify CNX to the extent that CNX would be called upon to pay any of these liabilities, there is no assurance that CONSOL will satisfy its obligations to indemnify CNX in the event that CNX is so called upon (See "Item 1A. Risk Factors" in CNX's 2022 Annual Report on Form 10-K as filed with the SEC on February 9, 2023 ("2022 Form 10-K") for additional information).
CNX enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded in the Consolidated Balance Sheets. As of June 30, 2023, the purchase obligations for each of the next five years and beyond are as follows:
22

Obligations Due | Amount
Less than 1 year | $ | 247,372 |
1 - 3 years | 432,561 |
3 - 5 years | 356,584 |
More than 5 years | 652,823 |
Total Purchase Obligations | $ | 1,689,340 |

NOTE 12—DERIVATIVE INSTRUMENTS:
CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The change in fair value of the interest rate swap agreements is accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings.
In March 2020, CNX entered into an interest rate swap agreement, inclusive of a put option at zero basis points, related to $160,000 of borrowings under the CNX Credit Facility which has the economic effect of modifying the variable-interest obligation into a fixed-interest obligation over a four year period.
In March 2020, CNX entered into a four-year interest rate swap related to an additional $250,000 of borrowings under the CNX Credit Facility, inclusive of a put option at zero basis points, effective April 3, 2020. In December 2020, CNX executed an offsetting $250,000 interest rate swap, effective immediately, which expires in April 2024. Consistent with the previous interest rate swap agreements, the $250,000 interest rate swaps were entered into to manage CNX's exposure to interest rate volatility.
CNX enters into financial derivative instruments (over-the-counter swaps) to manage its exposure to natural gas and NGL price fluctuations. Typically, CNX "sells" swaps under which it receives a fixed price from counterparties and pays a floating market price. In order to lock in certain margins while balancing its basis hedges, during the first quarter of 2022, CNX purchased, rather than sold, financial natural gas swaps for the period April through October of 2022. Under these purchased financial swaps, CNX pays a fixed price to, and receives a floating price from, its hedge counterparties. Purchased swaps have the effect of reducing total hedged volumes for the period of the swap. 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 applicable counterparty master agreements, if CNX's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with our counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis.
Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions.
The total notional amounts of CNX's derivative instruments were as follows:

| June 30, |  | December 31, |  | Forecasted to
| 2023 |  | 2022 |  | Settle Through
Natural Gas Commodity Swaps (Bcf) | 1,538.3 |  |  | 1,607.9 |  |  | 2027
Natural Gas Basis Swaps (Bcf) | 929.0 |  |  | 1,023.7 |  |  | 2027
Propane Commodity Swaps (Mbbls) | 246.6 |  | — |  |  | 2024
Interest Rate Swaps | $ | 410,000 |  |  | $ | 410,000 |  |  | 2024

23

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

| June 30, |  | December 31,
| 2023 |  | 2022
Current Assets: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 84,922 |  |  | $ | 21,759 |
Propane Swaps | 3,035 |  |  | — |
Basis Only Swaps | 124,990 |  |  | 118,115 |
Interest Rate Swaps | 14,065 |  |  | 14,600 |
Total Current Assets | $ | 227,012 |  |  | $ | 154,474 |
Other Non-Current Assets: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 157,010 |  |  | $ | 42,786 |
Basis Only Swaps | 148,877 |  |  | 197,280 |
Interest Rate Swaps | — |  |  | 4,865 |
Total Other Non-Current Assets | $ | 305,887 |  |  | $ | 244,931 |
Current Liabilities: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 208,440 |  |  | $ | 732,717 |
Basis Only Swaps | 21,793 |  |  | 38,559 |
Interest Rate Swaps | 10,641 |  |  | 11,377 |
Total Current Liabilities | $ | 240,874 |  |  | $ | 782,653 |
Non-Current Liabilities: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 771,888 |  |  | $ | 1,466,124 |
Basis Only Swaps | 40,856 |  |  | 47,370 |
Interest Rate Swaps | — |  |  | 3,527 |
Total Non-Current Liabilities | $ | 812,744 |  |  | $ | 1,517,021 |

24

The effect of commodity derivative instruments on the Company's Consolidated Statements of Income was as follows:

|  | For the Three Months Ended |  | For the Six Months Ended
|  | June 30, |  | June 30,
|  | 2023 |  | 2022 |  | 2023 |  | 2022
Realized Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |  |
Natural Gas Commodity Swaps |  | $ | 83,395 |  |  | $ | (558,374) |  |  | $ | 33,469 |  |  | $ | (830,193) |
Natural Gas Basis Swaps |  | (4,455) |  |  | 27,983 |  |  | (15,561) |  |  | 28,961 |
Propane Swaps |  | 619 |  |  | — |  |  | 619 |  |  | — |
Total Realized Gain (Loss) on Commodity Derivative Instruments |  | 79,559 |  |  | (530,391) |  |  | 18,527 |  |  | (801,232) |
Unrealized Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |  |
Natural Gas Commodity Swaps |  | 326,127 |  |  | (197,309) |  |  | 1,306,963 |  |  | (1,851,422) |
Natural Gas Basis Swaps |  | 134,671 |  |  | 75,057 |  |  | (23,564) |  |  | 273,618 |
Propane Swaps |  | 2,115 |  |  | — |  |  | 2,713 |  |  | — |
Total Unrealized Gain (Loss) on Commodity Derivative Instruments |  | 462,913 |  |  | (122,252) |  |  | 1,286,112 |  |  | (1,577,804) |
Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |  |  |  |
Natural Gas Commodity Swaps |  | 409,522 |  |  | (755,683) |  |  | 1,340,432 |  |  | (2,681,615) |
Natural Gas Basis Swaps |  | 130,216 |  |  | 103,040 |  |  | (39,125) |  |  | 302,579 |
Propane Swaps |  | 2,734 |  |  | — |  |  | 3,332 |  |  | — |
Total Gain (Loss) on Commodity Derivative Instruments |  | $ | 542,472 |  |  | $ | (652,643) |  |  | $ | 1,304,639 |  |  | $ | (2,379,036) |

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

|  | For the Three Months Ended |  | For the Six Months Ended
|  | June 30, |  | June 30,
|  | 2023 |  | 2022 |  | 2023 |  | 2022
Cash Received (Paid) in Settlement of Interest Rate Swaps |  | $ | 1,016 |  |  | $ | (763) |  |  | $ | 1,816 |  |  | $ | (1,700) |
Unrealized (Loss) Gain on Interest Rate Swaps |  | (176) |  |  | 2,131 |  |  | (1,137) |  |  | 7,353 |
Gain on Interest Rate Swaps |  | $ | 840 |  |  | $ | 1,368 |  |  | $ | 679 |  |  | $ | 5,653 |

The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and normal sales exception and are not subject to derivative instrument accounting.
NOTE 13—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 and SOFR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:
Level 1 - Quoted prices for identical instruments in active markets.
Level 2 - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach
25

models that use significant observable inputs, including NYMEX forward curves, LIBOR and SOFR-based discount rates and basis forward curves.
Level 3 - Unobservable inputs significant to the fair value measurement supported by little or no market activity.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.
The financial instrument measured at fair value on a recurring basis is summarized below:

| Fair Value Measurements at June 30, 2023 |  | Fair Value Measurements at December 31, 2022
Description | Level 1 |  | Level 2 |  | Level 3 |  | Level 1 |  | Level 2 |  | Level 3
Gas Derivatives | $ | — |  |  | $ | (524,143) |  | * | $ | — |  |  | $ | — |  |  | $ | (1,904,830) |  | ** | $ | — |
Interest Rate Swaps | $ | — |  |  | $ | 3,424 |  |  | $ | — |  |  | $ | — |  |  | $ | 4,561 |  |  | $ | — |

*Includes $16,913 of gas derivatives that have been settled but not received.
**Includes $77,662 of gas derivatives that have been settled but not paid.
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

| June 30, 2023 |  | December 31, 2022
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Cash and Cash Equivalents | $ | 22,765 |  |  | $ | 22,765 |  |  | $ | 21,321 |  |  | $ | 21,321 |
Long-Term Debt (Excluding Debt Issuance Costs) | $ | 2,166,994 |  |  | $ | 2,215,368 |  |  | $ | 2,219,868 |  |  | $ | 2,240,919 |

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 14—SEGMENT INFORMATION:
The Company reports segment information based on the "management" approach. The management approach designates the internal reporting used by management for making decisions and assessing performance as the source of the Company’s reportable segments.
The Company evaluates the performance of its reportable segments based on total revenue and other operating income and operating expenses directly attributable to that segment. Certain expenses are managed outside the reportable segments and therefore are not allocated. These expenses include, but are not limited to, interest expense and other corporate expenses such as selling, general and administrative costs.
CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers and the Company has two reportable segments that conducts those operations: Shale and Coalbed Methane. The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, new technologies, as well as various other expenses that are managed outside the reportable segments as discussed above. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses.
26

Industry segment results for the three months ended June 30, 2023 are:

|  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 234,192 |  |  | $ | 22,634 |  |  | $ | 235 |  |  | $ | 257,061 |  |  |  |  |  |  |  |  |  | (A)
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 9,355 |  |  | 9,355 |  |  |  |  |  |  |  |  |  |
Gain on Commodity Derivative Instruments |  |  | 73,522 |  |  | 6,002 |  |  | 462,948 |  |  | 542,472 |  |  |  |  |  |  |  |  |  |
Other Revenue and Operating Income |  |  | 17,027 |  |  | — |  |  | 13,785 |  |  | 30,812 |  |  |  |  |  |  |  |  |  | (B)
Total Revenue and Other Operating Income |  |  | $ | 324,741 |  |  | $ | 28,636 |  |  | $ | 486,323 |  |  | $ | 839,700 |  |  |  |  |  |  |  |  |  |
Total Operating Expense |  |  | $ | 171,501 |  |  | $ | 34,020 |  |  | $ | 66,113 |  |  | $ | 271,634 |  |  |  |  |  |  |  |  |  |
Earnings (Loss) Before Income Tax |  |  | $ | 153,240 |  |  | $ | (5,384) |  |  | $ | 488,866 |  |  | $ | 636,722 |  |  |  |  |  |  |  |  |  |
Segment Assets |  |  | $ | 6,589,145 |  |  | $ | 949,438 |  |  | $ | 993,272 |  |  | $ | 8,531,855 |  |  |  |  |  |  |  |  |  | (C)
Depreciation, Depletion and Amortization |  |  | $ | 86,816 |  |  | $ | 12,586 |  |  | $ | 4,280 |  |  | $ | 103,682 |  |  |  |  |  |  |  |  |  |
Capital Expenditures |  |  | $ | 186,285 |  |  | $ | 7,630 |  |  | $ | 2,070 |  |  | $ | 195,985 |  |  |  |  |  |  |  |  |  |

(A) Included in Natural Gas, NGLs and Oil Revenue are sales of $36,511 to Citadel Energy Marketing LLC, and $31,648 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(B) Includes midstream revenue of $17,027 and equity in earnings of unconsolidated affiliates of $1,334 for Shale and Other, respectively. Other also includes sales of environmental attributes of $7,986.
(C) Other includes investments in unconsolidated equity affiliates of $13,162.
Industry segment results for the three months ended June 30, 2022 are:

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

(D) Included in Natural Gas, NGLs and Oil Revenue are sales of $117,460 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(E) Includes midstream revenue of $17,990 and equity in earnings of unconsolidated affiliates of $1,377 for Shale and Other, respectively.
(F) Other includes investments in unconsolidated equity affiliates of $14,978.
Industry segment results for the six months ended June 30, 2023 are:

|  |  | Shale |  | Coalbed Methane |  | Other |  | Consolidated |  |  |  |  |  |  |  |  |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 641,390 |  |  | $ | 70,670 |  |  | $ | 640 |  |  | $ | 712,700 |  |  |  |  |  |  |  |  |  | (G)
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 46,167 |  |  | 46,167 |  |  |  |  |  |  |  |  |  |
Gain on Commodity Derivative Instruments |  |  | 17,186 |  |  | 1,331 |  |  | 1,286,122 |  |  | 1,304,639 |  |  |  |  |  |  |  |  |  |
Other Revenue and Operating Income |  |  | 33,780 |  |  | — |  |  | 18,390 |  |  | 52,170 |  |  |  |  |  |  |  |  |  | (H)
Total Revenue and Other Operating Income |  |  | $ | 692,356 |  |  | $ | 72,001 |  |  | $ | 1,351,319 |  |  | $ | 2,115,676 |  |  |  |  |  |  |  |  |  |
Total Operating Expense |  |  | $ | 359,618 |  |  | $ | 70,440 |  |  | $ | 162,173 |  |  | $ | 592,231 |  |  |  |  |  |  |  |  |  |
Earnings Before Income Tax |  |  | $ | 332,738 |  |  | $ | 1,561 |  |  | $ | 1,230,379 |  |  | $ | 1,564,678 |  |  |  |  |  |  |  |  |  |
Segment Assets |  |  | $ | 6,589,145 |  |  | $ | 949,438 |  |  | $ | 993,272 |  |  | $ | 8,531,855 |  |  |  |  |  |  |  |  |  | (I)
Depreciation, Depletion and Amortization |  |  | $ | 174,927 |  |  | $ | 25,032 |  |  | $ | 8,945 |  |  | $ | 208,904 |  |  |  |  |  |  |  |  |  |
Capital Expenditures |  |  | $ | 345,634 |  |  | $ | 17,089 |  |  | $ | 3,290 |  |  | $ | 366,013 |  |  |  |  |  |  |  |  |  |

(G) Included in Natural Gas, NGLs and Oil Revenue are sales of $86,749 to Direct Energy Business Marketing LLC, and $81,429 to Citadel Energy Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(H) Includes midstream revenue of $33,780 and equity in earnings of unconsolidated affiliates of $1,448 for Shale and Other, respectively. Other also includes sales of environmental attributes of $7,986.
(I) Other includes investments in unconsolidated equity affiliates of $13,162.
27

Industry segment results for the six months ended June 30, 2022 are:

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

(J) Included in Natural Gas, NGLs and Oil Revenue are sales of $213,299 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(K) Includes midstream revenue of $35,647 and equity in earnings of unconsolidated affiliates of $2,177 for Shale and Other, respectively.
(L) Other includes investments in unconsolidated equity affiliates of $14,978.
Reconciliation of Segment Information to Consolidated Amounts:
Revenue and Other Operating Income (Loss)

| For the Three Months Ended June 30, |  | For the Six Months Ended June 30,
2023 |  | 2022 |  | 2023 |  | 2022
Total Segment Revenue from Contracts with External Customers | $ | 283,443 |  |  | $ | 1,067,948 |  |  | $ | 792,647 |  |  | $ | 1,876,070 |
Gain (Loss) on Commodity Derivative Instruments | 542,472 |  |  | (652,643) |  |  | 1,304,639 |  |  | (2,379,036) |
Other Operating Income | 13,785 |  |  | 5,113 |  |  | 18,390 |  |  | 10,286 |
Total Consolidated Revenue and Other Operating Income (Loss) | $ | 839,700 |  |  | $ | 420,418 |  |  | $ | 2,115,676 |  |  | $ | (492,680) |

NOTE 15—STOCK REPURCHASE:
On January 26, 2021, the Company’s Board of Directors approved an increase in the aggregate amount of the previous $750,000 stock repurchase program plan to $900,000, and on October 25, 2021, the Board of Directors approved an additional increase in the aggregate amount of the stock repurchase program plan to $1,900,000. As of June 30, 2023 the amount available under the stock repurchase program is $291,002, and is not subject to an expiration date. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans.
During the six months ended June 30, 2023, 9,747,408 shares were repurchased and retired at an average price of $15.98 per share for a total cost of $157,302, which includes the one-percent excise tax under the Inflation Reduction Act of 2022. During the six months ended June 30, 2022, 12,912,070 shares were repurchased and retired at an average price of $17.09 per share for a total cost of $220,968.
On July 25, 2023, the Company’s Board of Directors approved a $1,000,000 increase to its existing stock repurchase program. As of July 25, 2023, this approval increased the dollar amount of common stock currently available to be repurchased under the Company’s existing stock repurchase program to approximately $1,268,209, which is not subject to a termination date or expiration date.
28

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CNX.
As of June 30, 2023 and December 31, 2022, CNX purchased goods and services related to capital projects in the amount of $38,792 and $56,052, respectively, which are included in accounts payable.
The following table shows cash paid:

| For the Six Months Ended June 30,
| 2023 |  | 2022
Interest (Net of Amounts Capitalized) | $ | 46,053 |  |  | $ | 62,751 |
Income Taxes | $ | 6,050 |  |  | $ | — |

NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:
CNX has reviewed all recently issued, but not yet effective, accounting pronouncements and does not believe any of these pronouncements will have a material impact on the Company.
29

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this Form 10-Q. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward-looking statements that are based on the current views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see "Part I. Item 1A. Risk Factors" and the section entitled "Forward-Looking Statements" contained in our Annual Report on Form 10-K for the year ended December 31, 2022, which we filed with the SEC on February 9, 2023. CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
General
CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations. Examples include the conflict between Russia and Ukraine and the recent announcement by the Organization of the Petroleum Exporting Countries (OPEC) to cut production, both of which have had an impact on global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
Natural gas, NGL, and Oil Pricing
Prices for natural gas, NGLs and oil that CNX produces significantly impact revenue and cash flows. In the current economic environment, CNX expects that commodity prices for some or all of the commodities we produce will remain volatile. 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 as well as financial hedges. However, this market volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Inflation
Heightened levels of inflation, primarily related to steel, diesel fuel and labor, continue to present risk for CNX and the broader natural gas industry. CNX experienced higher capital costs from inflation in the six months ended June 30, 2023. If inflation continues at its current levels or increases further for any extended period of time, and CNX is unable to successfully mitigate the impact, our costs could increase further, having a greater impact on our financial position. Rising interest rates could also increase our borrowing costs on new debt and could affect the fair value of our investments. CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset cost increases from inflation.
Hedging Update
Total hedged natural gas production in the third quarter of 2023 is 114.3 Bcf. CNX's annual gas hedge position is shown in the table below:

|  | 2023 |  | 2024
Volumes Hedged (Bcf), as of 7/6/23 |  | 432.6(1) |  | 411.1 |

1 Includes actual settlements of 211.7 Bcf.
CNX's hedged gas volumes include a combination of NYMEX financial hedges, index (NYMEX and basis) financial hedges, and physical fixed price sales. In addition, to protect the NYMEX hedge volumes from basis exposure, CNX enters into basis-only financial hedges and physical sales with fixed basis at certain sales points. See Quantitative and Qualitative Disclosures About Market Risk in Item 3 of this Form 10-Q for additional information.
30

Results of Operations - Three Months Ended June 30, 2023 Compared with Three Months Ended June 30, 2022
Net Income
CNX reported net income of $475 million, or earnings per diluted share of $2.47, for the three months ended June 30, 2023, compared to net income of $33 million, or earnings per diluted share of $0.15, for the three months ended June 30, 2022.
Included in the earnings for the three months ended June 30, 2023 was an unrealized gain on commodity derivative instruments of $463 million and a net gain on asset sales and abandonments of $106 million. Included in the earnings for the three months ended June 30, 2022 was an unrealized loss on commodity derivative instruments of $122 million and a net gain on asset sales and abandonments of $6 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the gain on asset sales and abandonments.
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 14 – Segment Information in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Non-GAAP Financial Measures Reconciliation

| For the Three Months Ended June 30,
(Dollars in millions) | 2023 | 2022
Total Revenue and Other Operating Income | $ | 840 |  |  | $ | 420 |
Add (Deduct): |  |  |
Purchased Gas Revenue | (9) |  |  | (46) |
Unrealized (Gain) Loss on Commodity Derivative Instruments | (463) |  |  | 122 |
Other Revenue and Operating Income | (31) |  |  | (23) |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | $ | 337 |  |  | $ | 473 |
Total Operating Expense | $ | 272 |  |  | $ | 330 |
Add (Deduct): |  |  |
Depreciation, Depletion and Amortization (DD&A) - Corporate | (3) |  |  | (2) |
Exploration and Production Related Other Costs | (2) |  |  | (5) |
Purchased Gas Costs | (9) |  |  | (46) |
Selling, General and Administrative Costs | (30) |  |  | (30) |
Other Operating Expense | (21) |  |  | (21) |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1 | $ | 207 |  |  | $ | 226 |

1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
31

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

| For the Three Months Ended June 30,
| 2023 |  | 2022 |  | Variance
| in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe
Total Sales Volumes (Bcfe)* |  |  | 134.2 |  |  |  | 142.3 |  |  |  | (8.1) |
Natural Gas, NGL and Oil Revenue | $ | 257 |  |  | $ | 1.87 |  |  | $ | 1,003 |  |  | $ | 7.30 |  |  | $ | (746) |  |  | $ | (5.43) |
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement | 80 |  |  | 0.64 |  |  | (530) |  |  | (3.98) |  |  | 610 |  |  | 4.62 |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | 337 |  |  | 2.51 |  |  | 473 |  |  | 3.32 |  |  | (136) |  |  | (0.81) |
Lease Operating Expense | 13 |  |  | 0.10 |  |  | 14 |  |  | 0.10 |  |  | (1) |  |  | — |
Production, Ad Valorem, and Other Fees | 5 |  |  | 0.04 |  |  | 10 |  |  | 0.07 |  |  | (5) |  |  | (0.03) |
Transportation, Gathering and Compression | 88 |  |  | 0.65 |  |  | 88 |  |  | 0.62 |  |  | — |  |  | 0.03 |
Depreciation, Depletion and Amortization (DD&A) | 101 |  |  | 0.75 |  |  | 114 |  |  | 0.79 |  |  | (13) |  |  | (0.04) |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure | 207 |  |  | 1.54 |  |  | 226 |  |  | 1.58 |  |  | (19) |  |  | (0.04) |
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure | $ | 130 |  |  | $ | 0.97 |  |  | $ | 247 |  |  | $ | 1.74 |  |  | $ | (117) |  |  | $ | (0.77) |

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
The 8.1 Bcfe decrease in total sales volumes in the period-to-period comparison was primarily due to normal production declines and the timing of when new wells were turned-in-line after the 2022 period. There was also an approximate 3.0 Bcfe reduction in volumes related to the sale of various non-operated oil and gas assets (See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).
Changes in the average costs per Mcfe were primarily related to the following items:
•Production, ad valorem and other fees decreased on a per unit basis primarily due to decreased realized prices on natural gas.
•Transportation, gathering and compression increased on a per unit basis primarily due to an increase in repairs and maintenance expense and electrical compression expense and the overall decrease in volumes. The increase was offset in part by a transportation refund received in connection with an interstate pipeline rate case settlement.
•Depreciation, depletion and amortization expense decreased on a per unit basis due to a lower annual depletion rate primarily resulting from low-cost reserve additions from development during the 2022 period.
32

Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:

|  | For the Three Months Ended June 30,
in thousands (unless noted) |  | 2023 |  | 2022 |  | Variance |  | Percent Change
LIQUIDS |  |  |  |  |  |  |  |
NGL: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 9,659 |  |  | 8,845 |  |  | 814 |  |  | 9.2 | %
Sales Volume (Mbbls) |  | 1,610 |  |  | 1,474 |  |  | 136 |  |  | 9.2 | %
Gross Price ($/Bbl) |  | $ | 19.08 |  |  | $ | 43.26 |  |  | $ | (24.18) |  |  | (55.9) | %
Gross NGL Revenue |  | $ | 30,763 |  |  | $ | 63,774 |  |  | $ | (33,011) |  |  | (51.8) | %
Oil/Condensate: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 291 |  |  | 343 |  |  | (52) |  |  | (15.2) | %
Sales Volume (Mbbls) |  | 49 |  |  | 57 |  |  | (8) |  |  | (14.0) | %
Gross Price ($/Bbl) |  | $ | 63.42 |  |  | $ | 96.24 |  |  | $ | (32.82) |  |  | (34.1) | %
Gross Oil/Condensate Revenue |  | $ | 3,076 |  |  | $ | 5,505 |  |  | $ | (2,429) |  |  | (44.1) | %
NATURAL GAS |  |  |  |  |  |  |  |
Sales Volume (MMcf) |  | 124,207 |  |  | 133,143 |  |  | (8,936) |  |  | (6.7) | %
Sales Price ($/Mcf) |  | $ | 1.80 |  |  | $ | 7.02 |  |  | $ | (5.22) |  |  | (74.4) | %
Gross Natural Gas Revenue |  | $ | 223,222 |  |  | $ | 934,127 |  |  | $ | (710,905) |  |  | (76.1) | %
Hedging Impact ($/Mcf) |  | $ | 0.64 |  |  | $ | (3.98) |  |  | $ | 4.62 |  |  | 116.1 | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement |  | $ | 79,559 |  |  | $ | (530,391) |  |  | $ | 609,950 |  |  | 115.0 | %

The decrease in gross revenue was primarily the result of the $5.22 per Mcf decrease in natural gas prices, when excluding the impact of hedging, the 8.1 Bcfe decrease in sales volumes, and the $24.18 per Bbl decrease in NGL prices. These decreases were offset, in-part, by the impact of the change in the realized gain (loss) on commodity derivative instruments - cash settlement related to the Company's hedging program.
33

SEGMENT ANALYSIS for the three months ended June 30, 2023 compared to the three months ended June 30, 2022:

| For the Three Months Ended |  | Difference to Three Months Ended
| June 30, 2023 |  | June 30, 2022
(in millions) | Shale |  | CBM |  | Other |  | Total |  | Shale |  | CBM |  | Other |  | Total
Natural Gas, NGLs and Oil Revenue | $ | 234 |  |  | $ | 23 |  |  | $ | — |  |  | $ | 257 |  |  | $ | (689) |  |  | $ | (56) |  |  | $ | (1) |  |  | $ | (746) |
Gain on Commodity Derivative Instruments | 74 |  |  | 6 |  |  | 463 |  |  | 543 |  |  | 563 |  |  | 47 |  |  | 585 |  |  | 1,195 |
Purchased Gas Revenue | — |  |  | — |  |  | 9 |  |  | 9 |  |  | — |  |  | — |  |  | (37) |  |  | (37) |
Other Revenue and Operating Income | 17 |  |  | — |  |  | 14 |  |  | 31 |  |  | (1) |  |  | — |  |  | 9 |  |  | 8 |
Total Revenue and Other Operating Income | 325 |  |  | 29 |  |  | 486 |  |  | 840 |  |  | (127) |  |  | (9) |  |  | 556 |  |  | 420 |
Lease Operating Expense | 9 |  |  | 4 |  |  | — |  |  | 13 |  |  | (1) |  |  | — |  |  | — |  |  | (1) |
Production, Ad Valorem, and Other Fees | 5 |  |  | — |  |  | — |  |  | 5 |  |  | (3) |  |  | (2) |  |  | — |  |  | (5) |
Transportation, Gathering and Compression | 71 |  |  | 17 |  |  | — |  |  | 88 |  |  | (5) |  |  | 5 |  |  | — |  |  | — |
Depreciation, Depletion and Amortization | 87 |  |  | 13 |  |  | 4 |  |  | 104 |  |  | (9) |  |  | — |  |  | (3) |  |  | (12) |
Exploration and Production Related Other Costs | — |  |  | — |  |  | 2 |  |  | 2 |  |  | — |  |  | — |  |  | (3) |  |  | (3) |
Purchased Gas Costs | — |  |  | — |  |  | 9 |  |  | 9 |  |  | — |  |  | — |  |  | (37) |  |  | (37) |
Selling, General and Administrative Costs | — |  |  | — |  |  | 30 |  |  | 30 |  |  | — |  |  | — |  |  | — |  |  | — |
Other Operating Expense | — |  |  | — |  |  | 21 |  |  | 21 |  |  | — |  |  | — |  |  | — |  |  | — |
Total Operating Expense | 172 |  |  | 34 |  |  | 66 |  |  | 272 |  |  | (18) |  |  | 3 |  |  | (43) |  |  | (58) |
Other Expense | — |  |  | — |  |  | 2 |  |  | 2 |  |  | — |  |  | — |  |  | (3) |  |  | (3) |
Gain on Asset Sales and Abandonments, net | — |  |  | — |  |  | (106) |  |  | (106) |  |  | — |  |  | — |  |  | (100) |  |  | (100) |
Loss on Debt Extinguishment | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (13) |  |  | (13) |
Interest Expense | — |  |  | — |  |  | 35 |  |  | 35 |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Total Other Expense | — |  |  | — |  |  | (69) |  |  | (69) |  |  | — |  |  | — |  |  | (112) |  |  | (112) |
Total Costs and Expenses | 172 |  |  | 34 |  |  | (3) |  |  | 203 |  |  | (18) |  |  | 3 |  |  | (155) |  |  | (170) |
Earnings (Loss) Before Income Tax | $ | 153 |  |  | $ | (5) |  |  | $ | 489 |  |  | $ | 637 |  |  | $ | (109) |  |  | $ | (12) |  |  | $ | 711 |  |  | $ | 590 |

34

SHALE SEGMENT
The Shale segment had earnings before income tax of $153 million for the three months ended June 30, 2023 compared to earnings before income tax of $262 million for the three months ended June 30, 2022.

| For the Three Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
Shale Gas Sales Volumes (Bcf) | 114.0 |  |  | 122.1 |  |  | (8.1) |  |  | (6.6) | %
NGLs Sales Volumes (Bcfe)* | 9.7 |  |  | 8.8 |  |  | 0.9 |  |  | 10.2 | %
Oil/Condensate Sales Volumes (Bcfe)* | 0.3 |  |  | 0.3 |  |  | — |  |  | — | %
Total Shale Sales Volumes (Bcfe)* | 124.0 |  |  | 131.2 |  |  | (7.2) |  |  | (5.5) | %
Average Sales Price - Natural Gas (per Mcf) | $ | 1.76 |  |  | $ | 7.00 |  |  | $ | (5.24) |  |  | (74.9) | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | 0.64 |  |  | $ | (4.01) |  |  | $ | 4.65 |  |  | 116.0 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 3.18 |  |  | $ | 7.21 |  |  | $ | (4.03) |  |  | (55.9) | %
Average Sales Price - Oil/Condensate (per Mcfe)* | $ | 10.54 |  |  | $ | 16.03 |  |  | $ | (5.49) |  |  | (34.2) | %
Total Average Shale Sales Price (per Mcfe) | $ | 2.48 |  |  | $ | 3.31 |  |  | $ | (0.83) |  |  | (25.1) | %
Average Shale Lease Operating Expenses (per Mcfe) | 0.07 |  |  | 0.08 |  |  | (0.01) |  |  | (12.5) | %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) | 0.04 |  |  | 0.05 |  |  | (0.01) |  |  | (20.0) | %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe) | 0.57 |  |  | 0.58 |  |  | (0.01) |  |  | (1.7) | %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.70 |  |  | 0.74 |  |  | (0.04) |  |  | (5.4) | %
Total Average Shale Production Costs (per Mcfe) | $ | 1.38 |  |  | $ | 1.45 |  |  | $ | (0.07) |  |  | (4.8) | %
Total Average Shale Production Margin (per Mcfe) | $ | 1.10 |  |  | $ | 1.86 |  |  | $ | (0.76) |  |  | (40.9) | %

* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGL, condensate, and natural gas prices.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $234 million for the three months ended June 30, 2023 compared to $923 million for the three months ended June 30, 2022. The $689 million decrease was due primarily to a 74.9% decrease in the average sales price for natural gas, a 5.5% decrease in total Shale sales volumes and a 55.9% decrease in the average sales price of NGLs. The decrease in total Shale volumes was primarily due to normal production declines and the timing of when new wells were turned-in-line after the 2022 period. There was also an approximate 3.0 Bcfe reduction in volumes related to the sale of non-operated Shale wells (See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).
The decrease in total average Shale sales price was primarily due to a $5.24 per Mcf decrease in average gas sales price and a $4.03 per Mcfe decrease in the average NGL sales price. These decreases were offset in part by a $4.65 per Mcf change in the realized gain (loss) on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 103.9 Bcf of the Company's produced Shale gas sales volumes for the three months ended June 30, 2023 at an average gain of $0.70 per Mcf hedged. For the three months ended June 30, 2022, these financial hedges represented approximately 104.6 Bcf at an average loss of $4.68 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $172 million for the three months ended June 30, 2023 compared to $190 million for the three months ended June 30, 2022. The decreases in total dollars and unit costs for the Shale segment were due to the following items:
•Shale lease operating expenses were $9 million for the three months ended June 30, 2023 compared to $10 million for the three months ended June 30, 2022. The decrease in total dollars was primarily due to a decrease in water disposal costs.
•Shale production, ad valorem and other fees were $5 million for the three months ended June 30, 2023 compared to $8 million for the three months ended June 30, 2022. The decrease in total dollars was primarily due to decreased realized prices on natural gas and the decrease in total Shale sales volumes.
35

•Shale transportation, gathering and compression costs were $71 million for the three months ended June 30, 2023 compared to $76 million for the three months ended June 30, 2022. The decrease in total dollars was primarily due to a transportation refund received in the current period in connection with an interstate pipeline rate case settlement. The decrease was offset, in part, by an increase in repairs and maintenance expense and electrical compression expense. On a per unit basis, the decrease in total dollars was offset by the decrease in total Shale sales volumes.
•Depreciation, depletion and amortization costs attributable to the Shale segment were $87 million for the three months ended June 30, 2023 compared to $96 million for the three months ended June 30, 2022. These amounts included depletion on a units of production basis of $0.59 per Mcfe and $0.62 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a lower annual depletion rate related to low-cost reserve additions from development in the 2022 period. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering services provided to third-parties. The Shale segment had other revenue and operating income of $17 million for the three months ended June 30, 2023 compared to $18 million for the three months ended June 30, 2022. The decrease in the period-to-period comparison was primarily due to lower third-party gathering volumes due to normal production declines.
COALBED METHANE (CBM) SEGMENT
The CBM segment had a loss before income tax of $5 million for the three months ended June 30, 2023 compared to earnings before income tax of $7 million for the three months ended June 30, 2022.

| For the Three Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 10.1 |  |  | 11.0 |  |  | (0.9) |  |  | (8.2) | %
Average Sales Price - Gas (per Mcf) | $ | 2.24 |  |  | $ | 7.23 |  |  | $ | (4.99) |  |  | (69.0) | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | 0.59 |  |  | $ | (3.75) |  |  | $ | 4.34 |  |  | 115.7 | %
Total Average CBM Sales Price (per Mcf) | $ | 2.84 |  |  | $ | 3.49 |  |  | $ | (0.65) |  |  | (18.6) | %
Average CBM Lease Operating Expenses (per Mcf) | 0.44 |  |  | 0.39 |  |  | 0.05 |  |  | 12.8 | %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) | 0.05 |  |  | 0.22 |  |  | (0.17) |  |  | (77.3) | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 1.64 |  |  | 1.07 |  |  | 0.57 |  |  | 53.3 | %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.24 |  |  | 1.18 |  |  | 0.06 |  |  | 5.1 | %
Total Average CBM Production Costs (per Mcf) | $ | 3.37 |  |  | $ | 2.86 |  |  | $ | 0.51 |  |  | 17.8 | %
Total Average CBM Production Margin (per Mcf) | $ | (0.53) |  |  | $ | 0.63 |  |  | $ | (1.16) |  |  | (184.1) | %

The CBM segment had natural gas revenue of $23 million for the three months ended June 30, 2023 compared to $79 million for the three months ended June 30, 2022. The decrease was due to a 69.0% decrease in the average sales price for natural gas in the current period and an 8.2% decrease in CBM sales volumes due to normal production declines.
The total average CBM sales price decreased $0.65 per Mcf due to a $4.99 per Mcf decrease in average gas sales price, offset in part by a $4.34 per Mcf change 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 8.3 Bcf of the Company's produced CBM sales volumes for the three months ended June 30, 2023 at an average gain of $0.72 per Mcf hedged. For the three months ended June 30, 2022, these financial hedges represented approximately 8.9 Bcf at an average loss of $4.64 per Mcf hedged.
Total operating costs and expenses for the CBM segment were $34 million for the three months ended June 30, 2023 compared to $31 million for the three months ended June 30, 2022. The increases in total dollars and unit costs for the CBM segment were due to the following items:
•CBM lease operating expenses were $4 million for both the three months ended June 30, 2023 and June 30, 2022. The increase in unit costs was due to the decrease in CBM sales volumes.
36

•CBM production, ad valorem and other fees were nominal for the three months ended June 30, 2023 compared to $2 million for the three months ended June 30, 2022. The decreases in total dollars and unit costs were primarily due to decreased realized prices on natural gas.
•CBM transportation, gathering and compression costs were $17 million for the three months ended June 30, 2023 compared to $12 million for the three months ended June 30, 2022. The increases in total dollars and unit costs were primarily due to increases in repairs and maintenance expense and electrical compression expense.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $13 million for both the three months ended June 30, 2023 and June 30, 2022. These amounts included depletion on a units of production basis of $0.64 per Mcfe for both periods. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER SEGMENT
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, new technologies, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes.
The Other Segment had earnings before income tax of $489 million for the three months ended June 30, 2023 compared to a loss before income tax of $222 million for the three months ended June 30, 2022. The increase in total dollars is discussed below.

| For the Three Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
Other Gas Sales Volumes (Bcf) | 0.1 |  |  | 0.1 |  |  | — |  |  | — | %

Unrealized Gain (Loss) on Commodity Derivative Instruments
For the three months ended June 30, 2023, the Other Segment recognized an unrealized gain on commodity derivative instruments of $463 million. For the three months ended June 30, 2022, the Other Segment recognized an unrealized loss on commodity derivative instruments of $122 million. The unrealized gain or loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Purchased Gas Revenue and Costs
Purchased gas volumes represent volumes of natural gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $9 million for the three months ended June 30, 2023 compared to $46 million for the three months ended June 30, 2022. Purchased gas costs were $9 million for the three months ended June 30, 2023 compared to $46 million for the three months ended June 30, 2022. The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes and a decrease in average sales price.

| For the Three Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
Purchased Gas Sales Volumes (in Bcf) | 4.9 |  |  | 9.1 |  |  | (4.2) |  |  | (46.2) | %
Average Sales Price (per Mcf) | $ | 1.89 |  |  | $ | 5.14 |  |  | $ | (3.25) |  |  | (63.2) | %
Purchased Gas Average Cost (per Mcf) | $ | 1.78 |  |  | $ | 5.08 |  |  | $ | (3.30) |  |  | (65.0) | %

37

Other Operating Income

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Sales of Environmental Attributes | $ | 8 |  |  | $ | — |  |  | $ | 8 |  |  | 100.0 | %
Excess Firm Transportation Income | 4 |  |  | 3 |  |  | 1 |  |  | 33.3 | %
Water Income | 1 |  |  | 1 |  |  | — |  |  | — | %
Equity Income from Affiliates | 1 |  |  | 1 |  |  | — |  |  | — | %
Total Other Operating Income | $ | 14 |  |  | $ | 5 |  |  | $ | 9 |  |  | 180.0 | %

•Sales of environmental attributes, includes items such as (but are not limited to): carbon credits, air quality credits, renewable energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold.
•Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third-parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the unutilized firm transportation and processing fees in total other operating expense.
•Equity income from affiliates primarily represents CNX's share of earnings from a 50% interest in a power plant located within CNX’s CBM field. Power generated from the facility is sold into wholesale electricity markets during times of peak energy consumption. Due to the plant consuming low carbon intensity coal mine methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy Credits.
Exploration and Production Related Other Costs

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Seismic Activity | $ | — |  |  | $ | 3 |  |  | $ | (3) |  |  | (100.0) | %
Lease Expiration Costs | 1 |  |  | 1 |  |  | — |  |  | — | %
Land Rentals | 1 |  |  | 1 |  |  | — |  |  | — | %
Total Exploration and Production Related Other Costs | $ | 2 |  |  | $ | 5 |  |  | $ | (3) |  |  | (60.0) | %

•Seismic activity expense for the prior period primarily related to the acquisition of three-dimensional seismic data.
•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months.
Selling, General and Administrative ("SG&A")
SG&A costs include costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Salaries, Wages and Employee Benefits | $ | 6 |  |  | $ | 8 |  |  | $ | (2) |  |  | (25.0) | %
Contributions and Advertising | 1 |  |  | 2 |  |  | (1) |  |  | (50.0) | %
Short-Term Incentive Compensation | 3 |  |  | 3 |  |  | — |  |  | — | %
Long-Term Equity-Based Compensation (Non-Cash) | 5 |  |  | 4 |  |  | 1 |  |  | 25.0 | %
Other | 15 |  |  | 13 |  |  | 2 |  |  | 15.4 | %
Total SG&A | $ | 30 |  |  | $ | 30 |  |  | $ | — |  |  | — | %

•Salaries, wages and employee benefits decreased in the period-to-period comparison primarily due to a decrease in employee related expenses.
38

Other Operating Expense

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Unutilized Firm Transportation and Processing Fees | $ | 14 |  |  | $ | 18 |  |  | $ | (4) |  |  | (22.2) | %
Litigation Settlements | — |  |  | 2 |  |  | (2) |  |  | (100.0) | %
Insurance Expense | 1 |  |  | 1 |  |  | — |  |  | — | %
Virginia Flood Expense | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Environmental Attribute Fees | 2 |  |  | — |  |  | 2 |  |  | 100.0 | %
Other | 3 |  |  | — |  |  | 3 |  |  | 100.0 | %
Total Other Operating Expense | $ | 21 |  |  | $ | 21 |  |  | $ | — |  |  | — | %

•Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Income. The decrease in the period-to-period comparison was primarily due to a portion of a transportation refund received in connection with an interstate pipeline rate case settlement applicable to unutilized firm transportation expense.
•CNX and its subsidiaries are subject to various lawsuits and claims in the normal course of business. CNX accrues the estimated loss for these lawsuits and claims as litigation settlements when the loss is probable and can be estimated. (See Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX's 2022 Form 10-K for additional information). The decrease in litigation settlements in the period-to-period comparison was the result of various items, none of which were individually material.
•Virginia flood expense includes the continuing effort to cleanup and repair areas that were impacted by flooding that occurred in Buchanan County, Virginia in July 2022.
•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Operating Income.
•Other increased in the period-to-period comparison due to various one-time items, none of which were individually material.
Other Expense

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Right-of-Way Sales | $ | 2 |  |  | $ | — |  |  | $ | 2 |  |  | 100.0 | %
Other | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Total Other Income | $ | 3 |  |  | $ | — |  |  | $ | 3 |  |  | 100.0 | %
Other Expense |  |  |  |  |  |  |
Professional Services | $ | 1 |  |  | $ | 1 |  |  | $ | — |  |  | — | %
Bank Fees | 3 |  |  | 3 |  |  | — |  |  | — | %
Other Corporate Expense | 1 |  |  | 1 |  |  | — |  |  | — | %
Total Other Expense | $ | 5 |  |  | $ | 5 |  |  | $ | — |  |  | — | %
Total Other Expense | $ | 2 |  |  | $ | 5 |  |  | $ | (3) |  |  | (60.0) | %

39

Gain on Asset Sales and Abandonments, net
A net gain on asset sales and abandonments of $106 million was recognized in the three months ended June 30, 2023 compared to a net gain of $6 million in the three months ended June 30, 2022. The net gain recognized in the three months ended June 30, 2023 primarily relates to the sale of various non-operated oil and gas assets (See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). The net gain recognized during the three months ended June 30, 2022 primarily relates to the sale of various non-core assets (rights-of-way, surface acreage and other non-care oil and gas interests).
Loss on Debt Extinguishment
A loss on debt extinguishment of $13 million was recognized in the three months ended June 30, 2022 in connection with the purchase of a portion of the Convertible Notes due May 2026. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Interest Expense

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Total Interest Expense | $ | 35 |  |  | $ | 31 |  |  | $ | 4 |  |  | 12.9 | %

The $4 million increase in total interest expense was primarily due to slightly higher interest paid on long-term debt that was issued after the second quarter of 2022. The increase was also due to a minimal unrealized loss on interest rate swaps in the current period compared to a $2 million unrealized gain in the prior period. These increases were offset in part by lower borrowings on the revolving credit facility. See Note 12 – Derivative Instruments and Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Income Taxes

| For the Three Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Total Company Earnings Before Income Tax | $ | 637 |  |  | $ | 47 |  |  | $ | 590 |  |  | 1,255.3 | %
Income Tax Expense | $ | 162 |  |  | $ | 14 |  |  | $ | 148 |  |  | 1,057.1 | %
Effective Income Tax Rate | 25.4 | % |  | 28.9 | % |  | (3.5) | % |  |

The effective income tax rate was 25.4% for the three months ended June 30, 2023 compared to 28.9% for the three months ended June 30, 2022. The effective rate for the three months ended June 30, 2023 differs from the U.S. federal statutory rate of 21% primarily due to the impact of equity compensation, federal tax credits and state taxes primarily due to a West Virginia tax law. The effective rate for the three months ended June 30, 2022 differs from the U.S. federal statutory rate of 21% primarily due to the impact of the partial repurchase of the Convertible Notes, equity compensation and state income taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
40

Results of Operations - Six Months Ended June 30, 2023 Compared with Six Months Ended June 30, 2022
Net Income (Loss)
CNX reported net income of $1,185 million, or earnings per diluted share of $6.09, for the six months ended June 30, 2023, compared to a net loss of $890 million, or a loss per diluted share of $4.52, for the six months ended June 30, 2022.
Included in the earnings for the six months ended June 30, 2023 was an unrealized gain on commodity derivative instruments of $1,287 million and a net gain on asset sales and abandonments of $115 million. Included in the loss for the six months ended June 30, 2022 was an unrealized loss on commodity derivative instruments of $1,578 million and a net gain on asset sales and abandonments of $20 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the gain on asset sales and abandonments.
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 14 – Segment Information in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Non-GAAP Financial Measures Reconciliation

| For the Six Months Ended June 30,
(Dollars in millions) | 2023 | 2022
Total Revenue and Other Operating Income (Loss) | $ | 2,116 |  |  | $ | (493) |
Add (Deduct): |  |  |
Purchased Gas Revenue | (46) |  |  | (92) |
Unrealized (Gain) Loss on Commodity Derivative Instruments | (1,287) |  |  | 1,578 |
Other Revenue and Operating Income | (52) |  |  | (46) |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | $ | 731 |  |  | $ | 947 |
Total Operating Expense | $ | 592 |  |  | $ | 653 |
Add (Deduct): |  |  |
Depreciation, Depletion and Amortization (DD&A) - Corporate | (7) |  |  | (7) |
Exploration and Production Related Other Costs | (7) |  |  | (6) |
Purchased Gas Costs | (43) |  |  | (91) |
Selling, General and Administrative Costs | (66) |  |  | (62) |
Other Operating Expense | (36) |  |  | (32) |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1 | $ | 433 |  |  | $ | 455 |

1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
41

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

| For the Six Months Ended June 30,
| 2023 |  | 2022 |  | Variance
| in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe
Total Sales Volumes (Bcfe)* |  |  | 270.0 |  |  |  |  | 293.2 |  |  |  |  | (23.2) |
Natural Gas, NGL and Oil Revenue | $ | 713 |  |  | $ | 2.64 |  |  | $ | 1,748 |  |  | $ | 6.14 |  |  | $ | (1035) |  |  | $ | (3.50) |
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement | 18 |  |  | 0.07 |  |  | (801) |  |  | (2.91) |  |  | 819 |  |  | 2.98 |
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure | 731 |  |  | 2.71 |  |  | 947 |  |  | 3.23 |  |  | (216) |  |  | (0.52) |
Lease Operating Expense | 30 |  |  | 0.11 |  |  | 30 |  |  | 0.10 |  |  | — |  |  | 0.01 |
Production, Ad Valorem, and Other Fees | 15 |  |  | 0.05 |  |  | 20 |  |  | 0.07 |  |  | (5) |  |  | (0.02) |
Transportation, Gathering and Compression | 186 |  |  | 0.69 |  |  | 177 |  |  | 0.60 |  |  | 9 |  |  | 0.09 |
Depreciation, Depletion and Amortization (DD&A) | 202 |  |  | 0.75 |  |  | 228 |  |  | 0.78 |  |  | (26) |  |  | (0.03) |
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure | 433 |  |  | 1.60 |  |  | 455 |  |  | 1.55 |  |  | (22) |  |  | 0.05 |
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure | $ | 298 |  |  | $ | 1.11 |  |  | $ | 492 |  |  | $ | 1.68 |  |  | $ | (194) |  |  | $ | (0.57) |

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
The 23.2 Bcfe decrease in volumes in the period-to-period comparison was primarily due to various operational delays and challenges that occurred in 2022, which impacted current period production due to the timing of wells being turned-in-line. The remaining variance is primarily due to normal production declines.
Changes in the average costs per Mcfe were primarily related to the following items:
•Lease operating expense increased on a per unit basis primarily due to an increase in repair and maintenance expense and the overall decrease in volumes.
•Production, ad valorem and other fees decreased on a per unit basis primarily due to decreased realized prices on natural gas.
•Transportation, gathering and compression expense increased on a per unit basis primarily due to increased processing costs, increased electrical compression expense, increased repairs and maintenance expense and lower volumes.
•Depreciation, depletion and amortization expense decreased on a per unit basis due to a lower annual depletion rate primarily resulting from low-cost reserve additions from development during the 2022 period.
42

Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:

|  | For the Six Months Ended June 30,
in thousands (unless noted) |  | 2023 |  | 2022 |  | Variance |  | Percent Change
LIQUIDS |  |  |  |  |  |  |  |
NGL: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 19,719 |  |  | 17,351 |  |  | 2,368 |  |  | 13.6 | %
Sales Volume (Mbbls) |  | 3,287 |  |  | 2,892 |  |  | 395 |  |  | 13.7 | %
Gross Price ($/Bbl) |  | $ | 23.40 |  |  | $ | 44.46 |  |  | $ | (21.06) |  |  | (47.4) | %
Gross NGL Revenue |  | $ | 76,819 |  |  | $ | 128,570 |  |  | $ | (51,751) |  |  | (40.3) | %
Oil/Condensate: |  |  |  |  |  |  |  |
Sales Volume (MMcfe) |  | 806 |  |  | 698 |  |  | 108 |  |  | 15.5 | %
Sales Volume (Mbbls) |  | 134 |  |  | 116 |  |  | 18 |  |  | 15.5 | %
Gross Price ($/Bbl) |  | $ | 65.88 |  |  | $ | 86.46 |  |  | $ | (20.58) |  |  | (23.8) | %
Gross Oil/Condensate Revenue |  | $ | 8,849 |  |  | $ | 10,060 |  |  | $ | (1,211) |  |  | (12.0) | %
NATURAL GAS |  |  |  |  |  |  |  |
Sales Volume (MMcf) |  | 249,498 |  |  | 275,144 |  |  | (25,646) |  |  | (9.3) | %
Sales Price ($/Mcf) |  | $ | 2.51 |  |  | $ | 5.85 |  |  | $ | (3.34) |  |  | (57.1) | %
Gross Natural Gas Revenue |  | $ | 627,032 |  |  | $ | 1,609,401 |  |  | $ | (982,369) |  |  | (61.0) | %
Hedging Impact ($/Mcf) |  | $ | 0.07 |  |  | $ | (2.91) |  |  | $ | 2.98 |  |  | 102.4 | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement |  | $ | 18,527 |  |  | $ | (801,233) |  |  | $ | 819,760 |  |  | 102.3 | %

The decrease in gross revenue was primarily the result of the $3.34 per Mcf decrease in natural gas prices, when excluding the impact of hedging, the 23.2 Bcfe decrease in sales volumes and the $21.06 per Bbl decrease in NGL prices. These decreases were offset, in-part, by the impact of the change in the gain (loss) on commodity derivative instruments - cash settlement related to the Company's hedging program.
43

SEGMENT ANALYSIS for the six months ended June 30, 2023 compared to the six months ended June 30, 2022:

| For the Six Months Ended |  | Difference to Six Months Ended
| June 30, 2023 |  | June 30, 2022
(in millions) | Shale |  | CBM |  | Other |  | Total |  | Shale |  | CBM |  | Other |  | Total
Natural Gas, NGLs and Oil Revenue | $ | 641 |  |  | $ | 71 |  |  | $ | 1 |  |  | $ | 713 |  |  | $ | (963) |  |  | $ | (72) |  |  | $ | — |  |  | $ | (1,035) |
Gain on Commodity Derivative Instruments | 17 |  |  | 1 |  |  | 1,287 |  |  | 1,305 |  |  | 755 |  |  | 64 |  |  | 2,865 |  |  | 3,684 |
Purchased Gas Revenue | — |  |  | — |  |  | 46 |  |  | 46 |  |  | — |  |  | — |  |  | (46) |  |  | (46) |
Other Revenue and Operating Income | 34 |  |  | — |  |  | 18 |  |  | 52 |  |  | (1) |  |  | — |  |  | 7 |  |  | 6 |
Total Revenue and Other Operating Income | 692 |  |  | 72 |  |  | 1,352 |  |  | 2,116 |  |  | (209) |  |  | (8) |  |  | 2,826 |  |  | 2,609 |
Lease Operating Expense | 20 |  |  | 10 |  |  | — |  |  | 30 |  |  | (2) |  |  | 2 |  |  | — |  |  | — |
Production, Ad Valorem, and Other Fees | 12 |  |  | 3 |  |  | — |  |  | 15 |  |  | (3) |  |  | (2) |  |  | — |  |  | (5) |
Transportation, Gathering and Compression | 153 |  |  | 32 |  |  | 1 |  |  | 186 |  |  | — |  |  | 9 |  |  | — |  |  | 9 |
Depreciation, Depletion and Amortization | 174 |  |  | 25 |  |  | 10 |  |  | 209 |  |  | (23) |  |  | (1) |  |  | (2) |  |  | (26) |
Exploration and Production Related Other Costs | — |  |  | — |  |  | 7 |  |  | 7 |  |  | — |  |  | — |  |  | 1 |  |  | 1 |
Purchased Gas Costs | — |  |  | — |  |  | 43 |  |  | 43 |  |  | — |  |  | — |  |  | (48) |  |  | (48) |
Selling, General and Administrative Costs | — |  |  | — |  |  | 66 |  |  | 66 |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Other Operating Expense | — |  |  | — |  |  | 36 |  |  | 36 |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Total Operating Expense | 359 |  |  | 70 |  |  | 163 |  |  | 592 |  |  | (28) |  |  | 8 |  |  | (41) |  |  | (61) |
Other Expense | — |  |  | — |  |  | 3 |  |  | 3 |  |  | — |  |  | — |  |  | (2) |  |  | (2) |
Gain on Asset Sales and Abandonments, net | — |  |  | — |  |  | (115) |  |  | (115) |  |  | — |  |  | — |  |  | (95) |  |  | (95) |
Loss on Debt Extinguishment | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (13) |  |  | (13) |
Interest Expense | — |  |  | — |  |  | 71 |  |  | 71 |  |  | — |  |  | — |  |  | 13 |  |  | 13 |
Total Other Expense | — |  |  | — |  |  | (41) |  |  | (41) |  |  | — |  |  | — |  |  | (97) |  |  | (97) |
Total Costs and Expenses | 359 |  |  | 70 |  |  | 122 |  |  | 551 |  |  | (28) |  |  | 8 |  |  | (138) |  |  | (158) |
Earnings Before Income Tax | $ | 333 |  |  | $ | 2 |  |  | $ | 1,230 |  |  | $ | 1,565 |  |  | $ | (181) |  |  | $ | (16) |  |  | $ | 2,964 |  |  | $ | 2,767 |

44

SHALE SEGMENT
The Shale segment had earnings before income tax of $333 million for the six months ended June 30, 2023 compared to earnings before income tax of $514 million for the six months ended June 30, 2022.

| For the Six Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
Shale Gas Sales Volumes (Bcf) | 228.9 |  |  | 252.6 |  |  | (23.7) |  |  | (9.4) | %
NGLs Sales Volumes (Bcfe)* | 19.7 |  |  | 17.3 |  |  | 2.4 |  |  | 13.9 | %
Oil/Condensate Sales Volumes (Bcfe)* | 0.8 |  |  | 0.7 |  |  | 0.1 |  |  | 14.3 | %
Total Shale Sales Volumes (Bcfe)* | 249.4 |  |  | 270.6 |  |  | (21.2) |  |  | (7.8) | %
Average Sales Price - Natural Gas (per Mcf) | $ | 2.43 |  |  | $ | 5.80 |  |  | $ | (3.37) |  |  | (58.1) | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | 0.08 |  |  | $ | (2.92) |  |  | $ | 3.00 |  |  | 102.7 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 3.90 |  |  | $ | 7.41 |  |  | $ | (3.51) |  |  | (47.4) | %
Average Sales Price - Oil/Condensate (per Mcfe)* | $ | 10.96 |  |  | $ | 14.40 |  |  | $ | (3.44) |  |  | (23.9) | %
Total Average Shale Sales Price (per Mcfe) | $ | 2.64 |  |  | $ | 3.20 |  |  | $ | (0.56) |  |  | (17.5) | %
Average Shale Lease Operating Expenses (per Mcfe) | 0.08 |  |  | 0.08 |  |  | — |  |  | — | %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) | 0.05 |  |  | 0.05 |  |  | — |  |  | — | %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe) | 0.62 |  |  | 0.57 |  |  | 0.05 |  |  | 8.8 | %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.69 |  |  | 0.73 |  |  | (0.04) |  |  | (5.5) | %
Total Average Shale Production Costs (per Mcfe) | $ | 1.44 |  |  | $ | 1.43 |  |  | $ | 0.01 |  |  | 0.7 | %
Total Average Shale Production Margin (per Mcfe) | $ | 1.20 |  |  | $ | 1.77 |  |  | $ | (0.57) |  |  | (32.2) | %

* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGL, condensate, and natural gas prices.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $641 million for the six months ended June 30, 2023 compared to $1,604 million for the six months ended June 30, 2022. The $963 million decrease was due primarily to a 58.1% decrease in the average sales price for natural gas, a 7.8% decrease in total Shale sales volumes and a 47.4% decrease in the average sales price of NGLs. The decrease in total Shale sales volumes was primarily due to various operational delays and challenges that occurred in 2022, which impacted current period production due to the timing of wells being turned-in-line. The remaining variance is primarily due to normal production declines.
The decrease in total average Shale sales price was primarily due to a $3.37 per Mcf decrease in average natural gas sales price and a $3.51 per Mcfe decrease in the average NGL sales price. These decreases were offset in part by a $3.00 per Mcf change in the realized gain (loss) on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 188.3 Bcf of the Company's produced Shale gas sales volumes for the six months ended June 30, 2023 at an average gain of $0.09 per Mcf hedged. For the six months ended June 30, 2022, these financial hedges represented approximately 212.6 Bcf at an average loss of $3.47 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $359 million for the six months ended June 30, 2023 compared to $387 million for the six months ended June 30, 2022. The decrease in total dollars and increase in unit costs for the Shale segment were due to the following items:
•Shale lease operating expenses were $20 million for the six months ended June 30, 2023 compared to $22 million for the six months ended June 30, 2022. The decrease in total dollars was primarily related to a decrease in water disposal costs.
•Shale production, ad valorem and other fees were $12 million for the six months ended June 30, 2023 compared to $15 million for the six months ended June 30, 2022. The decrease in total dollars was primarily due to decreased realized prices on natural gas.
•Shale transportation, gathering and compression costs were $153 million for both the six months ended June 30, 2023 and June 30, 2022. The increase in unit costs was due to the decrease in total Shale sales volumes.
45

•Depreciation, depletion and amortization costs attributable to the Shale segment were $174 million for the six months ended June 30, 2023 compared to $197 million for the six months ended June 30, 2022. These amounts included depletion on a unit of production basis of $0.59 per Mcfe and $0.63 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a lower annual depletion rate related to low-cost reserve additions from development in the 2022 period. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering services provided to third-parties. The Shale segment had other revenue and operating income of $34 million for the six months ended June 30, 2023 compared to $35 million for the six months ended June 30, 2022. The decrease in the period-to-period comparison was primarily due to lower third-party gathering volumes due to normal production declines.
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of $2 million for the six months ended June 30, 2023 compared to earnings before income tax of $18 million for the six months ended June 30, 2022.

| For the Six Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 20.5 |  |  | 22.5 |  |  | (2.0) |  |  | (8.9) | %
Average Sales Price - Natural Gas (per Mcf) | $ | 3.45 |  |  | $ | 6.37 |  |  | $ | (2.92) |  |  | (45.8) | %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement (per Mcf) | $ | 0.06 |  |  | $ | (2.78) |  |  | $ | 2.84 |  |  | 102.2 | %
Total Average CBM Sales Price (per Mcf) | $ | 3.52 |  |  | $ | 3.58 |  |  | $ | (0.06) |  |  | (1.7) | %
Average CBM Lease Operating Expenses (per Mcf) | 0.49 |  |  | 0.36 |  |  | 0.13 |  |  | 36.1 | %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) | 0.17 |  |  | 0.23 |  |  | (0.06) |  |  | (26.1) | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 1.56 |  |  | 1.01 |  |  | 0.55 |  |  | 54.5 | %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.22 |  |  | 1.16 |  |  | 0.06 |  |  | 5.2 | %
Total Average CBM Production Costs (per Mcf) | $ | 3.44 |  |  | $ | 2.76 |  |  | $ | 0.68 |  |  | 24.6 | %
Total Average CBM Production Margin (per Mcf) | $ | 0.08 |  |  | $ | 0.82 |  |  | $ | (0.74) |  |  | (90.2) | %

The CBM segment had natural gas revenue of $71 million for the six months ended June 30, 2023 compared to $143 million for the six months ended June 30, 2022. The $72 million decrease was due to a 45.8% decrease in the average sales price for natural gas in the current period and an 8.9% decrease in CBM sales volumes due to normal production declines.
The total average CBM sales price decreased $0.06 per Mcf due to a $2.92 per Mcf decrease in average natural gas sales price, offset in part by a $2.84 per Mcf change 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 15.6 Bcf of the Company's produced CBM sales volumes for the six months ended June 30, 2023 at an average gain of $0.09 per Mcf hedged. For the six months ended June 30, 2022, these financial hedges represented approximately 18.0 Bcf at an average loss of $3.46 per Mcf hedged.
Total operating costs and expenses for the CBM segment were $70 million for the six months ended June 30, 2023 compared to $62 million for the six months ended June 30, 2022. The increases in total dollars and unit costs for the CBM segment were due to the following items:
•CBM lease operating expenses were $10 million for the six months ended June 30, 2023 compared to $8 million for the six months ended June 30, 2022. The increases in total dollars and unit costs were primarily due to increases in repairs and maintenance expense.
•CBM production, ad valorem and other fees were $3 million for the six months ended June 30, 2023 compared to $5 million for the six months ended June 30, 2022. The decreases in total dollars and unit costs were primarily due to decreased realized prices on natural gas.
46

•CBM transportation, gathering and compression costs were $32 million for the six months ended June 30, 2023 compared to $23 million for the six months ended June 30, 2022. The increases in total dollars and unit cost were primarily due to an increase in repairs and maintenance expense and electrical compression expense.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $25 million for the six months ended June 30, 2023 compared to $26 million for the six months ended June 30, 2022. These amounts included depletion on a unit of production basis of $0.64 per Mcfe for both periods. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER SEGMENT
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, new technologies, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes.
The Other Segment had earnings before income tax of $1,230 million for the six months ended June 30, 2023 compared to a loss before income tax of $1,734 million for the six months ended June 30, 2022. The increase in total dollars is discussed below.

| For the Six Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
Other Gas Sales Volumes (Bcf) | 0.1 |  |  | 0.1 |  |  | — |  |  | — | %

Unrealized Gain (Loss) on Commodity Derivative Instruments
For the six months ended June 30, 2023, the Other Segment recognized an unrealized gain on commodity derivative instruments of $1,287 million as well as cash settlements received of $1 million. For the six months ended June 30, 2022, the Other Segment recognized an unrealized loss on commodity derivative instruments of $1,578 million. The unrealized gain or loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Purchased Gas Revenue and Costs
Purchased gas volumes represent volumes of natural gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $46 million for the six months ended June 30, 2023 compared to $92 million for the six months ended June 30, 2022. Purchased gas costs were $43 million for the six months ended June 30, 2023 compared to $91 million for the six months ended June 30, 2022. The period-to-period decrease in purchased gas revenue was due to a decrease in average sales price, offset in part by an increase in purchased gas sales volumes.

| For the Six Months Ended June 30,
| 2023 |  | 2022 |  | Variance |  | Percent Change
Purchased Gas Sales Volumes (in Bcf) | 17.8 |  |  | 15.3 |  |  | 2.5 |  |  | 16.3 | %
Average Sales Price (per Mcf) | $ | 2.59 |  |  | $ | 6.03 |  |  | $ | (3.44) |  |  | (57.0) | %
Purchased Gas Average Cost (per Mcf) | $ | 2.42 |  |  | $ | 5.93 |  |  | $ | (3.51) |  |  | (59.2) | %

Other Operating Income

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Sales of Environmental Attributes | $ | 8 |  |  | $ | — |  |  | $ | 8 |  |  | 100.0 | %
Excess Firm Transportation Income | 5 |  |  | 6 |  |  | (1) |  |  | (16.7) | %
Water Income | 2 |  |  | 3 |  |  | (1) |  |  | (33.3) | %
Equity Income from Affiliates | 1 |  |  | 2 |  |  | (1) |  |  | (50.0) | %
Other | 2 |  |  | — |  |  | 2 |  |  | 100.0 | %
Total Other Operating Income | $ | 18 |  |  | $ | 11 |  |  | $ | 7 |  |  | 63.6 | %

47

•Sales of environmental attributes, includes items such as (but are not limited to): carbon credits, air quality credits, renewable energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold.
•Excess firm transportation income represents revenue from the sale of excess firm transportation capacity to third parties. The Company obtains firm pipeline transportation capacity to enable gas production to flow uninterrupted as sales volumes increase. In order to minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in Total Other Operating Expense.
•Equity income from affiliates primarily represents CNX’s share of earnings from a 50% interest in a power plant located within CNX’s CBM field. Power generated from the facility is sold into wholesale electricity markets during times of peak energy consumption. Due to the plant consuming coal mine methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy Credits.
Exploration and Production Related Other Costs

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Lease Expiration Costs | $ | 4 |  |  | $ | 1 |  |  | $ | 3 |  |  | 300.0 | %
Permitting Expense | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Land Rentals | 2 |  |  | 2 |  |  | — |  |  | — | %
Seismic Activity | — |  |  | 3 |  |  | (3) |  |  | (100.0) | %
Total Exploration and Production Related Other Costs | $ | 7 |  |  | $ | 6 |  |  | $ | 1 |  |  | 16.7 | %

•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months. The increase in the six months ended June 30, 2023 was primarily due to an increase in the number of leases that were allowed to expire.
•Seismic activity expense for the prior period primarily related to the acquisition of three-dimensional seismic.
Selling, General and Administrative ("SG&A")
SG&A costs include costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Long-term Equity-Based Compensation (Non-Cash) | $ | 13 |  |  | $ | 11 |  |  | $ | 2 |  |  | 18.2 | %
Salaries, Wages and Employee Benefits | 16 |  |  | 15 |  |  | 1 |  |  | 6.7 | %
Short-term Incentive Compensation | 6 |  |  | 7 |  |  | (1) |  |  | (14.3) | %
Contributions and Advertising | 3 |  |  | 4 |  |  | (1) |  |  | (25.0) | %
Other | 28 |  |  | 25 |  |  | 3 |  |  | 12.0 | %
Total SG&A | $ | 66 |  |  | $ | 62 |  |  | $ | 4 |  |  | 6.5 | %

•Long-term equity-based compensation increased in the period-to-period comparison primarily due to an acceleration of expense related to employee departures.
•Other increased primarily due to an increase in insurance expense and various one-time items, none of which were individually material.
48

Other Operating Expense

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Environmental Attribute Fees | $ | 2 |  |  | $ | — |  |  | $ | 2 |  |  | 100.0 | %
Idle Equipment and Service Charges | 2 |  |  | — |  |  | 2 |  |  | 100.0 | %
Insurance Expense | 2 |  |  | 1 |  |  | 1 |  |  | 100.0 | %
Virginia Flood Expense | 1 |  |  | — |  |  | 1 |  |  | 100.0 | %
Litigation Settlements | — |  |  | 3 |  |  | (3) |  |  | (100.0) | %
Unutilized Firm Transportation and Processing Fees | 23 |  |  | 27 |  |  | (4) |  |  | (14.8) | %
Other | 6 |  |  | 1 |  |  | 5 |  |  | 500.0 | %
Total Other Operating Expense | $ | 36 |  |  | $ | 32 |  |  | $ | 4 |  |  | 12.5 | %

•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Operating Income.
•Virginia flood expense includes the continuing effort to cleanup and repair areas that were impacted by flooding that occurred in Buchanan County, Virginia in July 2022.
•Unutilized firm transportation and processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Other Operating Income. The decrease in the period-to-period comparison was primarily due to a portion of a transportation refund received in connection with an interstate pipeline rate case settlement applicable to unutilized firm transportation expense.
•Other increased in the period-to-period comparison due to various one-time items, none of which were individually material.
Other Expense

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Right-of-Way Sales | $ | 4 |  |  | $ | 2 |  |  | $ | 2 |  |  | 100.0 | %
Other | 2 |  |  | 4 |  |  | (2) |  |  | (50.0) | %
Total Other Income | $ | 6 |  |  | $ | 6 |  |  | $ | — |  |  | — | %
Other Expense |  |  |  |  |  |  |
Professional Services | $ | 2 |  |  | $ | 3 |  |  | $ | (1) |  |  | (33.3) | %
Bank Fees | 6 |  |  | 5 |  |  | 1 |  |  | 20.0 | %
Other Corporate Expense | 1 |  |  | 3 |  |  | (2) |  |  | (66.7) | %
Total Other Expense | $ | 9 |  |  | $ | 11 |  |  | $ | (2) |  |  | (18.2) | %
Total Other Expense | $ | 3 |  |  | $ | 5 |  |  | $ | (2) |  |  | (40.0) | %

Gain on Asset Sales and Abandonments, net
A net gain on asset sales and abandonments of $115 million was recognized in the six months ended June 30, 2023 compared to a net gain of $20 million in the six months ended June 30, 2022. The net gain recognized in the six months ended June 30, 2023 primarily relates to the sale of various non-operated oil and gas assets (See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). The net gain recognized during the six months ended June 30, 2022 primarily relates to the sale of various non-core assets (rights-of-way, surface acreage and other non-care oil and gas interests).
49

Loss on Debt Extinguishment
A loss on debt extinguishment of $13 million was recognized in the six months ended June 30, 2022 in connection with the purchase of a portion of the Convertible Notes due May 2026. See Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Interest Expense

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Total Interest Expense | $ | 71 |  |  | $ | 58 |  |  | $ | 13 |  |  | 22.4 | %

The $13 million increase in total interest expense was primarily due to a $1 million unrealized loss on interest rate swaps in the current period compared to a $7 million unrealized gain in the prior period. The increase was also due to slightly higher interest paid on long-term debt that was issued after the second quarter of 2022. These increases were offset in part by lower borrowings on the revolving credit facility. See Note 12 – Derivative Instruments and Note 10 – Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Income Taxes

| For the Six Months Ended June 30,
(in millions) | 2023 |  | 2022 |  | Variance |  | Percent Change
Total Company Earnings (Loss) Before Income Tax | $ | 1,565 |  |  | $ | (1,202) |  |  | $ | 2,767 |  |  | 230.2 | %
Income Tax Expense (Benefit) | $ | 379 |  |  | $ | (312) |  |  | $ | 691 |  |  | 221.5 | %
Effective Income Tax Rate | 24.2 | % |  | 26.0 | % |  | (1.8) | % |  |

The effective income tax rate was 24.2% for the six months ended June 30, 2023 compared to 26.0% for the six months ended June 30, 2022. The effective tax rate for the six months ended June 30, 2023 differs from the U.S. federal statutory rate of 21.0% primarily due to the impact of equity compensation, federal tax credits and state taxes primarily due to a West Virginia tax law change. The effective tax rate for the six months ended June 30, 2022 differs from the U.S. federal statutory rate of 21.0% primarily due to the impact of the partial repurchase of the Convertible Notes, equity compensation and state income taxes. See Note 5 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
50

Liquidity and Capital Resources
Overview, Sources and Uses
CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CNX currently believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments, if any, and to provide required letters of credit for the current fiscal year. Nevertheless, the ability of CNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, some of which are beyond CNX’s control.
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.
CNX continuously reviews its liquidity and capital resources. If market conditions were to change, for instance due to a significant decline in commodity prices and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be reduced.
As of June 30, 2023, CNX was in compliance with all of its debt covenants. After considering the potential effect of a significant decline in commodity prices, CNX currently expects to remain in compliance with its debt covenants.
CNX frequently evaluates potential acquisitions. CNX has historically funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CNX on terms which CNX finds acceptable, or at all.
Factors that may Impact our Liquidity
•The Company’s cash on hand and access to additional liquidity. Cash and cash equivalents as of June 30, 2023 and December 31, 2022 were $22.8 million and $21.3 million, respectively.
•Accounts and notes receivable - trade as of June 30, 2023 and December 31, 2022 were $97.7 million and $348.5 million, respectively. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the prices we receive for our natural gas and NGLs and the volumes sold.
•Capital expenditures are expected to range between $625 million to $675 million for the year ended December 31, 2023. For the six months ended June 30, 2023, CNX had capital expenditures of $366.0 million. Accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring an increase in costs in the future.
•Production volumes are expected to range between 545.0 Bcfe and 555.0 Bcfe for the year ended December 31, 2023. For the six months ended June 30, 2023, CNX had production volumes of 270.0 Bcfe.
•Prices for natural gas and NGLs are volatile, and an extended decline in the prices we receive for our natural gas and NGLs will adversely affect our financial condition and cash flows.
•In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas and NGL swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of $524 million at June 30, 2023 and a net liability of $1,905 million at December 31, 2022. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q for further discussion of our commodity risk management.
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Cash Flows (in millions)

| For the Six Months Ended June 30,
| 2023 |  | 2022 |  | Change
Cash Provided by Operating Activities | $ | 447 |  |  | $ | 528 |  |  | $ | (81) |
Cash Used in Investing Activities | $ | (223) |  |  | $ | (232) |  |  | $ | 9 |
Cash Used in Financing Activities | $ | (223) |  |  | $ | (299) |  |  | $ | 76 |

Cash flows from operating activities changed in the period-to-period comparison primarily due to the following items:
•Net income increased $2,075 million in the period-to-period comparison.
•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $697 million benefit for the change in deferred income taxes, a $2,959 million net change in commodity derivative instruments, a $96 million increase in gain on asset sales and abandonments, net and a $202 million net benefit for various other changes in working capital.
Cash flows from investing activities changed in the period-to-period comparison primarily due to the following items:
•Capital expenditures increased $107 million primarily due to an increase in drilling and completions activity and an overall increase in costs related to inflation.
•Proceeds from asset sales increased $116 million primarily due to the sale of various non-operated oil and gas assets (See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).
Cash flows from financing activities changed in the period-to-period comparison primarily due to the following items:
•Proceeds from CNXM's Revolving Credit Facility Borrowings decreased $44 million and repayments of CNXM's Revolving Credit Facility Borrowings increased $13 million.
•Proceeds from CNX's Revolving Credit Facility Borrowings decreased $585 million and repayments of CNX's Revolving Credit Facility Borrowings decreased $644 million.
•In the six months ended June 30, 2022, CNX paid $27 million to repurchase $14 million of the 2026 Convertible Notes at an average price of 188.0% of the principal.
•In the six months ended June 30, 2023, CNX repurchased $159 million of its common stock on the open market compared to $212 million during the six months ended June 30, 2022.
Commitments and Significant Contractual Obligations
The following is a summary of the Company's significant contractual obligations at June 30, 2023 (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 | $ | 400 |  |  | $ | 800 |  |  | $ | 200 |  |  | $ | — |  |  | $ | 1,400 |
Gas Firm Transportation and Processing | 246,972 |  |  | 431,761 |  |  | 356,384 |  |  | 652,823 |  |  | 1,687,940 |
Long-Term Debt | — |  |  | 325,124 |  |  | 451,497 |  |  | 1,390,373 |  |  | 2,166,994 |
Interest on Long-Term Debt | 137,174 |  |  | 250,778 |  |  | 198,956 |  |  | 179,470 |  |  | 766,378 |
Finance Lease Obligations | 3,362 |  |  | 7,126 |  |  | 6,912 |  |  | 288 |  |  | 17,688 |
Interest on Finance Lease Obligations | 1,126 |  |  | 1,882 |  |  | 915 |  |  | 20 |  |  | 3,943 |
Operating Lease Obligations | 53,166 |  |  | 88,057 |  |  | 9,786 |  |  | 17,155 |  |  | 168,164 |
Interest on Operating Lease Obligations | 6,856 |  |  | 6,607 |  |  | 2,310 |  |  | 1,353 |  |  | 17,126 |
Long-Term Liabilities—Employee Related (a) | 2,230 |  |  | 4,488 |  |  | 4,810 |  |  | 21,893 |  |  | 33,421 |
Other Long-Term Liabilities (b) | 154,497 |  |  | 10,000 |  |  | 10,000 |  |  | 67,987 |  |  | 242,484 |
Total Contractual Obligations (c) | $ | 605,783 |  |  | $ | 1,126,623 |  |  | $ | 1,041,770 |  |  | $ | 2,331,362 |  |  | $ | 5,105,538 |

_________________________
(a)Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.
(b)Other long-term liabilities include royalties and other long-term liability costs.
(c)The table above does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
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Debt
At June 30, 2023, CNX had total long-term debt of $2,167 million, excluding unamortized debt issuance costs. This long-term debt consisted of:
•An aggregate principal amount of $500 million of 7.375% Senior Notes due January 2031, less $6 million of unamortized bond discount. Interest on the notes is payable January 15 and July 15 each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
•An aggregate principal amount of $500 million of 6.00% Senior Notes due January 2029. Interest on the notes is payable January 15 and July 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
•An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $4 million of unamortized bond discount. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of these notes.
•An aggregate principal amount of $350 million of 7.25% Senior Notes due March 2027 plus $2 million of unamortized bond premium. Interest on the notes is payable March 14 and September 14 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
•An aggregate principal amount of $331 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $6 million of unamortized discount and issuance costs. Interest on the notes is payable May 1 and November 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).
•An aggregate principal amount of $100 million in outstanding borrowings under the CNXM Credit Facility. Payment of the principal and interest on the CNXM Credit Facility is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of the CNXM Facility.
Total Equity and Dividends
CNX had total equity of $3,983 million at June 30, 2023 compared to $2,950 million at December 31, 2022. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.
The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance can be given that CNX will pay dividends in the future. CNX has not paid dividends on its common stock since 2016. 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. CNX's Credit Facility limits its ability to pay dividends in excess of an annual rate of $0.10 per share when the Company's net leverage ratio exceeds 3.00 to 1.00 and is subject to availability under the Credit Facility of at least 20% of the aggregate commitments and there being no borrowing base deficiency. The Credit Facility does not permit such dividend payments when an event of default has occurred and is continuing. The indentures to the 7.25% Senior Notes due March 2027, the 6.00% Senior Notes due January 2029, and the 7.375% Senior Notes due January 2031 limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the six months ended June 30, 2023.
Off-Balance Sheet Transactions
CNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CNX uses a combination of surety bonds, corporate guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected in the Consolidated Balance Sheet at June 30, 2023. Management believes these items will expire without being funded. See Note 11 – 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.
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Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities, revenue and expenses and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements. Actual results could materially differ from those estimates. The preceding discussion and analysis of our consolidated results of operations and financial condition should be read in conjunction with our Consolidated Financial Statements included elsewhere in this Quarterly Report on Form 10-Q. The 2022 financial statements, as part of our Form 10-K filed with the SEC, includes additional information about us, our operations, our financial condition, our critical accounting policies and accounting estimates, and should be read in conjunction with this Quarterly Report on Form 10-Q. Our significant accounting policies are described in Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX's 2022 Form 10-K.
Forward-Looking Statements
We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act)) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," "will," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe a strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
•prices for natural gas and NGLs 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;
•unsuccessful operational efforts or continued natural gas price decreases requiring write downs of our proved natural gas properties, or changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as movement in our stock price, weighted-average cost of capital, terminal growth rates and industry multiples, could cause goodwill and other intangible assets we hold to become impaired and result in material non-cash charges to earnings;
•a loss of our competitive position because of the competitive nature of the natural gas industry, consolidation within the industry or overcapacity in the industry adversely affecting our ability to sell our products and midstream services;
•deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, inflationary pressures, or negative credit market conditions;
•hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
•negative public perception regarding our Company or industry;
•events beyond our control, including a global or domestic health crisis, or political or economic instability or armed conflict in oil and gas producing regions;
•increasing attention to environmental, social and governance matters;
•dependence on gathering, processing and transportation facilities and other midstream facilities owned by others, and disruption of, capacity constraints in, or proximity to pipeline systems, and any decrease in availability of pipelines or other midstream facilities;
•uncertainties in estimating our economically recoverable natural gas reserves and inaccuracies in our estimates;
•the high-risk nature of drilling, developing and operating natural gas wells;
•our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their development or drilling;
•the substantial capital expenditures required for, and commensurate risks associated with, our development and exploration projects, as well as midstream system development;
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•decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials in sufficient quantities or at reasonable costs to support our operations;
•our ability to find adequate water sources for our use in shale gas drilling and production operations, or our ability to dispose of, transport or recycle water used or removed in connection with our gas operations at a reasonable cost and within applicable environmental rules;
•failure to successfully estimate the rate of decline of existing reserves or to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;
•losses incurred as a result of title defects in the properties in which we invest, or the loss of certain leasehold or other rights related to our midstream activities;
•the impact of climate change legislation, litigation and potential, as well as any adopted, environmental regulations, including those relating to greenhouse gas emissions;
•environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;
•existing and future governmental laws, regulations, other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations;
•significant costs and liabilities may be incurred as a result of pipeline operations and related increase in the regulation of natural gas gathering pipelines;
•changes in federal or state income tax laws or rates focused on natural gas exploration and development;
•the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the Exchange Act;
•risks associated with our current long-term debt obligations;
•a decrease in our borrowing base, which could decrease for a variety of reasons including lower natural gas prices, declines in natural gas proved reserves, asset sales and lending requirements or regulations;
•risks associated with our Convertible Notes, including the potential impact that the Convertible Notes may have on our reported financial results, potential dilution, our ability to raise funds to repurchase the Convertible Notes, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of the Company;
•the potential impact of the capped call transaction undertaken in tandem with the Convertible Notes issuance, including counterparty risk;
•challenges associated with strategic determinations, including the allocation of capital and other resources to strategic opportunities;
•inability to complete acquisitions and divestitures, or failure to produce anticipated benefits of the transaction;
•there is no guarantee that we will continue to repurchase shares of our common stock under our current or any future share repurchase program at levels undertaken previously or at all;
•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;
•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 may be allocated responsibility;
•cyber-incidents could have a material adverse effect on our business, financial condition or results of operations;
•our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel;
•terrorist activities could materially adversely affect our business and results of operations; and
•certain other factors addressed in this report and in our 2022 Form 10-K under "Risk Factors".
Although forward-looking statements reflect our good faith beliefs at the time they are made, they involve known and unknown risks, uncertainties and other factors. For more information concerning factors that could cause actual results to differ materially from those conveyed in the forward-looking statements, including, among others, that our business plans may change as circumstances warrant, please refer to the "Risk Factors" and "Forward-Looking Statements" sections of our Annual Report 2022 Form 10-K and subsequent Quarterly Reports on Form 10-Q. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.
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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 and liquids. CNX uses fixed-price contracts, options and derivative commodity instruments (over-the-counter swaps) to minimize exposure to market price volatility in the sale of natural gas and NGLs. Under our risk management policy, it is not our intent to engage in derivative activities for speculative purposes. Typically, CNX "sells" swaps under which it receives a fixed price from counterparties and pays a floating market price, but occasionally CNX may find it advantageous to purchase, rather than "sell", financial swaps.
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 predefined risk parameters.
CNX believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates our exposure to material pricing risks. The use of derivative instruments without other risk assessment procedures could materially affect the Company's results of operations depending on market prices; however, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity due to our risk assessment procedures and internal controls.
For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX's 2022 Form 10-K.
CNX's open derivative instruments can cause earnings volatility relative to changes in market prices until the derivative contracts are either settled or are monetized prior to settlement. At June 30, 2023 and December 31, 2022 our open derivative instruments were in net liability positions with fair values of $524 million and $1,905 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at June 30, 2023 and December 31, 2022. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $678 million and $816 million at June 30, 2023 and December 31, 2022, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by $678 million and $679 million at June 30, 2023 and December 31, 2022, respectively.
CNX's interest expense is sensitive to changes in the general level of interest rates in the United States. The Company uses derivative instruments to manage risk related to interest rates. These instruments change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. At June 30, 2023 and December 31, 2022, CNX had $2,060 million and $2,055 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $13 million and $14 million, respectively. At June 30, 2023 and December 31, 2022, CNX had $100 million and $154 million, respectively, of debt outstanding under variable-rate instruments. CNX’s primary exposure to market risk for changes in interest rates relates to CNX's revolving credit facility, under which there were no borrowings at June 30, 2023 and December 31, 2022, and CNXM's revolving credit facility, under which there were $100 million of borrowings at June 30, 2023 and $154 million at December 31, 2022. A hypothetical 100 basis-point increase in the average rate for CNX's variable-rate instruments would decrease pre-tax future earnings as of June 30, 2023 and December 31, 2022 by $1 million and $2 million, respectively, on an annualized basis.
All of the Company’s transactions are denominated in U.S. dollars and, as a result, it does not have material exposure to currency exchange-rate risks.
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Natural Gas Hedging Volumes
As of July 6, 2023, the Company's hedged volumes for the periods indicated are as follows:

| For the Three Months Ended |  |
| March 31, |  | June 30, |  | September 30, |  | December 31, |  | Total Year
2023 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | N/A |  | N/A |  | 114.3 |  |  | 114.0 |  |  | 228.3 |
Weighted Average Hedge Price per Mcf | N/A |  | N/A |  | $ | 2.42 |  |  | $ | 2.51 |  |  | $ | 2.47 |
2024 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 99.3 |  |  | 108.8 |  |  | 107.7 |  |  | 107.5 |  |  | 411.1*
Weighted Average Hedge Price per Mcf | $ | 2.35 |  |  | $ | 2.52 |  |  | $ | 2.50 |  |  | $ | 2.53 |  |  | $ | 2.47 |
2025 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 92.5 |  |  | 92.9 |  |  | 93.9 |  |  | 95.0 |  |  | 374.3 |
Weighted Average Hedge Price per Mcf | $ | 2.42 |  |  | $ | 2.38 |  |  | $ | 2.38 |  |  | $ | 2.39 |  |  | $ | 2.39 |
2026 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 76.6 |  |  | 85.5 |  |  | 86.3 |  |  | 86.3 |  |  | 333.3*
Weighted Average Hedge Price per Mcf | $ | 2.48 |  |  | $ | 2.55 |  |  | $ | 2.55 |  |  | $ | 2.54 |  |  | $ | 2.53 |
2027 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 53.6 |  | 54.1 |  | 54.7 |  | 54.7 |  | 217.1
Weighted Average Hedge Price per Mcf | $ | 3.29 |  |  | $ | 3.32 |  |  | $ | 3.32 |  |  | $ | 3.40 |  |  | $ | 3.33 |

*Quarterly volumes do not add to annual volumes inasmuch as a discrete condition in individual quarters, where basis hedge volumes exceed NYMEX hedge volumes, does not exist for the year taken as a whole.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure controls and procedures. CNX, under the supervision and with the participation of its management, including CNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s "disclosure controls and procedures," as such term is defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CNX’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of June 30, 2023 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.
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PART II: OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The first through the third paragraphs of Note 11 – Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.
From time to time, CNX and federal, state, and local regulatory agencies that oversee CNX’s activities enter into agreements regarding notices of noncompliance. CNX is currently not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which the Company is subject to, that would have a material effect on future financial results.
ITEM 1A. RISK FACTORS
The financial conditions and operating results of the Company can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in "Item 1A. Risk Factors" in CNX's 2022 Form 10-K. The risks described could materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. CNX may experience additional risks and uncertainties not currently known; or, as a result of developments occurring in the future, conditions that are currently deemed to be immaterial may also materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. There have been no material changes to the Company’s risk factors since the 2022 Form 10-K was filed.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth repurchases of our common stock during the three months ended June 30, 2023:

ISSUER PURCHASES OF EQUITY SECURITIES
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (000's omitted)
April 1, 2023 - April 30, 2023 | 1,139,739 |  | $ | 15.95 |  | 1,137,269 |  | $ | 335,968 |
May 1, 2023 - May 31, 2023 | 1,414,441 |  | $ | 15.53 |  | 1,414,441 |  | $ | 314,007 |
June 1, 2023 - June 30, 2023 | 1,357,063 |  | $ | 16.95 |  | 1,357,063 |  | $ | 291,002 |
Total | 3,911,243 |  |  | 3,908,773 |  |

(1) Includes shares withheld from employees to satisfy minimum tax withholding obligations associated with the vesting of restricted stock during the period.
(2) Shares repurchased as part of the Company's $1,900 million share repurchase program authorized by the Board of Directors, which is not subject to an expiration date. The amount of shares that may yet be purchased under the Plan does not include a $1,000 million increase authorized by the Board of Directors on July 25, 2023 (See Note 15 – Stock Repurchase in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for more information).
ITEM 5. OTHER INFORMATION
Trading Arrangements
None of the Company’s directors or "officers," as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), adopted, modified, or terminated a "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408 of Regulation S-K, during the Company’s fiscal quarter ended June 30, 2023.
Amended and Restated Bylaws
On July 25, 2023, the Company’s Board of Directors approved the Amended and Restated Bylaws, effective as of such
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date (the "Amended and Restated Bylaws"). The Amended and Restated Bylaws include certain changes to the procedures by which stockholders may recommend nominees to the Company’s Board of Directors, among other updates, including to:
•address matters relating to Rule 14a-19 (the "Universal Proxy Rule") under the Exchange Act, including (i) requiring that any stockholder submitting a nomination notice make a representation as to whether such stockholder intends to solicit proxies in support of director nominees other than the Company’s nominees in accordance with the Universal Proxy Rule, and if so, agree in writing that such stockholder will comply with the requirements of the Universal Proxy Rule; (ii) providing the Company a remedy if a stockholder fails to satisfy the Universal Proxy Rule requirements; (iii) requiring that a stockholder inform the Company if such stockholder no longer plans to solicit proxies in accordance with the Universal Proxy Rule; and (iv) requiring stockholders intending to use the Universal Proxy Rule to provide reasonable evidence of the satisfaction of the requirements under the Universal Proxy Rule at least five business days before the meeting upon request by the Company;
•revise and enhance the procedures and disclosure requirements set forth in the advance notice bylaw provisions for director nominations made and business proposals submitted by stockholders (other than proposals submitted pursuant to Rule 14a-8 under the Exchange Act), including (i) requiring additional information, representations, and disclosures regarding proposing stockholders, proposed nominees, proposed business, and other persons related to, and acting in concert with, a stockholder and the stockholder’s solicitation of proxies; (ii) clarifying that stockholders are not entitled to make additional or substitute nominations or proposals after the submission deadline and may only nominate a number of candidates to the Board of Directors that does not exceed the number of directors to be elected at such meeting; (iii) requiring that if requested by the Secretary of the Company, the Board of Directors or any committee of the Board of Directors, proposed nominees make themselves available for interviews by the Board of Directors and any committee of the Board of Directors within five business days following the date of such request; and (iv) clarifying the authority of the Secretary of the Company, the Board of Directors, or any committee of the Board of Directors to request additional information or written verification to demonstrate the accuracy of previously-provided information with respect to proposing stockholders, proposed nominees, and proposed business;
•require any stockholders directly or indirectly soliciting proxies from other stockholders to use a proxy card color other than white, with the white proxy card being reserved for exclusive use by the Board of Directors;
•clarify and revise who has the authority to call stockholder meetings, determine the order of business, decide the rules of procedure, and regulate the conduct of stockholder meetings;
•provide that the vote standard applicable to the proposal on the frequency of future advisory votes on executive compensation required by Section 14A(a)(2) of the Exchange Act (to determine whether the advisory vote on executive compensation will occur every one year, two years or three years) is a plurality of the votes cast by the Company’s stockholders; and
•incorporate certain administrative, modernizing, and conforming changes to provide clarification and consistency, including regarding meetings of the Board of Directors.
The foregoing description of the Amended and Restated Bylaws does not purport to be complete and is qualified in its entirety by reference to the full text of the Amended and Restated Bylaws, which is filed as Exhibit 3.1 to this Quarterly Report on Form 10-Q and incorporated herein by reference.
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ITEM 6. EXHIBITS

3.1 |  |  | Amended and Restated Bylaws of CNX Resources Corporation, filed here within.
10.1 |  |  | Letter Agreement, dated May 24, 2023, by and between CNX Resources Corporation and Olayemi Akinkugbe, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 26, 2023.
10.2 |  |  | Amendment No. 2, dated as of May 10, 2023, to the Third Amended and Restated Credit Agreement, dated October 6, 2021, by and among CNX Resources Corporation, the guarantors party thereto, the lenders party thereto and PNC Bank, N.A., as administrative agent and collateral agent, filed here within.
31.1* |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 |  |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 |  |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS |  | Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH* |  | Inline XBRL Taxonomy Extension Schema Document.
101.CAL* |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF* |  | Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB* |  | Inline XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE* |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104* |  | Cover Page Interactive Data File (embedded within the Inline XBRL document)

* Filed herewith
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: July 27, 2023

CNX RESOURCES CORPORATION
| By: |  | /S/ NICHOLAS J. DEIULIIS
|  |  | Nicholas J. DeIuliis
|  |  | Director, Chief Executive Officer and President (Duly Authorized Officer and Principal Executive Officer)
| By: |  | /S/ ALAN K. SHEPARD
|  |  | Alan K. Shepard
|  |  | Chief Financial Officer (Duly Authorized Officer and Principal Financial and Accounting Officer)
| By: |  | /S/ JASON L. MUMFORD
|  |  | Jason L. Mumford
|  |  | Vice President and Controller

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