UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-K

__________________________________________________

(Mark One)


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

For the fiscal year ended December 31, ~~2020~~2021


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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CNX Resources Corporation

(Exact name of registrant as specified in its charter)


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

CNX Center

1000 CONSOL Energy Drive Suite 400

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of exchange on which registered

Common Stock ($.01 par value)

CNX

New York Stock Exchange

Preferred Share Purchase Rights

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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, if any, 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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

The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, ~~2020,~~2021, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was ~~$1,111,264,635.~~$2,246,902,938.

The number of shares outstanding of the registrant's common stock as of January 20, ~~2021~~2022 is ~~219,707,417~~202,489,683 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CNX's Proxy Statement for the Annual Meeting of Shareholders to be held on May 6, 2021, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.

TABLE OF CONTENTS


		Page
PART I
ITEM 1.	Business	7
ITEM 1A.	Risk Factors	20
ITEM 1B.	Unresolved Staff Comments	4042
ITEM 2.	Properties	4042
ITEM 3.	Legal Proceedings	4142
ITEM 4.	Mine Safety Disclosures	4142

PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	4143
ITEM 6.	~~Selected Financial Data~~Reserved	4344
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	4445
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	7665
ITEM 8.	Financial Statements and Supplementary Data	7867
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	~~134~~120
ITEM 9A.	Controls and Procedures	~~134~~120
ITEM 9B.	Other Information	~~136~~122

PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	~~136~~122
ITEM 11.	Executive Compensation	~~137~~124
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~137~~124
ITEM 13.	Certain Relationships and Related Transactions and Director Independence	~~137~~124
ITEM 14.	Principal Accountant Fees and Services	~~137~~124

PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	~~138~~125
ITEM 16.	Form 10-K Summary	~~143~~129
SIGNATURES		~~143~~130

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-K:

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~~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 ~~futures~~ 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 ~~NGLs~~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.

FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Annual Report on Form 10-K (Form 10K) 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 Form 10-K 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 strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Form 10-K speak only as of the date of this Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•prices for natural gas and ~~natural gas liquids~~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 drilling 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, 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 could have an adverse effect on our operations, financial results or stock price;~~industry;

•events beyond our control, including a global or domestic health crisis;

•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;

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

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

•changes in federal or state income tax laws or ~~rates;~~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 senior notes due May 2026 (the “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, ~~we anticipate may not occur~~ or failure to produce anticipated ~~benefits;~~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

•other factors discussed in this ~~2020~~2021 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file with the Securities and Exchange Commission.

PART I

ITEM 1.Business

General

CNX Resources Corporation (“~~CNX”,~~CNX,” the “Company,” or “we,” “us,” or “our”) is ana premier independent ~~oil~~natural gas and ~~natural gas~~midstream company engaged in the exploration, development, production and acquisition of natural gas properties ~~primarily~~ in the Appalachian Basin. The majority of our operations are centered on unconventional shale formations, primarily the Marcellus Shale and Utica Shale, in Pennsylvania, Ohio and West Virginia. Additionally, we operate and develop Coal Bed Methane ~~(“CBM”)~~(CBM) properties in Virginia. We believe that our extensive held-by-production acreage position and development inventory combined with our regional operating expertise, extensive data set from development and non-op participation wells, midstream infrastructure ownership, low-cost operations and legacy surface acreage position provide us with significant competitive advantages that position us for long-term value creation.

CNX's Strategy and Corporate Values

CNX's strategy is to increase shareholder value through the development and growth of our existing natural gas assets and the selective acquisition of natural gas acreage leases within our operating footprint. Our mission is to empower our team to embrace and drive innovative change that creates long-term per share value for our investors, enhances our communities and delivers energy solutions for today and tomorrow.

CNX defines itself through its corporate values that serve as our road map and guide every aspect of our business as we strive to achieve our corporate mission:

•Responsibility: Be a safe and compliant operator; be a trusted community partner and respected corporate citizen; act with pride and integrity;

•Ownership: Be accountable for our actions and learn from our outcomes, both positive and negative; be calculated risk-takers and seek creative ways to solve problems; and

•Excellence: Be prudent capital allocators; be a lean, efficient, nimble organization; be a disciplined, reliable, performance-driven company.

These values are the foundation of CNX's identity and are the basis for how management defines continued success. ~~We believe CNX's rich resource~~With the benefit of a more than 155-year legacy and a substantial asset base ~~coupled with these core values, allows management~~amassed over many generations, the Company deploys a strategy focused on responsibly developing its resources to create long-term per share ~~value.~~ value for its shareholders, employees, and the communities where it operates.

CNX believes that natural gas is central to a low-cost, reliable, secure, lower-carbon energy ~~future. Widespread~~future that benefits American consumers, workers and ~~immediate fuel switching to natural gas is~~ the fastest and most cost-effective means to addressing climate concerns, improving air quality in the developing world and meeting the increasing demand for cleaner forms of energy. Natural gas is more than a short-term “bridge” fuel that is useful in the transition from more carbon-intensive energy sources to renewables, it is inextricably linked to the long-term success of renewable energy.environment.

~~2020~~2021 Operational Highlights and Outlook

•Over the past ten years, CNX's natural gas production has grown by approximately ~~300%~~285% to a total of ~~511.1~~590.2 net Bcfe in ~~2020.~~2021.

•Total average production of ~~1,396,371~~1,617,118 Mcfe per day;

•94% Natural Gas, 6% Liquids; and

•~~90%~~92% Shale, ~~10%~~8% coalbed methane.

At December 31, ~~2020,~~2021, our proved natural gas, NGL, condensate and oil reserves (collectively, ~~"natural~~“natural gas ~~reserves"~~reserves”) had the following characteristics:

•~~9.5~~9.6 Tcfe of proved reserves;

•~~94.6%~~93.4% natural gas;

•~~54.4%~~61.4% proved developed;

•~~98.7%~~98.5% operated; and

•~~A reserve life ratio of 18.69 years (based on 2020 production).~~

In ~~2021,~~2022, CNX expects capital expenditures of approximately ~~$430~~$470 million to ~~$470~~$500 million. The Company continuously evaluates multiple factors to determine activity throughout the year, and as such, may update guidance accordingly.

DETAIL OF OPERATIONS

Our operations include the following plays:

Shale

Our Shale properties represent our primary operating and growth area in terms of reserves, production, and capital investment. We have ~~the~~ rights to extract natural gas from Shale formations in Pennsylvania, West Virginia, and Ohio from approximately ~~524,000~~526,000 net Marcellus Shale acres and approximately 610,000 net Utica Shale acres at December 31, ~~2020.~~2021. Approximately ~~349,000~~348,000 Utica Shale acres coincide with Marcellus Shale acreage in Pennsylvania, West Virginia, and Ohio.

The Upper Devonian Shale formation, which includes both the Burkett Shale and Rhinestreet Shale, lies above the Marcellus Shale formation in southwestern Pennsylvania and northern West Virginia. The Company holds approximately 52,000 acres of incremental Upper Devonian acres; however, these acres have historically not been disclosed separately as they generally coincide with our Marcellus acreage and we have no current drilling program targeting this formation.

Coalbed Methane (CBM)

We have ~~the~~ rights to extract CBM in Virginia from approximately ~~283,000~~282,000 net CBM acres in Central Appalachia. We produce CBM natural gas primarily from the Pocahontas #3 seam and still have a nominal drilling program. The CBM natural gas we extract would otherwise be vented into the atmosphere during normal mining operations.

We also have ~~the~~ rights to extract CBM from approximately ~~1,896,000~~1,733,000 net CBM acres in other states including West Virginia, Pennsylvania, Ohio, Illinois, Indiana, and New Mexico with no current plans to drill CBM wells in these areas.

Other Gas

We have ~~the~~ rights to extract natural gas from other shale and shallow oil and gas positions primarily in Illinois, Indiana, New York, Ohio, Pennsylvania, Virginia, and West Virginia from approximately ~~1,017,000~~1,006,000 net acres at December 31, ~~2020.~~2021. The majority of our shallow oil and gas leasehold position is held by third-party production and all of it is extensively overlain by existing third-party natural gas gathering and transmission infrastructure.

Summary of Properties as of December 31, ~~2020~~2021


		Shale		CBM		Other Gas					Shale		CBM		Other Gas
		Segment		Segment		Segment		Total			Segment		Segment		Segment		Total
Estimated Net Proved Reserves (MMcfe)	Estimated Net Proved Reserves (MMcfe)	8,443,926		1,099,627		6,205		9,549,758		Estimated Net Proved Reserves (MMcfe)	8,532,076		1,087,172		6,482		9,625,730
Percent Developed (1)	Percent Developed (1)	52	%	71	%	100	%	54	%	Percent Developed (1)	60	%	71	%	100	%	61	%
Net Producing Wells (including oil and gob wells)	Net Producing Wells (including oil and gob wells)	491		3,852		57		4,400		Net Producing Wells (including oil and gob wells)	533		3,850		49		4,432
Net Acreage Position:	Net Acreage Position:									Net Acreage Position:
Net Proved Developed Acres	Net Proved Developed Acres	77,369		235,388		38,780		351,537		Net Proved Developed Acres	96,474		242,285		38,091		376,850
Net Proved Undeveloped Acres(2)	Net Proved Undeveloped Acres(2)	43,713		—		—		43,713		Net Proved Undeveloped Acres(2)	41,605		—		—		41,605
Net Unproved Acres~~(2)~~(3)	Net Unproved Acres~~(2)~~(3)	716,581		1,943,671		977,730		3,637,982		Net Unproved Acres~~(2)~~(3)	701,682		1,772,422		968,055		3,442,159
Total Net Acres~~(3)~~(4)	Total Net Acres~~(3)~~(4)	837,663		2,179,059		1,016,510		4,033,232		Total Net Acres~~(3)~~(4)	839,761		2,014,707		1,006,146		3,860,614

_________

(1) Percent developed is calculated as net proved developed reserves divided by net proved reserves, measured in MMcfe.

(2) Net proved undeveloped acres represent undrilled locations and can only be classified as having proved undeveloped reserves 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 (See glossary of oil and gas terms for additional information)

(3) Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

~~(3)~~(4) Acreage amounts are only included under the target strata CNX expects to produce with the exception of certain CBM acres governed by separate leases.

Producing Wells and Acreage

Most of our development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied.

The following table sets forth, at December 31, ~~2020,~~2021, the number of producing wells, developed acreage and undeveloped acreage:


		Gross(1)	Net(2)		Gross(1)	Net(2)
Producing Gas Wells (including gob wells) - Working Interest	Producing Gas Wells (including gob wells) - Working Interest	4,712	4,401	Producing Gas Wells (including gob wells) - Working Interest	4,716	4,432
Producing Oil Wells - Working Interest		—	—

Producing Gas Wells - Royalty Interest	Producing Gas Wells - Royalty Interest	1,810	—	Producing Gas Wells - Royalty Interest	2,031	—
Producing Oil Wells - Royalty Interest	Producing Oil Wells - Royalty Interest	152	—	Producing Oil Wells - Royalty Interest	150	—
Net Acreage Position:	Net Acreage Position:			Net Acreage Position:
Proved Developed Acreage	Proved Developed Acreage	351,537	351,537	Proved Developed Acreage	376,850	376,850
Proved Undeveloped Acreage	Proved Undeveloped Acreage	43,713	43,713	Proved Undeveloped Acreage	41,605	41,605
Unproved Acreage	Unproved Acreage	4,986,196	3,637,982	Unproved Acreage	4,756,680	3,442,159
Total Acreage	Total Acreage	5,381,446	4,033,232	Total Acreage	5,175,135	3,860,614

_________

(1) All of our acreage identified as proved developed and undeveloped is controlled fully by CNX through ownership of a 100% working interest.

(2) Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

The following table represents the terms under which we hold these acres:


		Gross Unproved Acres	Net Unproved Acres	Gross Proved Undeveloped Acres	Net Proved Undeveloped Acres		Gross Unproved Acres	Net Unproved Acres	Gross Proved Undeveloped Acres	Net Proved Undeveloped Acres
Held by Production/Fee	Held by Production/Fee	4,889,527	3,578,943	30,594	30,594	Held by Production/Fee	4,660,401	3,391,644	28,749	28,749
Expiration Within 2 Years	Expiration Within 2 Years	55,298	30,429	4,732	4,732	Expiration Within 2 Years	53,242	24,788	5,581	5,581
Expiration Beyond 2 Years	Expiration Beyond 2 Years	41,370	28,610	8,387	8,387	Expiration Beyond 2 Years	43,037	25,727	7,275	7,275
Total Acreage	Total Acreage	4,986,195	3,637,982	43,713	43,713	Total Acreage	4,756,680	3,442,159	41,605	41,605

The leases reflected above as Gross and Net Unproved Acres with expiration dates are included in our current drill plan or active land program. Leases with expiration dates within two years represent approximately 1% of our total net unproved acres and leases with expiration dates beyond two years represent approximately 1% of our total net unproved acres. In each case, we deemed this acreage to not be material to our overall acreage position. Additionally, based on our current drill plans and lease management we do not anticipate any material impact to our consolidated financial statements from the expiration of such leases.

Development Wells (Net)

During the years ended December 31, 2021, 2020 ~~2019~~ and ~~2018,~~2019, we drilled 33.0, 29.0 ~~75.7~~ and ~~83.9~~75.7 net development wells, respectively. Gob wells and wells drilled by operators other than our primary joint venture partners at that time are excluded from net development wells and represents less than 0.5 net wells for each year. ~~In 2020,~~As of December 31, 2021, there were ~~17.0~~13.0 net development wells and no exploratory wells drilled but uncompleted. The Company includes drilled and uncompleted net development wells in proved undeveloped reserves and the Company intends to complete and turn-in-line the wells within five years of the initial disclosure. There were no net dry development wells in ~~2020~~2021 or ~~2018~~2020 and 1.0 net dry development well in 2019. As of December 31, ~~2020,~~2021, there ~~are 24.0~~were no gross completed developmental wells ready to be turned in-line.

The following table illustrates the net wells drilled by well classification type:


		For the Year				For the Year
		Ended December 31,				Ended December 31,
		2020	2019	2018		2021	2020	2019
Shale Segment	Shale Segment	25.0	64.7	77.9	Shale Segment	33.0	25.0	64.7
CBM Segment	CBM Segment	4.0	11.0	6.0	CBM Segment	—	4.0	11.0
Other Gas Segment	Other Gas Segment	—	—	—	Other Gas Segment	—	—	—
Total Development Wells (Net)	Total Development Wells (Net)	29.0	75.7	83.9	Total Development Wells (Net)	33.0	29.0	75.7

Exploratory Wells (Net)

There were no net exploratory wells drilled during the year ended December 31, 2021. There were 2.0 and 5.0 net exploratory wells drilled during the years ended December 31, 2020 and 2019, respectively. ~~There were~~As of December 31, 2021, there are no net exploratory wells ~~drilled during the year ended December 31, 2018. As of December 31, 2020, there is 1.0 net exploratory well~~ in process. The following table illustrates the exploratory wells drilled by well classification type:


		For the Year Ended December 31,										For the Year Ended December 31,
		2020			2019			2018				2021			2020			2019
		Producing	Dry	Still Eval*.	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.		Producing	Dry	Still Eval.	Producing	Dry	Still Eval*.	Producing	Dry	Still Eval.**
Shale Segment	Shale Segment	—	—	2.0	4.0	—	1.0	—	—	—	Shale Segment	—	—	—	—	—	2.0	4.0	—	1.0
CBM Segment	CBM Segment	—	—	—	—	—	—	—	—	—	CBM Segment	—	—	—	—	—	—	—	—	—
Other Gas Segment	Other Gas Segment	—	—	—	—	—	—	—	—	—	Other Gas Segment	—	—	—	—	—	—	—	—	—
Total Exploratory Wells (Net)	Total Exploratory Wells (Net)	—	—	2.0	4.0	—	1.0	—	—	—	Total Exploratory Wells (Net)	—	—	—	—	—	2.0	4.0	—	1.0

_________

* Still evaluating in 2020 ~~includes~~included two wells that were drilled, completed, and were in process of being connected to production facilities at the end of the year and were turned in-line in early 2021. ~~The company is still currently~~

**Still evaluating ~~the~~in 2019 included one well that was partially constructed ~~2019 well~~and the Company was trying to determine the most economic approach to access the natural gas reserves. ~~The company expects to make a determination in~~During the year-ended December 31, 2021, ~~to either finalize~~ the ~~well or~~Company determined it would be more economical to access the ~~natural gas~~underlying reserves from ~~an alternative location.~~a different location and the costs associated with this well were recorded to Exploration and Production Related Other Costs in the Consolidated Statements of Income.

Reserves

The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).


Net Reserves (Million of Cubic Feet Equivalent)		As of December 31,
Net Reserves (Millions of Cubic Feet Equivalent)					Net Reserves (Millions of Cubic Feet Equivalent)	As of December 31,
		2020	2019	2018		2021	2020	2019
Proved Developed Reserves	Proved Developed Reserves	5,199,748	4,838,858	4,494,878	Proved Developed Reserves	5,905,611	5,199,748	4,838,858
Proved Undeveloped Reserves	Proved Undeveloped Reserves	4,350,010	3,586,809	3,386,457	Proved Undeveloped Reserves	3,720,119	4,350,010	3,586,809
Total Proved Developed and Undeveloped Reserves (1)	Total Proved Developed and Undeveloped Reserves (1)	9,549,758	8,425,667	7,881,335	Total Proved Developed and Undeveloped Reserves (1)	9,625,730	9,549,758	8,425,667

___________

(1) For additional information on our reserves, see ~~Other Supplemental Information–~~Note 22 – Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.

Discounted Future Net Cash Flows

The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:


		As of December 31,							As of December 31,
		2020		2019		2018			2021		2020		2019
		(Dollars in millions)							(Dollars in millions)
Future Net Cash Flows	Future Net Cash Flows	$	6,313	$	7,744	$	13,132	Future Net Cash Flows	$	16,017	$	6,313	$	7,744
Total PV-10 Measure of Pre-Tax Discounted Future Net Cash Flows (1)	Total PV-10 Measure of Pre-Tax Discounted Future Net Cash Flows (1)	$	3,603	$	4,176	$	6,172	Total PV-10 Measure of Pre-Tax Discounted Future Net Cash Flows (1)	$	8,081	$	3,603	$	4,176
Total Standardized Measure of After-Tax Discounted Future Net Cash Flows	Total Standardized Measure of After-Tax Discounted Future Net Cash Flows	$	2,636	$	3,070	$	4,655	Total Standardized Measure of After-Tax Discounted Future Net Cash Flows	$	5,882	$	2,636	$	3,070

____________

(1) We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principles (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.

Reconciliation of PV-10 to Standardized Measure


		As of December 31,							As of December 31,
		2020		2019		2018			2021		2020		2019
		(Dollars in millions)							(Dollars in millions)
NYMEX Natural Gas Prices (MMbtu)		$	1.985	$	2.578	$	3.100
Average Henry Hub Price ($/MMBtu)(1)								Average Henry Hub Price ($/MMBtu)(1)	$	3.598	$	1.985	$	2.578

Future Cash Inflows	Future Cash Inflows	$	16,578	$	19,490	$	26,610	Future Cash Inflows	$	31,839	$	16,578	$	19,490
Future Production Costs	Future Production Costs	(6,072)		(7,903)		(7,730)		Future Production Costs	(8,247)		(6,072)		(7,903)
Future Development Costs (including Abandonments)*		(1,958)		(1,121)		(1,600)
Future Development Costs (including Abandonments)(2)								Future Development Costs (including Abandonments)(2)	(1,736)		(1,958)		(1,121)
Future Net Cash Flows (pre-tax)	Future Net Cash Flows (pre-tax)	8,548		10,466		17,280		Future Net Cash Flows (pre-tax)	21,856		8,548		10,466
10% Discount Factor	10% Discount Factor	(4,945)		(6,290)		(11,108)		10% Discount Factor	(13,775)		(4,945)		(6,290)
PV-10 (Non-GAAP Measure)	PV-10 (Non-GAAP Measure)	3,603		4,176		6,172		PV-10 (Non-GAAP Measure)	8,081		3,603		4,176
Undiscounted Income Taxes	Undiscounted Income Taxes	(2,235)		(2,721)		(4,147)		Undiscounted Income Taxes	(5,839)		(2,235)		(2,721)
10% Discount Factor	10% Discount Factor	1,268		1,615		2,630		10% Discount Factor	3,640		1,268		1,615
Discounted Income Taxes	Discounted Income Taxes	(967)		(1,106)		(1,517)		Discounted Income Taxes	(2,199)		(967)		(1,106)
Standardized GAAP Measure(3)	Standardized GAAP Measure(3)	$	2,636	$	3,070	$	4,655	Standardized GAAP Measure(3)	$	5,882	$	2,636	$	3,070

*___________

(1) Based on the average, first day-of-the-month price.

(2) Future Development costs for 2021 include $406 million of plugging and abandonment costs and $185 million of Midstream capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7 million and $154 million, respectively. Future development costs for 2020 include $402 million of plugging and abandonment costs and $287 million of Midstream capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $18 million and $232 million, respectively. The increase from 2019 was primarily due to the addition of Midstream capital ~~is the~~as a result of the Merger that occurred on September 28, 2020 (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K).

(3) For additional information on our reserves, see Note 22 – Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.

Gas Production

The following table sets forth net sales volumes produced for the periods indicated:


		For the Year				For the Year
		Ended December 31,				Ended December 31,
		2020	2019	2018		2021	2020	2019
Natural Gas	Natural Gas				Natural Gas
Sales Volume (MMcf)	Sales Volume (MMcf)				Sales Volume (MMcf)
Shale	Shale	428,679	449,669	403,244	Shale	502,184	428,679	449,669
CBM	CBM	52,609	55,445	60,268	CBM	49,570	52,609	55,445
Other	Other	138	241	4,714	Other	234	138	241
Total	Total	481,426	505,355	468,226	Total	551,988	481,426	505,355

NGL
NGL*					NGL*
Sales Volume (Mbbls)	Sales Volume (Mbbls)				Sales Volume (Mbbls)
Shale	Shale	4,675	5,428	6,080	Shale	5,976	4,675	5,428
Other	Other	2	—	1	Other	—	2	—
Total	Total	4,677	5,428	6,081	Total	5,976	4,677	5,428

Oil and Condensate
Oil and Condensate*					Oil and Condensate*
Sales Volume (Mbbls)	Sales Volume (Mbbls)				Sales Volume (Mbbls)
Shale	Shale	250	195	364	Shale	396	250	195
Other	Other	14	8	35	Other	4	14	8
Total	Total	264	203	399	Total	400	264	203

Total Sales Volume (MMcfe)	Total Sales Volume (MMcfe)				Total Sales Volume (MMcfe)
Shale	Shale	458,231	483,413	441,907	Shale	540,413	458,231	483,413
CBM	CBM	52,609	55,445	60,268	CBM	49,570	52,609	55,445
Other	Other	232	291	4,929	Other	265	232	291
Total		511,072	539,149	507,104
Total**					Total**	590,248	511,072	539,149

*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas.

~~Note: 2018 production includes approximately 27 Bcfe~~**See Part II. Item 7. “Management's Discussion and Analysis of ~~production related to assets that were sold during that year. For additional information, see Note 4 - Acquisitions~~Financial Condition and ~~Dispositions~~Results of Operations” in ~~the Notes to the Audited Consolidated Financial Statements in Item 8 of~~ this Form 10-K ~~which is incorporated herein by reference.~~for a breakdown of sales volume variances.

CNX expects ~~2021~~2022 annual natural gas production volumes to be approximately ~~540-570~~575-605 Bcfe.

Average Sales Price and Average Lifting Cost

The following table sets forth the total average sales price and the total average lifting cost for all of our natural gas and NGL production for the periods indicated. Total lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Part II. Item 7. ~~"Management's~~“Management's Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” in this Form 10-K for a breakdown by segment.


		For the Year							For the Year
		Ended December 31,							Ended December 31,
		2020		2019		2018			2021		2020		2019
Average Sales Price - Gas (Mcf)	Average Sales Price - Gas (Mcf)	$	1.71	$	2.48	$	2.97	Average Sales Price - Gas (Mcf)	$	3.55	$	1.71	$	2.48
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)*		$	0.78	$	0.14	$	(0.15)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)*								(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)*	$	(0.98)	$	0.78	$	0.14
Average Sales Price - NGLs (Mcfe)**	Average Sales Price - NGLs (Mcfe)**	$	2.29	$	3.20	$	4.55	Average Sales Price - NGLs (Mcfe)**	$	5.65	$	2.29	$	3.20
Average Sales Price - Oil (Mcfe)**		$	6.55	$	8.13	$	9.89
Average Sales Price - Condensate (Mcfe)**		$	5.85	$	7.47	$	8.43
Average Sales Price - Oil/Condensate (Mcfe)**								Average Sales Price - Oil/Condensate (Mcfe)**	$	9.39	$	5.98	$	7.50

Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments*	Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments*	$	2.49	$	2.66	$	2.97	Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments*	$	2.79	$	2.49	$	2.66
Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments	Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments	$	1.75	$	2.53	$	3.11	Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments	$	3.70	$	1.75	$	2.53
Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)	Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)	$	0.08	$	0.12	$	0.19	Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)	$	0.08	$	0.08	$	0.12

Average Sales Price - NGLs (Bbl)	Average Sales Price - NGLs (Bbl)	$	13.74	$	19.20	$	27.30	Average Sales Price - NGLs (Bbl)	$	33.90	$	13.74	$	19.20
Average Sales Price - Oil (Bbl)		$	39.30	$	48.78	$	59.34
Average Sales Price - Condensate (Bbl)		$	35.10	$	44.82	$	50.58
Average Sales Price - Oil/Condensate (Bbl)								Average Sales Price - Oil/Condensate (Bbl)	$	56.34	$	35.88	$	45.00

*Excludes the effect of hedge monetizations.

**Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas.

Sales of NGLs, condensates and oil enhance our reported natural gas equivalent sales price. Across all volumes, when excluding the impact of hedging, sales of liquids added $0.15 per Mcfe, $0.04 per Mcfe, and $0.05 per Mcfe for 2021, 2020, and ~~$0.14 per Mcfe for 2020,~~ 2019, ~~and 2018,~~ respectively, to average gas sales prices. CNX expects to continue to realize a liquids uplift benefit as additional wells are turned-in-line, primarily in the liquid-rich areas of the Marcellus Shale. We continue to sell the majority of our NGLs through the large midstream companies that process our natural gas. This approach allows us to take advantage of the processors’ transportation efficiencies and diversified markets. Certain of CNX’s processing contracts provide for the ability to take our NGLs “in-kind” and market them directly if desired. The processed purity products are ultimately sold to industrial, commercial and petrochemical markets.

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. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, we have delivered quantities required under these contracts. CNX also enters into various financial natural gas swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. These transactions exist parallel to the underlying physical transactions and represented approximately 470.0 Bcf of our produced gas sales volumes for the year ended December 31, 2021 at an average price of $2.51 per Mcf. The notional volumes associated with these gas swaps represented approximately 461.1 Bcf of our produced natural gas sales volumes for the year ended December 31, 2020 at an average price of $2.57 per Mcf. The notional volumes associated with these gas swaps represented approximately 389.2 Bcf of our produced natural gas sales volumes for the year ended December 31, 2019 at an average price of $2.70 per Mcf. As of January ~~7, 2021,~~6, 2022, these physical and swap transactions represent approximately ~~472.1 Bcf of our estimated 2021 production at an average price of $2.50 per Mcf, 391.3~~470.8 Bcf of our estimated 2022 production at an average price of ~~$2.34~~$2.45 per Mcf, ~~284.8~~392.3 Bcf of our estimated 2023 production at an average price of ~~$2.22~~$2.36 per Mcf, ~~approximately 263.1~~344.6 Bcf of our estimated 2024 production at an average price of ~~$2.28~~$2.25 per Mcf, ~~and~~ approximately ~~103.0~~273.4 Bcf of our estimated 2025 production at an average price of ~~$2.10~~$2.23 per Mcf, and approximately 220.9 Bcf of our estimated 2026 production at an average price of $2.45 per Mcf.

CNX's hedging strategy and information regarding derivative instruments used are outlined in Part II. Item 7A. ~~"Qualitative~~“Quantitative and ~~Quantitative~~Qualitative Disclosures About Market ~~Risk"~~Risk” and in Note 19 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

Midstream Gas Services

CNX designs, builds and operates natural gas gathering systems to move gas from the wellhead to interstate pipelines or other local sales points. In addition, over time CNX has acquired extensive gathering assets through acquisitions. CNX ~~now~~ owns or operates approximately 2,600 miles of natural gas gathering pipelines as well as a number of natural gas processing facilities.

As a result of the Merger that occurred on September 28, 2020 (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K), CNX owns substantially all of its Shale gathering

systems in Pennsylvania and West Virginia. With respect to CNX's Shale wells in Ohio, CNX primarily contracts with third-party gathering services. CNX also provides natural gas gathering services to third-parties.

CNX has developed a diversified portfolio of firm transportation capacity options to support its production. CNX plans to

selectively acquire firm capacity on an as-needed basis, while minimizing transportation costs and long-term financial obligations. Optimization of our firm transportation portfolio may also include, from time to time and as appropriate, releasing firm transportation to others. CNX also benefits from the strategic location of our primary production areas in southwestern Pennsylvania, northern West Virginia and eastern Ohio. These areas are currently served by a large concentration of major pipelines that provide us with access to major gas markets without the necessity of transporting our natural gas out of the ~~region, and it is expected that recently-approved and pending pipeline projects will increase the take-away capacity from our~~ region. In addition to firm transportation capacity, CNX has developed a processing portfolio to support produced volumes from its wet gas production areas and has the operational and contractual flexibility to potentially convert a portion of currently processed wet gas volumes to be marketed as dry gas volumes, or vice-versa, as economically appropriate.

CNX has the advantage of having natural gas production from lower Btu wells in close proximity to higher Btu wells. Separately, the low Btu natural gas and the high Btu natural gas may need processing in order to meet downstream pipeline specifications. The geographic proximity and interconnected gathering system servicing these wells, allow CNX to blend this gas together and in some cases eliminate the need for the costly processing of natural gas that does not meet pipeline specification. This allow us more flexibility in bringing wells online at qualities that meet interstate pipeline specifications.

CNX also supplies turn-key solutions for water sourcing, delivery and disposal for our natural gas operations and supplies solutions for water sourcing as well as delivery and disposal for third parties. In coordination with our midstream operations, CNX works to develop solutions that coincide with our midstream operations to offer gas natural gathering and water delivery solutions in one package to third parties.

Marketing

Substantially all of our natural gas is sold at market prices primarily under short-term sales contracts and is subject to seasonal and general market price swings. The principal markets for our natural gas are in the Appalachian Basin where we sell natural gas to gas marketers, industrial customers, local distribution companies, ~~gas marketers~~ and power generation facilities. Our extensive hedge position mitigates unpredictability in pricing on hedged volumes.

We also incur gathering, compression, processing, and transportation expenses to move our natural gas production from the wellhead to our principal markets in the United States. Although we own midstream facilities, we also gather, process, and transport our natural gas to market by utilizing pipelines and facilities owned by others where we have long-term contractual capacity arrangements or use purchaser-owned capacity under both long-term and short-term sales contracts.

To date, we have not experienced significant difficulty in transporting or marketing our natural gas production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production.

CNX expects natural gas to continue to be a significant contributor to the domestic electric generation mix in the long term, as well as to fuel industrial growth in the U.S. economy. Continued demand for CNX's natural gas and the prices that CNX obtains are affected by natural gas use in the production of electricity, pipeline capacity, weather, U.S. manufacturing and the overall strength of the economy, environmental and government regulation, technological developments, the availability and price of competing alternative fuel supplies, and national and regional supply and demand dynamics.

Natural Gas Competition

CNX gas operations are primarily located in the eastern United States, specifically the Appalachian Basin, which is highly fragmented and not dominated by any single producer. We believe that competition among producers is based primarily on acreage position, drilling and operating costs as well as pipeline transportation availability to the various markets. CNX competes with other large producers, as well as a myriad of smaller producers and marketers. CNX also competes for pipeline capacity and other services to deliver its products to customers.

Non-Core Mineral Assets and Surface Properties

CNX owns significant natural gas assets that are not in our short-term or medium-term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures or a combination of the foregoing in order to bring the value of these assets forward for the benefit of our shareholders. We also control a significant amount of surface acreage. This surface acreage is valuable to us in the development of the gathering system for our Shale production. We also derive value from this surface control by granting rights of way or development rights to third-parties when we are able to derive appropriate value for our shareholders.

~~Water Division~~

Human Capital Management

AtAs of December 31, ~~2020,~~2021, CNX had ~~451~~441 employees, none of whom are subject to a collective bargaining ~~agreement.~~agreements. CNX recognizes that our future success depends on the expertise and services of our key employees. CNX is ~~emphatic about~~firmly committed to the health and safety of not only our employees and service providers, but also the communities in which ~~we operate.~~CNX operates.

Training and Education.CNX has a variety of ~~programs~~initiatives dedicated to ensuring our employee and contractor workforce are appropriately trained and aligned on expectations regarding safety and environmental performance. These programs utilize behavior-based techniques which embrace a ~~partnership among~~collaboration between management, employees, and the service provider workforce to continually focus attention and actions on appropriate daily safety ~~behavior.~~behaviors. This is accomplished through an evergreen approach with constant evaluation and adaptation for ~~employee,~~workforce, safety, and business ~~needs.~~objectives. Fundamentally, ~~the~~ daily on-site safety meetings, job safety analyses (JSA) and ~~empowerment~~the universal expectation for any employee or contractor to stop work if a risk is identified help foster a ~~culture of~~cultural focus on Health, Safety, and Environmental (HSE) awareness, ~~and accountability embraced~~also known as Operational Excellence. Accountability is an expectation at all levels of ~~CNX;~~ the Company—from individual contributors and service providers to management and executive leadership. In addition to ~~our culture of~~ continual analysis and assessment, CNX ~~expects all~~empowers its employees and ~~service providers~~contractors to ~~meet HSE expectations and CNX empowers our employees to make adjustments~~take corrective action or stop work ~~as needed in order to correct, or prevent,~~immediately if adverse safety or environmental ~~conditions.~~conditions are identified. CNX expects all of ~~our~~its employees and service providers to meet the training requirements outlined by OSHA, and all other ~~governing agencies.~~appropriate regulatory entities, and to always conduct our daily business consistent with our core values of Responsibility, Ownership and Excellence. CNX also provides the opportunity for all employees to obtain certification in First Aid, CPR, and AED administration. The Company’s safety training content is published on ~~the~~its corporate website to ~~allow~~afford service providers ~~constant~~ready access to CNX’s ~~message~~ expectation of individual empowerment and accountability.

Diversity and Inclusion.CNX values diversity throughout the organization. ~~We recognize~~The Company knows that a diverse, ~~extensive talent pool provides~~talented team working together in an inclusive culture is key to achieving long-term goals. In addition to prioritizing diversity within recruiting and hiring practices, CNX also believes in cultivating a culture sensitive to the ~~best~~importance of diversity in the workplace. In 2021, the Company provided Diversity and Inclusion training which was completed by 100% of its employee population. This course combined scenarios, personal interviews, discussion and exploration questions, exercises, and instruction content. Employees were exposed to potential cultural experiences of individuals with identities that may be different from their own, and had the opportunity to ~~acquire unique perspectives, experiences, ideas~~learn how others may experience the same workplace in very disparate ways. CNX intends to continue and ~~solutions that~~expand Diversity and Inclusion training in 2022. Finally, a Diversity & Inclusion Advisory Council and cross-training rotational program for diverse employees were established to help ~~drive our business forward. Though no significant hiring occurred during an extraordinary 2020, we replaced a departing Section 16 officer with a diverse candidate, maintaining 30 percent~~support and augment the Company’s broader talent management and diversity ~~within our executive management team, the highest proportion among our peer group. Of the limited new hires in 2020, 38 percent were diverse.~~goals.

Employee Attraction and Retention.CNX recognizes the importance of attracting and retaining top talent to help drive the ~~best employees~~Company’s strategy forward. The Company is committed to ~~make the most~~attracting, developing, engaging, retaining, and rewarding a diverse team of its assets. While there is great talent in the current pool of industry workers, CNX sees the value in tapping into the potential of recent graduates within the region as well. In recent years, CNX has gonehighly skilled individuals dedicated to ~~great lengths to establish relationships with local colleges~~accountability, fairness, and ~~universities, increasing interest in our organization and industry amongst upcoming graduates.~~respect. The continued success of CNX is not only contingent upon seeking out the best possible candidates, but, more importantly, retaining and developing the ~~talent that lies within the organization as well.~~Company’s existing talent. CNX is proud to offer opportunities for employees to improve their skills toand help achieve ~~their~~individual career goals, including continuing education assistance and professional development for employees pursuing advanced education, certifications, or skill building. Goal attainment and outstanding achievements contribute to the year-end discretionary incentive pay awarded to employees that perform above expectations. Additionally, our Human Resources department retains personalized career development plans for every CNX employee aimed at outlining career goals and paths to reach those goals, as well as career ladders to outline growth paths for each role in the organization.

Quality Management ~~Systems~~.Systems. CNX is committed to fostering a culture of accountability and continuous ~~improvement. In 2019, CNX began~~improvement through the ~~implementation~~utilization of a ~~new~~ Quality Management System (QMS), which strengthens accountability across the enterprise, and reinforces our core values of Responsibility, Ownership, and Excellence. ~~The~~ QMS provides all employees, visitors, contractors and subcontractors who operate on our behalf with a practical, easily accessible system that defines clear expectations, responsibilities and standards that provide the basis of accountability for quality and excellence in all aspects of our business. ~~The Quality Management System~~QMS allows for continual identification, development of documentation control, and standardization of all processes and procedures throughout the organization. ~~The QMS includes CNX’s robust ISO (International Organization of Standardization) conforming Health and Safety, and Environmental Management Systems.~~ The elements of health, safety, environmental and quality control are housed in a unified system that allows for widespread utilization and measurement. ~~By taking ownership of our actions,~~ CNX has formalized our approach in these areas to deliver results that are consistently safe, predictable and environmentally responsible. CNX will conduct regular internal and external audits to ensure compliance, adherence to best-in-class processes and continuous improvement, as we relentlessly strive to be the most responsible and

efficient operator in the industry. CNX’s management expectation is that ~~the~~ QMS will serve as the platform through which the senior leadership manages and measures excellence in all operational aspects.

Health and ~~Safety~~Safety. . No job or activity is considered a success if ~~we compromise~~CNX compromises the safety of ~~our employees.~~its employees and contractors. Everyone working at CNX locations is empowered to stop work if they feel their safety or that of a coworker is at

risk. CNX’s approach to employee stop work empowerment, while reactive when necessary, includes proactive measures such as procedural enhancements and communication. ~~We promote~~CNX promotes empowerment through new employee on-boarding, CNX Hazard Training compliance, and ~~reinforcement, including an~~verification of contractor training and short service employee ~~recognition~~(SSE) program. Our safety professionals provide support throughout all phases of operation with education, training, policy development, audits and emergency preparedness and response. The evaluation of our health and safety performance is an ongoing, daily discussion. Key performance indicators are constantly monitored and analyzed for trends across operations. As trends are identified, CNX utilizes the information to amend policies, training and company-wide communication. The safety department, referred to as Operational Excellence, falls under the direction of the Chief Excellence Officer. The team takes a hybrid approach where a traditional safety group has been merged with an operation field compliance team to form the Operational Excellence department. The Vice President Operational Excellence briefs the Chief Excellence Officer on safety related issues, policy updates and performance trends regularly. Additionally, Operations executive management is kept up to date on safety-related items during weekly scheduled meetings. The ~~HSE~~Environmental, Safety and Corporate Responsibility (ESCR) Committee of the Board of Directors is kept apprised of safety related matters as needed and with monthly updates and quarterly meetings. CNX employs safety and health professionals with a variety of safety certifications such as ~~occupational health nurses, emergency medical technicians~~an Occupational Health Nurse, Emergency Medical Technicians and ~~emergency medical responders.~~Emergency Medical Responders.

Emergency Preparedness and ~~Response~~.Response. Emergency response plans are developed for all CNX locations and operations. The plans are reviewed for effectiveness biannually and are communicated to affected employees through safety meetings and training. Drills and emergency exercises are conducted to ensure all employees understand their roles and responsibilities during an actual event. These exercises range from tabletop exercises to internal drills, up to and including events involving external resources. CNX ~~works hand-in-hand~~actively engages with local municipalities and emergency responders to ensure they are ~~fluent in~~aware of our plan and procedures. CNX provides emergency responder training to volunteer fire departments, and county emergency management, including tours of various phases of operation they may encounter during an event.planned activities. This helps to familiarize emergency response resources with CNX personnel, facilities and operations. This proactive approach gives emergency responders the opportunity to ask questions and understand CNX protocols so they are prepared in the case of an emergency.

Industry Segments

Financial information concerning industry segments, as defined by GAAP, for the years ended December 31, 2021, 2020 ~~2019~~ and ~~2018~~2019 is included in Note 21 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K and is incorporated herein by reference.

Laws and Regulations

General

Our operations are subject to various federal, state and local (including county and municipal level) laws and regulations, with a heavy emphasis placed on compliance with environmental laws and regulations as a result of the nature of our business. These laws and regulations cover virtually every aspect of our operations including, among other things: transportation and use of public roads; construction of well pads, impoundments, tanks and roads; pooling and unitizations; water withdrawal and procurement for well stimulation purposes; well drilling, casing and hydraulic fracturing; stormwater management; well production; well plugging; venting or flaring of natural gas; pipeline construction and the compression and transmission of natural gas and liquids; reclamation and restoration of properties after natural gas operations are completed; handling, storage, transportation, treatment and disposal of materials used or generated by natural gas operations; the calculation, reporting and payment of taxes on gas production; and gathering of natural gas production. In addition to a variety of laws and regulations governing our natural gas operations, ~~we are~~CNX is also subject to laws and regulations with respect to our employees, including health and safety regulations, and various financial and regulatory laws and regulations relating to our status as a public company, and our participation in derivative markets.

Additionally, the electric power generation industry, which consumes significant quantities of natural gas, remains subject to extensive regulation regarding the environmental impact of its power generation activities, which could impact demand for our natural gas.

In 2010, Congress adopted comprehensive financial reform legislation that established federal oversight and regulation of the OTC derivative market and entities, such as the Company, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. The CFTC has adopted and implemented final rules that impose regulatory obligations on all market participants, including the Company, such as recordkeeping, certain reporting obligations and other regulations relevant to natural gas hedging activities. However, it is still not possible at this time

to predict the full extent of the impact of the regulations on the Company's hedging program or regulatory compliance obligations.

~~We endeavor~~CNX endeavors to conduct our natural gas and midstream operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions, exceedances and violations of permits and other regulatory requirements during operations can and do occur. Such exceedances and violations generally result in fines or penalties but could also make it more difficult for us to obtain necessary permits in the future. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or on our customers' ability to use our natural gas and may require us or our customers to change our or their operations significantly or incur substantial costs. See “Risk Factors -- Existing and future governmental laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations” for additional discussion regarding additional laws and regulations affecting our business, operations and industry.

The Company anticipates that compliance with existing laws and regulations governing the Company and its current operations will not have a material adverse effect upon its capital expenditures, earnings or competitive position. Additional proposals that affect the oil and natural gas industry are regularly considered by Congress, the states, regulatory agencies and the courts. The Company cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on the Company.

Environmental Laws

Many of the laws and regulations referred to above are state-level environmental laws and regulations, which vary according to the state where ~~we are~~CNX is operating. Our natural gas and midstream operations are also subject to numerous federal ~~level~~ environmental laws and regulations.

In addition to routine reviews and inspections by regulators to confirm compliance with applicable regulatory requirements, CNX has established protocols for ongoing assessments to identify potential environmental exposures. These assessments take into account industry and internal best management practices and evaluate compliance with laws and regulations and include reviews of our third-party service providers, including, for instance, waste management transporters and related facilities.

Hydraulic Fracturing Activities. Hydraulic fracturing is typically regulated by state oil and natural gas commissions and similar agencies, but the U.S. Environmental Protection Agency ~~(“EPA”)~~(EPA) has asserted certain regulatory authority over hydraulic fracturing and has moved forward with various regulatory actions, including the issuance of regulations requiring green completions for hydraulically fractured wells, and has disclosed its intent to develop regulations to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Some states, including states in which ~~we operate,~~CNX operates, have adopted regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. Additionally, these and other federal requirements and proposals may be subject to further review and revision by the EPA.

Scrutiny of hydraulic fracturing activities also continues in other ways at the federal and local levels. For example, in June 2015, the EPA issued its draft report on the potential impacts of hydraulic fracturing on drinking water and groundwater. The draft report found no systemic negative impacts from hydraulic fracturing. In December 2016, the EPA released its final report on the impacts of hydraulic fracturing on drinking water. While the language was changed and included the possibility of negative impacts from hydraulic fracturing, it also included the guidance to industry and regulators on how the process can be ~~performed safely. We~~performed. CNX cannot predict whether any other legislation or regulations will be enacted and, if so, what its provisions will be.

Clean Air Act. The federal Clean Air Act and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. Various activities in our operations are subject to air quality regulation, including pipeline compression, venting and flaring of

natural gas and hydraulic fracturing and completion processes, as well as fugitive emissions from operations. ~~We obtain~~CNX obtains permits, typically from state or local authorities, to conduct these activities. Additionally, ~~we are~~CNX is required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. Further, some states and the federal government have proposed that emissions from certain proximate and related sources should be aggregated to provide for regulation and permitting of a single, major source. Federal and state governmental agencies continue to investigate the potential for emissions from oil and natural gas activities and further regulation could increase our cost or temporarily restrict our ability to produce.

For example, the EPA sets National Ambient Air Quality Standards for certain pollutants and changes to such standards could cause us to make additional capital expenditures or alter our business operations in some manner. See “Risk Factors - Climate change risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities” for additional discussion regarding certain laws and regulations related to air emissions and related matters.

Clean Water Act. The federal Clean Water Act ~~(“CWA”)~~(CWA) and corresponding state laws affect our natural gas operations by regulating storm water or other regulated substance discharges, including pollutants, sediment and spills and releases of oil, brine and other substances, into surface waters (and under some state statutory schemes groundwater) and in certain instances imposing requirements to dispose of produced wastes and other oil and natural gas wastes at approved disposal facilities. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers, or a delegated state agency. These permits require regular monitoring and compliance with effluent limitations and reporting requirements and govern the discharge of pollutants into regulated waters. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. See “Risk Factors -Environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities” for additional discussion regarding certain laws and regulations related to clean water, the disposal or use of water and related matters.

Endangered Species Act. The Endangered Species Act and related state laws and regulation protect plant and animal species that are threatened or endangered. Some of our operations are located in areas that are or may be designated as protected habitats for endangered or threatened species, including the Northern Long-Eared and Indiana bats, which has a seasonal impact on our construction activities and operations. New or additional species that may be identified as requiring protection or consideration may lead to delays in permits and/or other restrictions on construction and development.

Safety of Gas Transmission and Gathering Pipelines. Natural gas pipelines serving our operations are subject to regulation by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration ~~(“PHMSA”)~~(PHMSA) pursuant to the Natural Gas Pipeline Safety Act of 1968, ~~(“NGPSA”)~~(NGPSA), as amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 ~~(“PSIA”)~~(PSIA), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of ~~2011 (the “2011 Pipeline Safety Act”).~~2011. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas. Additionally, certain states, such as West Virginia, also maintain jurisdiction over intrastate natural gas lines. These statutes and related regulations may be revised or amended which may lead to additional safety requirements. See “Risk Factors -- CNX may incur significant costs and liabilities as a result of pipeline operations and/or increases in the regulation of natural gas gathering pipelines” for additional discussion regarding gas transmission and gathering pipelines.

Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulations affect natural gas operations by imposing requirements for the management, treatment, storage and disposal of hazardous and non-hazardous wastes, including wastes generated by natural gas operations. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective action orders issued by the EPA that could adversely affect our financial results, financial condition and cash flows. On December 28, 2016 the EPA entered into a consent order to resolve outstanding litigation brought by environmental and citizen groups regarding the applicability of RCRA to wastes from oil and gas development activities. In April 2019, the EPA issued a report pursuant to the consent order concluding that revisions to the federal regulations for the management of exploration and production wastes under RCRA were not necessary at the time the report was issued. WeCNX cannot predict whether the EPA may change its conclusion at some point, or whether any other legislation or regulations will be enacted and if so, what its provisions will be.

Federal Regulation of the Sale and Transportation of Natural Gas

Federal Energy Regulatory Commission. Regulations and orders issued by the Federal Energy Regulatory Commission (FERC) impact our natural gas business to a certain degree. Although the FERC does not currently directly regulate our natural gas production activities, the FERC has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the FERC has jurisdiction over the transportation of natural gas in interstate commerce, and regulates the terms, conditions of service and rates for the interstate transportation of our natural gas production. The FERC possesses regulatory oversight over natural gas markets, including anti-market manipulation regulation. The FERC has the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties for violations of the Natural Gas Act or the FERC’s regulations and policies thereunder.

Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from regulation by the FERC. However, the distinction between federally unregulated gathering facilities and FERC-regulated transmission facilities is a fact-based determination, and the classification of such facilities may be the subject of dispute and, potentially, litigation. ~~We own~~CNX owns certain natural gas pipeline facilities that ~~we believe~~CNX believes meet the traditional tests which the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.

Natural gas prices are currently unregulated, but Congress historically has been active in the area of natural gas regulation. WeCNX cannot predict whether new legislation to regulate natural gas sales might be enacted in the future or what effect, if any, any such legislation might have on our operations.

Health and Safety Laws

Occupational Safety and Health Act. Our natural gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) and comparable state laws in some states, all of which regulate health and safety of employees at our natural gas operations. Additionally, OSHA's hazardous communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state laws and regulations require that information be maintained about hazardous materials used or produced by our natural gas operations and that this information be provided to employees, state and local governments and the public.

Climate Change Laws and Regulations

Climate change continues to be aan area of legislative and regulatory focus. There are a number of proposed and final laws and regulations ~~that~~intended to limit greenhouse gas emissions, and regulations that restrict emissions could increase our costs should the requirements necessitate the installation new equipment or the purchase of emission credits or allowances. These laws and regulations could also impact our customers, including the electric generation industry, making alternative sources of energy more competitive. Additional regulation could also lead to permitting delays and additional monitoring and administrative requirements, as well as to impacts on electricity generating operations. See “Risk Factors - ~~Regulation~~Climate change risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities” for additional discussion regarding certain laws and regulations related to climate change, greenhouse gas and related matters.

Title to Properties

CNX acquires ownership or leasehold rights to oil and natural gas properties prior to conducting operations on those properties. The legal requirements of such ownership or leasehold rights generally are established by state statutory or common law. As is customary in the natural gas industry, ~~we have~~CNX has generally conducted only a summary review of the title to oil and gas rights that are not yet in our development plans, but which ~~we believe we control.~~CNX believes it controls. This summary review is conducted at the time of acquisition or as part of a review of our land records. Prior to the commencement of development operations on natural gas and CBM properties, ~~we conduct~~CNX conducts a thorough title examination and perform curative work with respect to significant title defects. Our discovering title defects which ~~we are~~CNX is unable to cure may adversely impact our ability to develop those properties and weCNX may have to reduce our estimated gas reserves including our proved undeveloped reserves. In accordance with the foregoing, ~~we have~~CNX has completed title work on substantially all of our natural gas and CBM properties that are currently producing and believe that ~~we have~~CNX has satisfactory title to our producing properties in accordance with standards generally accepted in the industry. See “Risk Factors - WeCNX may incur losses as a result of title defects in the properties in which ~~we invest~~CNX invests or the loss of certain leasehold or other rights related to our midstream activities.”

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act, are filed with the Securities and Exchange Commission (the SEC). ~~We are~~CNX is subject to the informational requirements of the Exchange Act, and we file or furnish reports, proxy statements and other information with the SEC. Such reports and other information ~~we file~~CNX files with the SEC are available free of charge at our website www.cnx.com when such reports are available on the SEC’s website. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at ~~www.sec.gov.~~www.sec.gov. CNX periodically provides other information for investors on corporate website, including press releases and other information about financial performance, information on corporate governance and presentations. Our references to website URLs are intended to be inactive textual references only. The information found on, or that can be accessed from or that is hyperlinked to, our website does not constitute part of, and is not incorporated into, this Form 10-K.

Information About Our Executive Officers

Incorporated by reference into this Part I is the information set forth in Part III. Item 10 under the caption “Information About Our Executive Officers” (included herein pursuant to Item 401(b) of Regulation S-K).

Risk Factors Summary

The following is a summary of the principal risks that could adversely affect our business, operations and financial results. Please refer to Item 1A “Risk Factors” of this Form 10-K below for additional discussion of the risks summarized in this Risk Factors Summary.

Risks Related to Economic Conditions and our Industry

•Prices for natural gas and NGLs are volatile and ~~an extended decline in the prices we receive~~can fluctuate widely based upon a number of factors beyond our control, including supply and demand for our ~~natural gas and NGLs will adversely affect our business, operating results, financial condition and cash flows.~~products.

•If natural gas prices decrease or drilling efforts are unsuccessful, weCNX may be required to record write-downs of our proved natural gas properties.

•Competition and consolidation within the natural gas industry may adversely affect our ability to sell our products and midstream services or other parts of the business.

•Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions may have a material adverse effect on our liquidity, results of operations, business and financial condition that CNX cannot predict.

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

•Negative public perception regarding our ~~company~~Company or industry and changing investor sentiment towards climate change and fossil fuels could have an adverse effect on our operations, financial results or stock price.

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

•Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.

Risks Related to our Business Operations

•The disruption of, capacity constraints in, or proximity to pipeline and processing systems could limit sales of our natural gas and NGLs and cash flows from operations, and any decrease in availability of pipelines or other midstream facilities could adversely affect our operations.

•Uncertainties exist in the estimation of economical recovery of ~~natural gas~~oil and natural gas ~~liquid~~ reserves.

•Developing, producing, and operating natural gas wells is a high-risk activity, and is subject to operating risks and hazards that could increase expenses, decrease our production levels and expose us to losses or liabilities.

•Our identified ~~drilling~~development locations are scheduled over multiple future years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their actual development.

•Our ~~development and exploration projects, as well as our midstream development~~capital projects require substantial capital expenditures and are subject to regulatory, environmental, political, legal and economic ~~risks.~~risks and if CNX fails to generate sufficient cash flow, obtain required capital or financing on satisfactory terms or respond to regulatory and political developments, our natural gas reserves may decline and our operations and financial results may suffer.

•CNX may not be able to obtain required personnel, services, equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our operations.

•If CNX cannot find adequate sources of water for our use or ~~we are~~CNX is unable to dispose of or recycle water produced from our operations at a reasonable cost and within applicable environmental rules, our ability to produce natural gas economically and in sufficient quantities could be impaired.

•Failure to successfully replace our current natural gas, NGL and ~~natural gas liquid~~oil reserves through economic development of our existing or acquired assets or through acquisition of additional producing assets, would lead to a decline in our natural gas, NGL and ~~natural gas liquid~~oil production levels and reserves.

•WeCNX may incur losses as a result of title defects in the properties in which ~~we invest~~CNX invests or the loss of certain leasehold or other rights related to our midstream activities.

Legal, Environmental and Regulatory Risks

•Climate change risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty

concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities.

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

•Existing and future governmental laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations.

•CNX may incur significant costs and liabilities as a result of pipeline operations and/or increases in the regulation of natural gas gathering pipelines.

•Changes in federal or state tax laws focused on natural gas exploration and development could cause our financial position and profitability to ~~deteriorate.~~deteriorate and future tax liability may be greater than anticipated.

•CNX and its subsidiaries are subject to various legal proceedings and investigations, which may have an adverse effect on our business.

Financing, Investment and Indebtedness Risks

•Our current long-term debt obligations, and the terms of the agreements that govern that debt, and the risks associated therewith, could adversely affect our business, financial condition, liquidity and results of operations.

•Our borrowing base under our senior secured credit facility 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.

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

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

•~~We are~~CNX is subject to counterparty performance risk with respect to the capped call transactions.

•Conversion of the Convertible Notes may dilute the ownership interest of existing stockholders or may otherwise depress the price of our common stock.

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

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

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

Risks Related to ~~Strategic Transactions~~our Business Operations

•~~Strategic determinations, including~~The disruption of, capacity constraints in, or proximity to pipeline and processing systems could limit sales of our natural gas and NGLs and cash flows from operations, and any decrease in availability of pipelines or other midstream facilities could adversely affect our operations.

•Uncertainties exist in the ~~allocation~~estimation of economical recovery of oil and natural gas reserves.

•Our identified development locations are scheduled over multiple future years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their actual development.

•Our capital projects require substantial capital expenditures and ~~other resources to strategic opportunities,~~ are subject to regulatory, environmental, political, legal and economic risks and ~~uncertainties.~~

•~~We do not completely control the timing of divestitures that we plan~~if CNX fails to ~~engage in,~~generate sufficient cash flow, obtain required capital or financing on satisfactory terms or respond to regulatory and ~~they~~political developments, our natural gas reserves may ~~not provide anticipated benefits.~~

•~~There is no guarantee that CNX will continue to repurchase shares of~~decline and our ~~common stock under our current or any future share repurchase program at levels undertaken previously or at all.~~operations and financial results may suffer.

•CNX may ~~operate~~not be able to obtain required personnel, services, equipment, parts and raw materials in a ~~portion of~~timely manner, in sufficient quantities or at reasonable costs to support 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.~~operations.

•~~In connection with the separation~~If CNX cannot find adequate sources of water for our use or CNX is unable to dispose of or recycle water produced from our operations at a reasonable cost and within applicable environmental rules, our ability to produce natural gas economically and in sufficient quantities could be impaired.

•Failure to successfully replace our current natural gas, NGL and oil reserves through economic development of our ~~coal business, CONSOL Energy has agreed~~existing or acquired assets or through acquisition of additional producing assets, would lead to ~~indemnify us for~~a decline in our natural gas, NGL and oil production levels and reserves.

•CNX may incur losses as a result of title defects in the properties in which CNX invests or the loss of certain ~~liabilities, and we have agreed~~leasehold or other rights related to ~~indemnify CONSOL Energy for certain liabilities.~~our midstream activities.

~~Other General~~Legal, Environmental and Regulatory Risks

•~~Cyber-incidents targeting~~Climate change risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our ~~systems, oil~~operating costs and reduce the value of our natural gas ~~industry systems~~assets and ~~infrastructure, or the systems of our third party service providers could materially adversely affect our business, financial condition or results of operations.~~such regulation, as well as uncertainty

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concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities.

•~~Our success depends on key members of our management~~Environmental regulations can increase costs and ~~our ability to attract~~introduce uncertainty that could adversely impact the market for natural gas with potential short and ~~retain experienced technical and other professional personnel.~~long-term liabilities.

•~~Terrorist activities could materially adversely affect~~Existing and future governmental laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and ~~results of~~may restrict our operations.

•CNX may incur significant costs and liabilities as a result of pipeline operations and/or increases in the regulation of natural gas gathering pipelines.

~~ITEM 1A.~~•~~Risk Factors~~Changes in federal or state tax laws focused on natural gas exploration and development could cause our financial position and profitability to deteriorate and future tax liability may be greater than anticipated.

•

~~Investment in our securities is~~CNX and its subsidiaries are subject to various ~~risks, including risks~~legal proceedings and uncertainties inherent in our business. In addition to the other information contained in this Form 10-K, the following risk factors related to our business, operations, investments, financial position or future financial performance or cash flows should be considered in evaluating our company. If any of the following risks were to occur, it could cause an investment in our securities to decline and result in a loss.

~~Risks Related to Economic Conditions and our Industry~~

Prices for natural gas and NGLs are volatile and can fluctuate widely based upon a number of factors beyond our control. An extended decline in the prices we receive for our natural gas and NGLs will adversely affect our business, operating results, financial condition and cash flows.

Our financial results are significantly affected by the prices we receive for our natural gas and NGLs. Natural gas, NGLs, oil and condensate prices are very volatile and can fluctuate widely based upon supply from energy producers relative to demand for these products and other factors beyond our control. In particular, the U.S. natural gas industry continues to face concerns of oversupply due to the success of domestic shale development, associated natural gas produced by oil producers, and other North American shale gas plays that impact domestic pricing. The oversupply of natural gas, beginning in 2012, has resulted in depressed domestic prices. Henry Hub average spot prices for 2020 were $1.97 per MMBtu lower than for 2011. Industry drilling has continued in these plays, despite these lower gas prices, as producers continued to become more efficient. Domestic settled natural gas prices have continued to decrease, and continued volatility remains a strong possibility.

~~Our producing properties are geographically concentrated in the Appalachian Basin,~~investigations, which exacerbates the impact of regional supply and demand factors on our business, including the pricing of our natural gas. Not all of the natural gas produced in this region can be consumed by regional demand and must, therefore, be exported to other regions, which causes natural gas produced and sold locally to be priced at a discount to many other market hubs, such as the benchmark Henry Hub price. This discount, or negative basis, to the Henry Hub price is forecasted to continue in future years for Appalachian Basin producers. While we expect planned interstate pipeline projects to reduce this discount, it could widen further if production in the basin continues to grow and these expected projects to move gas out of the basin are cancelled, delayed or denied for any reason, such as permitting and regulatory issues or environmental lawsuits. During 2020, the Atlantic Coast Pipeline project, which was to move produced natural gas out of the northeast, was cancelled by its partners after nearly six years of work. An extended period of lower natural gas prices can reduce cash flow, which decreases funds available for capital expenditures to replace reserves or increase production.

~~Our drilling plans also include some activity in areas of shale formations that~~ may also contain NGLs, condensate and/or oil. The prices for NGLs, condensate and oil are also volatile for reasons similar to those described above, for natural gas. Although the Company is able to hedge natural gas benchmarks and local basis differentials, it has not found acceptable instruments to hedge its relatively minor quantities of NGL, condensate and oil. In addition, similar to the oversupply of natural gas, increased drilling activity by third-parties in formations containing NGLs has led to a significant decline in the price we receive for our NGLs. Further, an oversupply of NGLs in the local market where we operate requires excess NGLs to be transported out of our region and into the broader market, including international exports. NGLs are transported by a variety of methods, including pipeline, rail, and truck. Any disruption in those means of transportation could have a further detrimental impact on the price we receive for our NGLs. Our results of operations may be adversely affected by a continued depressed level of, or further downward fluctuations in, NGLs, condensate and oil prices.

~~Apart from issues with respect to the supply of products we produce, demand can fluctuate widely due to a number of matters beyond our control, including:~~

•~~weather conditions in our markets that affect the demand for natural gas;~~

•~~changes in the consumption pattern of industrial consumers, electricity generators and residential users of electricity and natural gas;~~

•~~with respect to natural gas, the price and availability of alternative fuel sources used by electricity generators;~~

•~~technological advances affecting energy consumption and conservation measures reducing demand;~~

•~~the costs, availability and capacity of transportation infrastructure;~~

•~~proximity and capacity of natural gas pipelines and other transportation facilities;~~

•~~changes in levels of international demand and tariffs associated with international export; and~~

•~~the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and delays.~~

If natural gas prices decrease or drilling efforts are unsuccessful, we may be required to record write-downs of our proved natural gas properties. Additionally, changes in assumptions impacting management’s estimates of future financial results as well as other assumptions related to the Company's stock price, weighted-average cost of capital, terminal growth rates and industry multiples, could cause goodwill and other intangible assets we hold to become impaired and result in material non-cash charges to earnings.

Lower natural gas prices or wells that produce less than expected quantities of natural gas may reduce the amount of natural gas that CNX can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets at least annually or whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever development plans change with respect to those assets. In the past we have had to record an impairment charge related to certain assets and CNX may incur impairment charges in the future, which could have an adverse effect on our ~~results of operations in the period taken.~~business.

~~For the year ended December 31, 2020, CNX recognized certain indicators of impairments specific to our Southwest Pennsylvania (SWPA) CBM asset group~~Financing, Investment and determined that the carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a result, an impairment of $62 million was recognized and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. The impairment was related to an economic decision to temporarily idle certain CBM wells and the related processing facility during the first quarter of 2020.Indebtedness Risks

~~Future acquisitions may lead to~~•Our current long-term debt obligations, and the acquisition of additional goodwill or other intangible assets. At least annually, or whenever events or changes in circumstances indicate a potential impairment in the carrying value as defined by GAAP, we will evaluate this goodwill and other intangible assets for impairment by first assessing qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair valueterms of the ~~reporting unit is less than~~agreements that govern that debt, and the carrying amount. Estimated fair values could change if, for example, there are changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market capitalization. The future impairment of these assets could require material non-cash charges to our results of operations, which could materially adversely affect our reported earnings and results of operations for the affected periods.

Competition and consolidation within the natural gas industry may adversely affect our ability to sell our products and midstream services or other parts of the business. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our products, which could impair our profitability.

The natural gas, exploration, production and midstream industries are intensely competitive with companies from various regions of the United States, and increasingly face competition in international markets. The industry has been experiencing increased competitive pressures as a result of both consolidation within the exploration and production space, along with the continued proliferation of stand-alone midstream companies. Midstream, transmission and processing consolidation in the industry could lead to a less competitive environment for CNX to find partners for projects needed to support development, which could increase costs. Many of the companies with which we compete are larger and if we are unable to compete, our company, our operating results, financial position or other parts of the business. may be adversely affected. In addition, we compete with larger companies to acquire new natural gas properties for future exploration, limiting our ability to replace the natural gas we produce or to grow our production. There is also increased competition within the industry as a result of oil-focused drilling, where natural gas is produced as an ancillary byproduct and may be sold at prices below market. Some of such “byproduct” gas could be transported to our key markets, thereby affecting regional supply. The industry also faces competition from alternative energy sources. The highly competitive environment in which we operate may negatively impact our ability to acquire additional properties at prices or upon terms we view as favorable. Any reduction in our ability to compete in current or future natural gas markets could materially adversely affect our business, financial condition, results of operations and cash flows.

In addition, potential third-party customers who are significant producers of natural gas and condensate may develop their own midstream systems in lieu of using our systems. All of these competitive pressures could materially adversely affect our business, results of operations, financial condition and cash flows.

Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions may have a material adverse effect on our liquidity, results of operations, business and financial condition that CNX cannot predict.

Economic conditions in a number of industries in which our customers operate, such as electric power generation, have experienced substantial deterioration in the past, resulting in reduced demand for natural gas. Renewed or continued weakness in the economic conditions of any of the industries we serve or that are served by our customersrisks associated therewith, could adversely affect our business, financial condition, liquidity and results of ~~operation and liquidity in a number of ways. For example:~~

operations.

•~~demand~~Our borrowing base under our senior secured credit facility could decrease for a variety of reasons including lower natural gas ~~and electricity~~prices, declines in ~~the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our~~ natural gas ~~business;~~proved reserves, asset sales and lending requirements or regulations.

•~~A decrease in international demand~~The accounting method for ~~natural gas or NGLs produced in the United States could adversely affect the pricing for such products, which could adversely affect our results of operations and liquidity;~~

•the tightening of credit or lack of credit availability to our customers could adversely affect our liquidity, as our ability to receive payment for our products sold and delivered depends on the continued creditworthiness of our customers;

•~~our ability to refinance our existing senior notes~~convertible debt securities that may be ~~limited and the terms on which we are able to do so may be less favorable to us depending on the strength of the capital markets, our credit ratings;~~

•our ability to access the capital markets may be restricted at a time when CNX would like, or need, to raise capital for our business including for exploration and/or development of our natural gas reserves; and

•~~a decline~~settled in ~~our creditworthiness may require us to post letters of credit,~~ cash, ~~collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.~~

In addition, the 2020 outbreak of the coronavirus pandemic (COVID-19) has materially and adversely impacted many businesses, industries and economies. For further detail regarding the risks to our business resulting from COVID-19, see Risk Factor titled “Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.”

~~Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.~~

To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expected production. As of January 7, 2021, we expect these transactions will represent approximately 472.1 Bcf of our estimated 2021 production at an average price of $2.50 per Mcf, 391.3 Bcf of our estimated 2022 production at an average price of $2.34 per Mcf, 284.8 Bcf of our estimated 2023 production at an average price of $2.22 per Mcf, 263.1 Bcf of our estimated 2024 production at an average price of $2.28 per Mcf, and 103.0 Bcf of our estimated 2025 production at an average price of $2.10 per Mcf. To the extent that we engage in hedging activities, CNX may be prevented from realizing the near-term benefits of price increases above the levels of the hedges. If we choose not to engage in or otherwise reduce our future use of hedging arrangements or are unable to engage in hedging arrangements due to lack of acceptable counterparties, CNX may be more adversely affected by changes in natural gas prices than we have historically performed, and then our competitors who engage in hedging arrangements to a greater extent than we do. Increases or decreases in forward market prices could result in material unrealized (non-cash) losses or gains on commodity derivative instruments resulting in volatility in reported earnings. Future legislation regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risks associated with our business.

~~In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:~~

•~~our production is less than expected;~~

•~~market prices for natural gas rise significantly in excess of our derivative hedge price resulting in significant cash payments to our hedge counterparties;~~

•~~we are unable to find available counterparties in the future with which to enter into hedges and counterparties able to enter into basis hedge contracts;~~

•~~the creditworthiness of our counterparties or their guarantors is substantially impaired; and~~

•~~counterparties have credit limits that may constrain our ability to hedge additional volumes.~~

~~Negative public perception regarding our Company or industry could have an adverse effect on our operations, financial results or stock price.~~

Negative public perception regarding our Company or industry resulting from, among other things, operational incidents or concerns raised by advocacy groups, related to environmental, health, or community impacts could result in increased regulatory scrutiny, which could then result in additional laws, regulations, guidelines and enforcement interpretations, at the federal or state level. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and an increased risk of litigation that may negatively impact our future financial results or our stock price. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

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

While CNX did not incur significant disruptions to operations during the year ended December 31, 2020 as a direct result of the COVID-19 pandemic. The outbreak of the coronavirus pandemic (COVID-19) may materially and adversely affect, our business, operating and financial results and liquidity in the future. The severity, magnitude and duration of the current COVID-19 outbreak and the efforts to reduce its spread remain uncertain, but continues to be rapidly changing and hard to predict. While the full impact of this virus and the long-term worldwide reaction to it and impact from it remains unknown at this time, government reaction to the pandemic and restrictions and limitations applied by the government as a result, continued widespread growth in infections, travel restrictions, quarantines, or site closures as a result of the virus could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, lead to disruptions in our supply chain (including necessary contractors and materials), lead to a disruption in our resource acquisition or permitting activities and cause disruption in our relationship with our customers. Additionally, the COVID-19 outbreak has significantly impacted economic activity and markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:

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

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

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

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

for natural gas, LNG, NGLs, oil and condensate, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic. Any of these outcomesConvertible Notes, could have a material ~~adverse~~ effect on our ~~business, operations,~~reported financial ~~results~~results.

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

•CNX is subject to counterparty performance risk with respect to the capped call transactions.

•Conversion of the Convertible Notes may dilute the ownership interest of existing stockholders or may otherwise depress the price of our common stock.

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

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

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

Risks Related to our Business Operations

~~Our business depends on gathering, processing and transportation facilities and other midstream facilities owned by others.~~ •The disruption of, capacity constraints in, or proximity to pipeline and processing systems could limit sales of our natural gas and NGLs and cash flows from operations, and any decrease in availability of pipelines or other midstream facilities could adversely affect our operations.

•

Although we own midstream facilities, we also gather, process and transport our natural gas to market by utilizing processing facilities and pipelines owned by others. If pipeline or processing facility capacity is limited or is unexpectedly disrupted for any reason, our sales of natural gas and/or NGLs could be reduced, which could negatively affect our profitability. If we cannot access processing facilities and pipeline transportation, we may have to reduce our production of natural gas, reducing our sales and revenues, and causing our unit costs to increase. If pipeline quality standards change or we cannot meet applicable standards, we might be required to install additional processing equipment which could increase our costs. Pipelines could also curtail our flows until the natural gas delivered to their pipeline is in compliance with predetermined gas quality specifications. Any reduction in our production of natural gas or increase in our costs could materially adversely affect our business, financial condition, results of operations and cash flows.

Further, a significant portion of our natural gas is sold on or through two pipeline systems, Texas Eastern Transmission and Columbia Gas Transmission, which could experience capacity issues, operational disruptions and unexpected downtime, with either no or little alternative transportation options are available for our natural gas. Reductions in capacity on the pipelines, which have occurred in the past, may result in curtailments and reduce our production of natural gas. A reduction in capacity on any downstream pipelines could also reduce the demand for our natural gas, which would reduce the price we receive for our production.

We have various third-party firm transportation, natural gas processing, gathering and other agreements in place, many of which have minimum volume delivery commitments that obligate us to pay fees on minimum volumes regardless of actual volume throughput. Reductions in our drilling program may result in insufficient production to utilize our full firm transportation and processing capacity, reducing our cash flow from operations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect our business, financial condition, results of operations and cash flows.

Our investment in midstream infrastructure development and maintenance programs is intended, among other items, to connect our wells to other existing gathering and transmission pipelines and can involve significant risks, including those relating to timing, cost overruns and operational efficiency. Significant portions of our natural gas production are dependent on a small number of key compression and processing stations. An operational issue at any of those stations would materially impact our production, cash flow and results of operation. Our midstream facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, the continuing operation of which is not within our control. These third-party pipelines and facilities may become unavailable because of testing, turnarounds, line repair, maintenance, changes to operating conditions, delivery or receipt parameters, unavailability of firm transportation, lack of operating capacity, force majeure events, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.

Uncertainties exist in the estimation of economical recovery of ~~natural gas and natural gas liquid reserves. With these uncertainties, estimates of revenues, operating and development costs and profitability may be inaccurate.~~

Natural gas reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of development and production. Reserves require estimates of underground accumulations of oil and natural gas and the use of assumptions concerning natural gas and natural gas liquid prices, production levels, recoverable reserve quantities and operating and development costs. For example, a significant amount of our proved oil and natural gas reserves are identified as proved undeveloped reserves and may be more susceptible to positive and negative changes in reserve estimates than our proved developed reserves. A portion of the proved undeveloped reserves booked during the last ten years were due to the addition of undeveloped wells on our Shale acreage more than one offset location away from existing production through the use of reliable, industry standard applications. Also, we make certain assumptions regarding natural gas and liquids prices, production levels and operating and development costs that may prove to be incorrect. Any significant

variance from these assumptions to actual figures could greatly affect our estimates of our natural gas and natural gas liquid reserves, the economically recoverable quantities of natural gas and natural gas liquids attributable to any particular group of properties, the classifications of natural gas reserves based on risk of recovery and estimates of the future net cash flows. The PV-10 measure of pre-tax discounted future net cash flows and the standardized measure of after-tax discounted future net cash flows from our proved reserves included within this Annual Report on Form 10-K are not necessarily the same as the current market value of our estimated natural gas and liquid reserves. We base the estimated discounted future net cash flows from our proved natural gas and natural gas liquid reserves on historical average prices and costs. However, actual future net cash flows from our proved and unproved natural gas and natural gas liquid properties may also be affected by factors such as:

•~~geological conditions;~~

•~~our acreage position, and our ability to acquire additional acreage, including purchases and third-party swaps to develop our position efficiently;~~

•~~changes in governmental regulations and taxation;~~

•~~the amount and timing of actual production;~~

•~~future prices and our hedging position;~~

•~~future operating costs;~~

•~~operational risks and results; and~~

•~~capital costs of drilling, completion and gathering assets.~~

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and natural gas liquid properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved natural gas reserves as of December 31, 2020 would decrease from $3.60 billion to $3.33 billion.

Developing, producing, and operating natural gas wells is a high-risk activity, and is subject to operating risks and hazards that could increase expenses, decrease our production levels and expose us to losses or liabilities.

Our financial results are materially dependent upon the success of our development program. The development of natural gas involves numerous risks, including the risk that an encountered well does not produce in sufficient quantities to make the well economically viable. The cost of drilling, completing and operating wells is substantial and uncertain, and our operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control. Our future development activities may not be successful, and if they are unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. CNX may be unable to development identified or budgeted wells within our expected time frame, or at all for various reasons, and a final determination with respect to the development of any scheduled or budgeted wells will be dependent on a number of factors, including:

•~~the results of delineation efforts and the acquisition, review and analysis of data, including seismic data;~~

•~~the availability of sufficient capital resources to us and any other participants in a well for the development of the well;~~

•~~whether we are able to acquire on a timely basis all of the leasehold interests required for the well, including through swap transactions with other operators;~~

•~~whether we are able to obtain, on a timely basis or at all, the permits required for the development of wells;~~

•~~whether production levels align with estimates; and~~

•~~economic and industry conditions at the time of development, including prevailing and anticipated prices for natural gas and oil and the availability and cost of oilfield services.~~

Our business strategy focuses on horizontal drilling and production in unconventional shale formations, primarily the Marcellus Shale and Utica Shale in the Appalachian Basin. Drilling and stimulating horizontal wells is technologically complex, expensive and involves a higher risk of failure when compared to vertical wells. Due to the higher costs, the risks of our development program are spread over a smaller number of wells, and in order to be profitable, each horizontal well will need to produce at higher levels. In addition, we use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad, or a single well could adversely affect production from all of the wells on the pad. Pad development can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we are better served by drilling horizontal wells using multi-well pads, the risk component involved in such development will be increased in some respects, with the result that CNX might find it more difficult to achieve economic

~~success in our development program.~~

The exploration, production, and transporting of natural gas involves numerous operational risks. The cost of developing and operating a shale gas well, a shallow oil and gas well or a coalbed methane (CBM) well is often uncertain, and a number of factors can delay, suspend, or prevent development operations, decrease production and/or increase the cost of our natural gas operations at particular sites for varying lengths of time. The operational factors that are most likely to negatively impact our operations include unexpected development and production conditions (pressure or irregularities in geologic formations or wells, material and equipment failures, fires, ruptures, loss of well control, landslides, mine subsidence, explosions or other accidents and environmental concerns and adverse weather conditions), which conditions and risks may be amplified as we increase the vertical and horizontal length of drilling endeavors; similar operational or design issues relating to pipelines, compressor stations, pump stations, related equipment and surrounding properties; challenges relating to transportation, pipeline infrastructure and capacity for treatment or disposal of waste water generated in operations and failure to obtain, or delays in the issuance of, permits at the state or local level and the resolution of regulatory concerns.

~~The realization of any of these risks could adversely affect our ability to conduct our operations, materially increase our costs, or result in substantial loss to us as a result of claims for:~~

•~~personal injury or loss of life;~~

•~~damage to and destruction of property, natural resources and equipment, including our properties and our natural gas production or transportation facilities;~~

•~~pollution and other environmental damage to our properties or the properties of others;~~

•~~potential legal liability and monetary losses;~~

•~~damage to our reputation within the industry or with customers;~~

•~~regulatory investigations and penalties;~~

•~~suspension of our operations; and~~

•~~repair and remediation costs.~~

The occurrence of any operational event that prevents delivery of natural gas to a customer and is not excusable as a force majeure event under our supply agreement, could result in economic penalties, suspension or ultimately termination of the supply agreement.

Although we maintain insurance for a number of risks and hazards, we may not be adequately insured against the losses or liabilities that could arise from a significant accident or disruption in our operations. The occurrence of an event that is not fully covered by insurance, such as pollution or environmental issues, could materially adversely affect our business, financial condition, results of operations and cash flows.

Our identified development locations are scheduled over multiple future years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their actual development.

•

Our management team has specifically identified and scheduled certain locations as an estimation of our future multi-year development activities on our existing acreage. These locations represent a significant part of our development strategy. Our ability to develop these locations may be dependent on a number of factors, including natural gas and oil prices, the availability and cost of capital drilling and production costs, the acquisition on acceptable terms of any leasehold interests we do not control but that are necessary to complete the drilling unit, including potentially through third-party swap transactions, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors. Because of these uncertain factors, we do not know if the numerous development locations we have identified will ever be drilled. CNX may require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any development activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves or may result in a downward revision of our estimated proved reserves, which could materially adversely affect our business and results of operations.

~~Our development and exploration projects, as well as our midstream development~~ projects require substantial capital expenditures and are subject to regulatory, environmental, political, legal and economic risks and if ~~we fail~~CNX fails to generate sufficient cash flow, obtain required capital or financing on satisfactory terms or ~~deal with the~~respond to regulatory and political ~~environment,~~developments, our natural gas reserves may decline and our operations and financial results may suffer.

•

As part of our strategic determinations, we expect to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves and maintenance, purchase or construction of midstream systems. If we are unable to

make sufficient or effective capital expenditures, we will be unable to maintain and grow our business. The gas gathering agreements that we have with third-parties may impose obligations on us to invest capital in our midstream systems which are not fully protected against volumetric risks associated with lower-than-forecast volumes flowing through our gathering systems. To the extent our customers are not contractually obligated to, and determine not to, develop their properties in the areas covered by these acreage dedications, or otherwise sell, exchange, farm-out or otherwise dispose of all of, or an undivided interest in, the development of the dedicated acreage, the resulting decrease in the development of reserves by our midstream customers could result in reduced volumes serviced by us and a commensurate decline in revenues and cash flows.

Additionally, the construction of additions or modifications to our existing midstream systems involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If these projects are undertaken, they may not be completed on schedule, at the budgeted cost or at all. The construction of additions to our existing assets may require us to obtain new land rights and regulatory permits prior to constructing new pipelines or facilities, which may not be obtained in a timely fashion or in a way that allows us to connect new natural gas supplies to existing gathering pipelines or capitalize on other attractive expansion opportunities. It may also become more expensive to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, cash flows could be adversely affected. Also, these midstream assets may not be able to attract enough throughput to achieve the expected investment return.

Revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. There is no assurance that we will have sufficient cash from operations, borrowing capacity under our credit facilities, or the ability to raise additional funds in the capital markets to meet our capital requirements. If cash flow generated by our operations or available borrowings under our credit facilities are not sufficient to meet our capital requirements, or we are unable to obtain additional financing, we could be required to curtail the pace of the development of our natural gas properties and midstream activities, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

CNX may not be able to obtain required personnel, services, equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our operations.

•

We rely on third-party contractors to provide key services and equipment for our operations. CNX contracts with third-parties for well services, related equipment and qualified experienced field personnel to drill wells, construct pipelines and conduct field operations. We also utilize third-party contractors to provide land acquisition and related services to support our land operational needs. The demand for these services, equipment and field personnel to drill wells, construct pipelines and conduct field operations and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Weather may also play a role with respect to the relative availability of certain materials. Historically, there have been shortages of drilling and work-over rigs, pipe, compressors and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. The costs and delivery times of equipment and supplies are substantially greater in periods of peak demand, including increased demand for plays outside of our area of geographic focus. In addition, accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring increased costs for contractors and/or materials. Accordingly, CNX cannot be assured that we will be able to obtain necessary services, drilling equipment and supplies in a timely manner or on satisfactory terms, and CNX may experience shortages of, or increases in the costs of, drilling equipment, crews and associated supplies, equipment and field services in the future.

Shortages may lead to escalating prices, poor service and inefficient drilling operations and increase the possibility of accidents due to the hiring of less experienced personnel and overuse of equipment by contractors. A decrease in the availability of these services, equipment or personnel could lead to a decrease in our natural gas production levels, increase our costs of natural gas production, and decrease our anticipated profitability. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which events could materially adversely affect our business, financial condition, results of operations, or cash flows.

We attempt to mitigate the risks involved with increased natural gas production activity by entering into “take or pay” contracts with well service providers which commit them to provide field services to us at specified levels and commit us to pay for field services at specified levels even if we do not use those services. However, these types of contracts expose us to economic risk during a downturn in demand or during periods of oversupply. Having to pay for services we do not use decreases our cash flow and increases our costs.

If CNX cannot find adequate sources of water for our use or ~~we are~~CNX is unable to dispose of or recycle water produced from our operations at a reasonable cost and within applicable environmental rules, our ability to produce natural gas economically and in sufficient quantities could be ~~impaired~~.impaired.

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As part of our drilling and production in shale formations, we use hydraulic fracturing processes that require access to adequate sources of water, which may not be available in proximity to our operations or at certain times of the year. To ensure adequate water for our operations, CNX may be required to invest substantial amounts of capital in water pipelines which are used for relatively short periods of time. Increased regulation of these water pipelines could cause us to invest additional capital, alter our disposal or transportation method or affect our operations in other manners. Alternatively, CNX may be required to truck water, and CNX may not be able to contract for sufficient water hauling trucks to meet our needs.

Further, our operations generate significant volumes of wastewater that must be treated, reused or disposed. This waste can be generated from various aspects of our operations, including from drilling fluids, completions activities and normal production over the life of the well, and are associated with all types of natural gas wells, including CBM wells and shale wells. A significant portion of this water can be recycled for use in other hydraulic fracturing operations. To the extent we must dispose of water rather than recycle it, our costs may increase, which will detrimentally affect our cash flows. We attempt to minimize the expense associated with the transportation of wastewater by optimizing the transportation between the sources of wastewater and locations where the wastewater can be reused or disposed. Various interruptions in our planned transportation of this wastewater, including operational issues and regulatory matters, could increase our operating costs, which would detrimentally affect our cash flows. The risk of pollution also exists while handling, transferring, storing and disposing wastewater and other wastes, as well as in development or production of a well.

Our inability to obtain sufficient amounts of water with respect to our Shale operations or to dispose of or recycle water and other wastes produced from our Shale and our CBM operations in an economically efficient manner, could increase our costs and delay our operations, which will adversely impact our cash flow and results of operations.

Failure to successfully replace our current natural gas, NGL and ~~natural gas liquid~~oil reserves through economic development of our existing or acquired assets or through acquisition of additional producing assets, would lead to a decline in our natural gas, NGL and ~~natural gas liquid~~oil production levels and reserves.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline can change if production from our existing wells is different than what has been estimated, operating conditions change or other circumstances arise that affect our ability to produce the wells. Thus, our future natural gas and natural gas liquid reserves and production and, therefore, our cash flow and income are highly dependent on our estimates and our success in efficiently developing and selling our current reserves and economically finding or acquiring additional economically recoverable reserves. CNX may not be able to develop, find or acquire additional economically recoverable reserves to replace our current and future production at acceptable costs.

In addition, the level of natural gas, NGL and condensate volumes handled through our midstream systems depends on the level of production from natural gas wells feeding into such midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, we must supply natural gas, NGLs and condensate from new wells on acreage in close proximity to our midstream systems. This can take the form of wells we develop on our own, wells developed by others on acreage that is dedicated to our midstream systems or through contracts with third-party customers to flow volumes on our midstream systems. We have no control over third party producers’ levels of development and completion activity in areas adjacent to our midstream systems, or the amount of reserves associated with or rate of production decline from those third-party wells – and only limited control over those factors on our own wells•.

WeCNX may incur losses as a result of title defects in the properties in which ~~we invest~~CNX invests or the loss of certain leasehold or other rights related to our midstream activities.

~~It is our practice when we acquire natural gas leases or interests not to conduct a thorough chain of title examination to the mineral interest.~~

Prior to the drilling of a well, however, it is the normal practice in our industry for the operator of the well to obtain a complete title review to ensure there are no obvious defects in title to the well. As a result of such examinations, certain curative work may be required to correct defects in the marketability of the title and such curative work entails expense. Our inability to cure any title defects in our leases in a timely and cost-efficient manner may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial position.

Additionally, most of the land on which our midstream systems have been constructed is not owned in fee by us; rather, the properties are held by surface use agreements, rights-of-way or other easement rights. We are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew the right-of-way or for other reasons, could materially adversely affect our business, financial condition, results of operations and cash flows.

Legal, Environmental and Regulatory Risks

concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities.

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The issue of global climate change continues to attract considerable public and scientific attention with underlying concern about the impacts of human activity, especially the emissions of greenhouse gases (“GHGs”) such as carbon dioxide (“CO2”) and methane, environment, and is increasingly the subject of civil litigation.

The EPA, under the Climate Action Plan, elected to regulate GHGs under the Clean Air Act (“CAA”) to limit emissions of CO2 from natural gas-fired power plants. In April 2017, the EPA announced that it was initiating a review of the Clean Power Plan consistent with President Trump’s Executive Order 13783, and in October 2017 published a proposed rule to formally repeal the Clean Power Plan. On August 20, 2018, the EPA issued the proposed “Affordable Clean Energy Rule.” On June 19, 2019, the EPA issued the final Affordable Clean Energy Rule, replacing the Clean Power Plan. The Biden administration may take a different direction than the Trump administration regarding these regulatory actions. For example, the new administration has announced it will re-enter the United States in the Paris Climate Accord and may attempt to establish more stringent standards to update or replace the Affordable Clean Energy Rule.

The EPA has adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permits for large stationary sources. Facilities requiring PSD permits may also be required to meet “best available control technology” (BACT) standards. Rulemaking related to GHG could alter or delay our ability to obtain new and/or modified air source permits.

The EPA has also adopted, changed and amended rules to control volatile organic compound emissions from certain oil and natural gas equipment and operations as part of its initiative to reduce methane emissions. In response to subsequent judicial involvement, the EPA issued a proposed rule in July 2017 that would stay the methane rule for two years which rule was vacated by the United States Court of Appeals for the D.C. Circuit. Thereafter in September 2018, the EPA proposed revisions to the 2016 New Source Performance Standards for the oil and natural gas industry. Additional revisions were proposed in August 2019 and August 2020. As these proposed rules are adopted, changed, rescinded or modified, these rules may result in increased costs for permitting, equipping, and monitoring methane emissions or otherwise restrict operations or increase the costs thereof.

Additionally, some states have issued mandates to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and potential cap-and-trade programs. For example, Pennsylvania has recently taken initial steps to bring Pennsylvania into a nine-state consortium of Northeastern and Mid-Atlantic States - the Regional Greenhouse Gas Initiative -- that set price and declining limits on CO2 emissions from power plants. Virginia recently joined the consortium as well. Most of these types of programs require major sources of emissions or major producers of fuels to acquire and subsequently surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved. The cost of these allowances could increase over time. While new laws and regulations that are aimed at reducing GHG emissions will increase demand for natural gas, they may also result in increased costs for permitting, equipping, monitoring and reporting GHGs associated with natural gas production and use.

Finally, there are currently more than twenty lawsuits filed on behalf of states and municipalities seeking to hold producers of oil, natural gas and coal liable for the consequences of certain weather-related events, like rising sea levels and more frequent and severe flooding, storms and heatwaves, and seeks money damages for remedial measures aimed at eliminating or ameliorating damages caused by climate change. For further discussion of pending legal proceedings, see Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

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

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CNX is subject to various stringent federal, state, and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may impose numerous obligations that are applicable to us and our customers' operations. Failure to comply with these laws, regulations and related permit requirements may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which CNX’s gathering systems pass, and some local municipalities may also have the right to pursue legal actions to enforce compliance, challenge governmental actions, as well as seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. CNX may not be able to recover all or any of these costs from insurance. There is no assurance that changes in or additions to regulations and public policies regarding the protection of the environment will not have a significant impact on our operations and profitability.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, and surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to investigate, remediate and restore sites where regulated substances have been disposed, stored or released, as well as fines and penalties for such releases. CNX may be required to remediate contaminated properties currently or formerly operated by us regardless of the cause of contamination or whether such contamination resulted from the conduct of others. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Additionally, the Federal Endangered Species Act (ESA) and similar state laws protect species endangered or threatened with extinction and may cause us to modify a natural gas well pad siting or pipeline right of ways or routes, or to develop and implement species-specific protection and enhancement plans and schedules to avoid or minimize impacts to endangered species or their habitats during construction or operations.

CNX utilizes pipelines extensively for its operations. Stream encroachment and crossing permits from the Army Corps of Engineers (ACOE) are often required for the location of or certain impacts these pipelines cause to streams and wetlands. The EPA and the ACOE have developed a rule that revised the definition of “waters of the United States” under the Clean Water Act. The EPA moved forward with the first step on December 11, 2018, when it issued a proposed, revised rule which would replace a prior 2015 rule with pre-2015 regulations, and which narrowed language defining “waters of the United States” under the Clean Water Act that existed prior to that time. In September 2019, the EPA and the ACOE announced that the agencies were repealing the 2015 rule. This second step was a notice-and-comment rulemaking in which federal agencies conducted a substantive reevaluation of such definition. On June 22, 2020, the Navigable Waters Protection Rule became effective. While CNX cannot at this time predict how this rule will be enforced by the new Biden administration, such rulemaking, its enforcement, and future revisions to the rulemaking could lead to additional mitigation costs and severely limit CNX’s operations.

The foregoing and other regulations applicable to the natural gas industry are under constant review for amendment or expansion at both the federal and state levels. Any future changes may increase the costs of producing natural gas and other hydrocarbons, which would adversely impact our cash flows and results of operations. For example, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight unconventional shale formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas agencies. The disposal of flowback and produced water and other wastes in underground injection disposal wells is regulated by the EPA under the federal Safe Drinking Water Act and by various states in which we conduct operations under counterpart state laws and regulations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from such operations.

Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, potentially resulting in increased costs of doing business and consequently affecting profitability. Please read “Business - Regulation of Environmental and Occupational Safety and Health Matters” under Item 1 of Part I of this Form 10-K.

Existing and future governmental laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations.

There are numerous federal and state governmental regulations applicable to the natural gas industry that are not directly related to environmental regulation, many of which are under perpetual review for amendment, expansion, or modifications which may adversely affect, among other things, our ability to develop the resource, obtain and operate under permits, as well

~~as pricing or marketing of natural gas production.~~

For example, currently CNX’s gathering operations are exempt from regulation by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act (NGA). Although FERC has not made any formal determinations with respect to any of our gathering facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish that a natural gas pipeline is a gathering pipeline not subject to FERC jurisdiction. However, this issue has been the subject of substantial litigation, and if FERC were to consider the status of an individual facility and determine that it is not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would become subject to regulation by FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect results of operations and cash flows.

Additionally, some states have adopted more stringent regulation and oversight of natural gas gathering lines than is currently required by federal standards. Pennsylvania, under Act 127, authorized Public Utility Commission (PUC) oversight of Class I gathering lines, and required standards and fees for Class II and Class III pipelines. The State of Ohio also moved to regulate natural gas gathering lines in a similar manner pursuant to Ohio Senate Bill 315 (SB315). SB315 expanded the Ohio PUC's authority over rural natural gas gathering lines. These changes in interpretation and regulation affect our midstream activities, requiring changes in reporting, as well as increased costs. Various judicial decisions that may directly or indirectly impact natural gas drilling could also serve to increase our cost of doing business or restrict our operations.

Pennsylvania courts have been considering cases involving concepts of landowner rights, trespass claims and the historic common law concept of “rule of capture” as well as the role that Pennsylvania’s Environmental Rights Amendment may play in natural gas drilling activities. These cases, and similar cases testing these and other legal principles could result in judicial outcomes that could negatively impact future shale drilling and hydraulic fracturing within the Commonwealth of Pennsylvania if the court finds that hydraulic fracturing could violate the constitutional or property rights of Pennsylvania citizens and residents.

~~Further, the Biden administration may take a different direction than the Trump administration regarding certain regulatory measures impacting air emissions or clean water standards.~~•For example, the new administration has announced that it will re-enter the United States in the Paris Climate Accords and may attempt to establish more stringent standards to update or replace the Affordable Clean Energy Rule. For additional detail regarding the risks to our business resulting from governmental regulation, see Risk Factor titled, “Climate change legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities.”~~See Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.~~

CNX may incur significant costs and liabilities as a result of pipeline operations and/or increases in the regulation of natural gas gathering pipelines.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) has adopted safety, transportation and operational regulations applicable to pipeline operators. Should our operations fail to comply with PHMSA or comparable state regulations, CNX could be subject to substantial penalties and fines. In October 2019, PHMSA issued a final rule, effective July 2020, regarding hazardous pipeline safety regulations that significantly extends the integrity management requirements to previously exempt pipelines and imposes additional obligations on hazardous liquid pipeline operators that are already subject to the integrity management requirements.

PHMSA also issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and response measures on natural gas and hazardous liquid pipeline operators. In October 2019, PMHSA published a final rule that significantly modifies existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of gas transmission and gathering pipelines. Compliance with the rule could materially adversely affect our operations. In May 2020, PMHSA proposed additional amendments to Federal Pipeline Safety Regulations. The adoption of these regulations, which may apply different and/or more comprehensive or stringent safety standards than we are currently subject to, could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While CNX cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow.

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Changes in federal or state tax laws focused on natural gas exploration and development could cause our financial position and profitability to ~~deteriorate. Additionally, our~~deteriorate and future tax liability may be greater than ~~expected if our net operating loss (“NOL”) carryforwards are limited, we do not generate expected deductions, or tax authorities challenge certain of our tax positions.~~anticipated.

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We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.

The passage of future legislation or any other changes in U.S. federal or state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to natural gas exploration and development. Any such changes could negatively affect our financial condition and results of operations. For instance, previous tax law legislation decreased the regular U.S. federal income tax rate, limited the ability of corporations to take certain interest deductions, increased the limitation on deductibility of executive compensation, and have eliminated a corporation’s ability to take deductions for income attributable to domestic production activities. Any future tax law legislation could adversely impact our financial position, current and deferred federal and state income tax liabilities and cash flows.

Additionally, legislation has been proposed from time to time in the states in which we operate - primarily Pennsylvania, Ohio, Virginia and West Virginia - that would impose additional taxes or increase taxes on the production from our wells. The proposed tax rates have varied but would represent a greater financial burden on the economics of the wells we drill in these states. Such changes in the rates of existing production taxes could adversely impact our earnings, cash flows and financial position.

As of December 31, 2020, we have U.S. federal and state NOL carryforwards of $1.0 billion and $1.9 billion, respectively, some of which expire at various dates from 2021 to 2040 while others have no expiration date. We expect to be able to utilize these NOL carryforwards and generate deductions to offset our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986 or otherwise. Additionally, any significant variance in our interpretation of current income tax laws, including as result of the release of any Treasury Regulations or other interpretive guidance or a challenge of one or more of our tax positions by the IRS or other tax authorities could affect our tax position. While we expect to be able to utilize our NOL carryforwards and generate deductions to offset our future taxable income, in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise), or our NOL carryforwards are subject to future limitations, our future tax liability may be greater than expected.

CNX and its subsidiaries are subject to various legal proceedings and investigations, which may have an adverse effect on our business.

We are party to a number of legal proceedings and, from time to time, investigations, in the normal course of business activities. Responding to investigations or defending these actions, especially purported class actions, can be costly and can distract management. For example, we are a defendant in pending purported class action lawsuits dealing with claimants’ alleged entitlements to, and accounting for, natural gas royalties. Additionally, we are a party to two climate change lawsuits being pursued by communities against fossil fuel producers relating to climate change, which are beginning to gain prevalence in the courts.There is also the possibility that CNX may become involved in future investigations or suits regarding its business activities. There is the potential that the costs of defending litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.

Financing, Investment and Indebtedness Risks

•Our current long-term debt obligations, and the terms of the agreements that govern that debt, ~~including debt of our subsidiaries,~~ and the risks associated therewith, could adversely affect our business, financial condition, liquidity and results of operations.

As of December 31, 2020, CNX's total long-term indebtedness, was approximately $2.5 billion, including current portion and excluding unamortized debt issuance costs, of which approximately (i) $500.0 million was under our 6.00% Senior Notes due 2029 (ii) $161.0 million was under our senior secured credit facility (the “Credit Facility”), (iii) $700.0 million was under our 7.25% Senior Notes due 2027 plus $7 million of unamortized bond premium, (iv) $345 million of 2.25% Senior Notes due

~~May 2026,~~(v) $400 million of 6.50% Senior Notes due March 2026 issued by our midstream business, less $4 million of unamortized bond discount (CNX is not a guarantor of these notes), (vi) $291 million in outstanding borrowings under our midstream revolver. (CNX is not a guarantor of this revolving credit facility), (vii) $115 million in outstanding borrowings under the Cardinal States Gathering Company Credit Facility (the “Cardinal States Facility”) and (iv) $45 million in outstanding borrowings under the CSG Holdings II LLC Credit Facility (the “CSG Holdings Facility”). The degree to which we are leveraged could have important consequences, including, but not limited to:

•~~increasing our vulnerability to general adverse economic and industry conditions;~~

•requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our natural gas reserves or other general corporate requirements;

•~~limiting our flexibility in planning for, or reacting to, changes in our business and in the natural gas industry;~~

•~~placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to capital resources; and~~

•~~limiting our ability to implement our business strategy.~~

The one-month LIBOR rate may be used under our secured credit facilities. The transition from LIBOR to a replacement interest rate “benchmark” is ongoing, and the effects of this transition remains unclear. The discontinuation of LIBOR is not expected to occur until the end of 2021, beyond which the United Kingdom’s Financial Conduct Authority will no longer mandate publication of LIBOR, but banks and other financial institutions are being encouraged to make the transition to a replacement rate sooner rather than later. In the U.S., the Alternative Reference Rates Committee (ARRC) was convened to identify a suitable alternative to LIBOR. The ARRC has chosen the Secured Overnight Financing Rate (SOFR) as its preferred alternative, which is based on rates for overnight loans, collateralized by U.S. treasury securities, and is based on directly observable Treasury-backed repurchase transactions, which is a liquid market with daily volumes regularly in excess of $800 billion. While many financial industry experts consider SOFR to be a reliable alternative to LIBOR, CNX cannot predict the effects of this transition, and our ability to borrow on favorable terms may be adversely affected.

Our senior secured Credit Facility and the indentures governing our 7.25% Senior Notes due 2027 and 6.00% Senior Notes due 2029 limit the incurrence of additional indebtedness unless specified tests or exceptions are met, compliance with certain financial covenants on a quarterly basis, and impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging in acquisitions. Failure to comply with these covenants could result in an event of default that, if not cured or waived, could materially adversely affect us. Further, CNXM’s existing $600 million revolving credit facility and CNXM’s $400 million of 6.50% Senior Notes, neither of which are guaranteed by CNX, subjects CNXM to similar financial and/or other restrictive covenants and other restrictions.

If our cash flows and capital resources are insufficient to fund our debt service obligations, including repayment of such obligations at maturity, we may be; forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our respective scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet their debt service and other obligations; however, our existing debt documents restrict our ability to sell assets and the use of the proceeds from the sales, such that we may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

Our borrowing base under our senior secured credit facility 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. ~~Significant reductions in our borrowing base below $1.8 billion could materially adversely affect our results of operations, financial condition and liquidity.~~

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Our ability to borrow and have letters of credit issued under our $1.8 billion senior secured Credit Facility is generally limited to a borrowing base. Our borrowing base is determined by the required number of lenders in good faith calculating a loan value of the Company’s proved natural gas reserves. The borrowing base under our Credit Facility is currently $1.8 billion. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination is expected to occur in the Spring of 2021. The various matters which we describe in other risk factors that can decrease our proved natural gas reserves including lower natural gas prices, operating difficulties and failure to replace our proved reserves could also decrease our borrowing base. Our borrowing base could also decrease as a result of new lending requirements or regulations or the issuance of new indebtedness. If our borrowing base declined significantly below $1.8 billion, CNX may be unable to implement our development plans, make acquisitions or otherwise execute our business plan which could materially

adversely affect our financial condition and results of operations. CNX also could be required to repay any outstanding indebtedness in excess of the redetermined borrowing base. CNX could face substantial liquidity problems, might not be able to access the equity or debt capital markets and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. CNX may not be able to consummate those sales or to obtain the proceeds which CNX could realize from them and those proceeds may not be adequate to meet any debt service obligations then due.

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

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

In addition, under certain circumstances, convertible debt instruments (such as the Convertible Notes) that may be settled entirely or partly in cash may be accounted for utilizing the treasury stock method, the effect of which is that the shares issuable upon conversion of such Convertible Notes are not included in the calculation of diluted earnings per share except to the extent that the conversion value of such Convertible Notes exceeds their principal amount. Under the treasury stock method, for purposes of calculating diluted earnings per share, the transaction is accounted for by including in the denominator the number of shares of common stock that would be necessary to settle such excess, if we elected to settle such excess in shares. There is no assurance that the future accounting standards will continue to permit the use of the treasury stock method. If we are unable or otherwise elect not to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, then our diluted earnings per share could be adversely affected.

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

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

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

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

~~We are~~CNX is subject to counterparty performance risk with respect to the capped call transactions.

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The counterparties to the capped call transactions are financial institutions or affiliates of financial institutions, and we will be subject to the risk that they might default under the capped call transactions. Our exposure to the credit risk of the counterparties will not be secured by any collateral. Global economic conditions have from time to time resulted in the actual or perceived failure or financial difficulties of many financial institutions. If a counterparty becomes subject to insolvency proceedings, with respect to such option counterparty’s obligations under the relevant capped call transaction, we will become

an unsecured creditor in those proceedings with a claim equal to our exposure at that time under our transactions with that counterparty. Our exposure will depend on many factors, but, generally, the increase in our exposure will be positively correlated to the increase in the market price and in the volatility of our common stock. In addition, upon a default by a counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any counterparty.

Conversion of the Convertible Notes may dilute the ownership interest of existing stockholders or may otherwise depress the price of our common stock.

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

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

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

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

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

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

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

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

Risks Related to Strategic Transactions

•Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are subject to risk and uncertainties, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition.

•CNX does not completely control the timing of divestitures that CNX plans to engage in, and they may not provide anticipated benefits.

•There is no guarantee that CNX 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.

•CNX may operate a portion of our business with one or more joint venture partners or in circumstances where CNX is not the operator, which may restrict our operational and corporate flexibility.

•In connection with the separation of our coal business, CONSOL Energy has agreed to indemnify us for certain liabilities, and we have agreed to indemnify CONSOL Energy for certain liabilities.

Other General Risks

•Cyber-incidents targeting our systems, oil and natural gas industry systems and infrastructure, or the systems of our third-party service providers could materially adversely affect 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.

ITEM 1A.Risk Factors

Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. In addition to the other information contained in this Form 10-K, the following risk factors related to our business, operations, investments, financial position or future financial performance or cash flows should be considered in evaluating our company. If any of the following risks were to occur, it could cause an investment in our securities to decline and result in a loss.

Risks Related to Economic Conditions and our Industry

Prices for natural gas and NGLs are volatile and can fluctuate widely based upon a number of factors beyond our control, including supply and demand for our products. An extended decline in the prices CNX receives for our natural gas and NGLs will adversely affect our business, operating results, financial condition and cash flows.

Our financial results are significantly affected by the prices we receive for our natural gas and NGLs. Natural gas, NGLs, oil and condensate prices are very volatile and can fluctuate widely based upon supply from energy producers relative to demand for these products and other factors beyond our control. In particular, the U.S. natural gas industry faces oversupply due to the success of domestic shale development, associated natural gas produced by oil producers, and other North American shale gas plays that impact domestic pricing. This oversupply of natural gas, beginning in 2012, has resulted in depressed domestic prices for most of that period. Industry drilling has continued in these plays, despite these lower gas prices, as producers continued to become more efficient. CNX expects continued volatility of natural gas prices in the future.

Our producing properties are geographically concentrated in the Appalachian Basin, which exacerbates the impact of regional supply and demand factors on our business, including the pricing of our natural gas. Not all of the natural gas produced in this region can be consumed by regional demand and must, therefore, be exported to other regions, which causes natural gas produced and sold locally to be priced at a discount to many other market hubs, such as the benchmark Henry Hub price. This discount, or negative basis, to the Henry Hub price is forecasted to continue in future years for Appalachian Basin producers. While new interstate pipeline projects could reduce this discount, it could increase further if production in the basin continues to grow and projects to move gas out of the basin are cancelled, delayed or denied for any reason, such as permitting and regulatory issues or environmental lawsuits. In July 2020, the Atlantic Coast Pipeline project, which was designed to move produced natural gas out of the northeast, was cancelled by its partners after nearly six years of work; and on January 25, 2022, the U.S. Court of Appeals for the Fourth Circuit invalidated the U.S. Forest Service and Bureau of Land Management (BLM) approvals for the Mountain Valley Pipeline to pass through the Jefferson National Forest. The ruling sends the permit back to the Forest Service and BLM for reconsideration. An extended period of lower natural gas prices can reduce cash flow, which decreases funds available for capital expenditures to replace reserves or increase production.

Our drilling plans also include some activity in areas of shale formations that may also contain NGLs, condensate and/or oil. The prices for NGLs, condensate and oil are also volatile for reasons similar to those described above, for natural gas. Although the Company is able to hedge natural gas benchmarks and local basis differentials, it has not found acceptable instruments to hedge its relatively minor quantities of NGL, condensate and oil. In addition, similar to the oversupply of natural gas, historically, increased drilling activity by third parties in formations containing NGLs has led to a significant decline in the price CNX receives for our NGLs. International demand and storage levels also affect NGL prices. Further, an oversupply of NGLs in the local markets where CNX operates requires excess NGLs to be transported out of our region and into the broader market, including international exports. NGLs are transported by a variety of methods, including pipeline, rail, and truck. Any disruption in those means of transportation could have a further detrimental impact on the price CNX receives for our NGLs. Our results of operations may be adversely affected by a depressed level of, or downward fluctuations in, NGLs, condensate and oil prices.

Apart from issues with respect to the supply of products CNX produces, demand can fluctuate widely due to a number of matters beyond our control, including:

•weather conditions in our markets that affect the demand for natural gas;

•changes in the consumption pattern of industrial consumers, electricity generators and residential users of electricity and natural gas;

•with respect to natural gas, the price and availability of alternative fuel sources used by electricity generators;

•technological advances affecting energy consumption and conservation measures reducing demand;

•the costs, availability and capacity of transportation infrastructure;

•proximity and capacity of natural gas pipelines and other transportation facilities;

•changes in levels of international demand and tariffs associated with international export; and

•the impact of domestic and foreign governmental laws and regulations, including environmental and climate

change regulations and delays.

Lack of market demand could result in temporarily shut-in wells due to low commodity prices and it is possible that some of our wells may be shut-in in the future or sales terms may be less favorable than might otherwise be obtained should demand for our products decrease and/or prices decrease.

If natural gas prices decrease or drilling efforts are unsuccessful, CNX may be required to record write-downs of our proved natural gas properties. Additionally, changes in assumptions impacting management’s estimates of future financial results as well as other assumptions related to the Company's stock price, weighted-average cost of capital, terminal growth rates and industry multiples, could cause goodwill and other intangible assets CNX holds to become impaired and result in material non-cash charges to earnings.

Lower natural gas prices or wells that produce less than expected quantities of natural gas, have in the past and may in the future reduce the amount of natural gas that CNX can produce economically. This results in our having to make substantial downward adjustments to our estimated proved reserves. When this occurs, or when our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. CNX is required to perform impairment tests on our assets at least annually or whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever development plans change with respect to those assets. In the past CNX has had to record an impairment charge related to certain assets and CNX may incur impairment charges in the future, which could have an adverse effect on our results of operations in the period taken.

For the year ended December 31, 2020, CNX recognized certain indicators of impairments specific to our Southwest Pennsylvania (SWPA) CBM asset group and determined that the carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a result, an impairment of $62 million was recognized and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. The impairment was related to an economic decision to temporarily idle certain CBM wells and the related processing facility during the first quarter of 2020. There were no impairments for the year ended December 31, 2021.

Future acquisitions may lead to the acquisition of additional goodwill or other intangible assets. At least annually, or whenever events or changes in circumstances indicate a potential impairment in the carrying value as defined by GAAP, CNX will evaluate this goodwill and other intangible assets for impairment by first assessing qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Estimated fair values could change if, for example, there are changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market capitalization. The future impairment of these assets could require material non-cash charges to our results of operations, which could materially adversely affect our reported earnings and results of operations for the affected periods.

Competition and consolidation within the natural gas industry may adversely affect our ability to sell our products and midstream services or other parts of the business. Increased competition or a loss of our competitive position can adversely affect our sales of, or our prices for, our products, which can impair our profitability.

The natural gas, exploration, production and midstream industries are intensely competitive with companies from various regions of the United States, and increasingly face competition in international markets. The industry has been experiencing increased competitive pressures as a result of both consolidation within the exploration and production space, along with the continued proliferation of stand-alone midstream companies. Midstream, transmission and processing consolidation in the industry could lead to a less competitive environment for CNX to find partners for projects needed to support development, which could increase costs. Many of the companies with which CNX competes are larger and have more resources to deploy, and if CNX were unable to compete, our company, our operating results, financial position or other parts of the business may be adversely affected. In addition, CNX competes with larger companies to acquire new natural gas properties for future exploration, limiting our ability to replace the natural gas CNX produces or to grow our production. There is also increased competition within the industry as a result of oil-focused drilling, where natural gas is produced as an ancillary byproduct and may be sold at prices below market. Some of such “byproduct” gas could be transported to our key markets, thereby affecting regional supply. The industry also faces competition from alternative energy sources. The highly competitive environment in which CNX operates may negatively impact our ability to acquire additional properties at prices or upon terms CNX views as

favorable. Any reduction in our ability to compete in current or future natural gas markets could materially adversely affect our business, financial condition, results of operations and cash flows.

Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions can have a material adverse effect on our liquidity, results of operations, business and financial condition that CNX cannot predict.

Economic conditions in a number of industries in which our customers operate, such as electric power generation, have experienced substantial deterioration in the past, resulting in reduced demand for natural gas. Renewed or continued weakness in the economic conditions of any of the industries CNX serves or that are served by our customers, or the increased focus by markets on carbon-neutrality, could adversely affect our business, financial condition, results of operation and liquidity in a number of ways. For example:

•demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas business;

•a decrease in international demand for natural gas or NGLs produced in the United States could adversely affect the pricing for such products, which could adversely affect our results of operations and liquidity;

•our ability to refinance our existing senior notes may be limited and the terms on which we are able to do so may be less favorable to us depending on the strength of the capital markets or our credit ratings;

•increased capital markets scrutiny of E&P companies leading to increased costs of capital or lack of credit availability; and

•a decline in our creditworthiness may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.

In addition, the ongoing coronavirus (COVID-19) pandemic has materially and adversely impacted many businesses, industries and economies.For further detail regarding the risks to our business resulting from COVID-19, see the Risk Factor titled “Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.”

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

To manage our exposure to fluctuations in the price of natural gas, CNX enters into hedging arrangements with respect to a portion of our expected production. As of January 6, 2022, CNX expects these transactions will represent approximately 470.8 Bcf of our estimated 2022 production at an average price of $2.45 per Mcf, 392.3 Bcf of our estimated 2023 production at an average price of $2.36 per Mcf, 344.6 Bcf of our estimated 2024 production at an average price of $2.25 per Mcf, 273.4 Bcf of our estimated 2025 production at an average price of $2.23 per Mcf, and 220.9 Bcf of our estimated 2026 production at an average price of $2.45 per Mcf. To the extent that CNX engages in hedging activities, CNX may be prevented from realizing the near-term benefits of price increases above the levels of the hedges. If CNX chooses not to engage in or otherwise reduce our future use of hedging arrangements or are unable to engage in hedging arrangements due to lack of acceptable counterparties, CNX may be more adversely affected by changes in natural gas prices than our competitors who engage in hedging arrangements to a greater extent than CNX does. Increases or decreases in forward market prices could result in material unrealized (non-cash) losses or gains on commodity derivative instruments resulting in volatility in reported earnings. Future legislation regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risks associated with our business.

In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•our production is less than expected;

•market prices for natural gas rise significantly in excess of our derivative hedge price resulting in significant cash payments to our hedge counterparties;

•we are unable to find available counterparties in the future with which to enter into hedges and counterparties able to enter into basis hedge contracts;

•the creditworthiness of our counterparties or their guarantors is substantially impaired; and

•counterparties have credit limits that may constrain our ability to hedge additional volumes.

Negative public perception regarding our Company or industry could have an adverse effect on our operations, financial results or stock price.

Negative public perception regarding our industry resulting from, among other things, operational incidents or concerns raised by advocacy groups, related to environmental, health, or community impacts has resulted in increased regulatory scrutiny, which has resulted in additional laws, regulations, guidelines and enforcement interpretations, at the federal or state level. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and an increased risk of litigation that may negatively impact our future financial results or our stock price. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. This could cause the permits CNX needs to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

In addition, in recent years increasing attention has been given to corporate activities related to environmental issues in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities, and other groups, to promote change at public companies, including through investment and voting practices. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. As a result, some capital markets participants have reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the energy industry. If divestment efforts continue, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted and have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

While CNX has not incurred significant disruptions to its operations during the years ended December 31, 2021 and 2020 as a direct result of the COVID-19 pandemic, the continuation of the COVID-19 pandemic may materially and adversely affect, our business, operating and financial results and liquidity in the future. The severity, magnitude and duration of the ongoing COVID-19 outbreak and the efforts to reduce its spread remain uncertain but continues to be rapidly changing and hard to predict. While the full impact of this virus and the long-term worldwide reaction to it and impact from it remains unknown at this time, government reaction to the pandemic and restrictions and limitations applied by the government as a result, continued changes in the infection rate, travel restrictions, quarantines, or site closures as a result of the virus could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, lead to disruptions in our supply chain (including necessary contractors and materials), lead to a disruption in our resource acquisition or permitting activities and cause disruption in our relationship with our customers. Additionally, the COVID-19 outbreak has significantly impacted economic activity and markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:

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

•the operations of our midstream service providers, on whom CNX relies for the transmission, gathering and processing of a significant portion of our produced natural gas, NGLs, oil and condensate, may be disrupted or suspended in response to containing the outbreak, and/or the difficult economic environment may lead to

the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices CNX receives for our produced natural gas, NGLs, oil and condensate or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

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

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

Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.

Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings, while not standardized or fully transparent, are used by some investors to evaluate their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries. Such diversion could have a negative impact on our stock price and our access to and costs of capital.

Risks Related to our Business Operations

The disruption of, capacity constraints in, or proximity to pipeline and processing systems could limit sales of our natural gas and NGLs and cash flows from operations, and any decrease in availability of pipelines or other midstream facilities could adversely affect our operations.

Although CNX owns midstream facilities, we also gather, process and transport our natural gas to market by utilizing processing facilities and pipelines owned by others. If pipeline or processing facility capacity is limited or is unexpectedly disrupted for any reason, our sales of natural gas and/or NGLs could be reduced, which could negatively affect our profitability. If CNX cannot access processing facilities and pipeline transportation, we may have to reduce our production of natural gas, reducing our sales and revenues, and causing our unit costs to increase. If pipeline quality standards change or we cannot meet applicable standards, we might be required to install additional processing equipment which could increase our costs. Pipelines could also curtail our flows until the natural gas delivered to their pipeline is in compliance with predetermined gas quality specifications. Any reduction in our production of natural gas or increase in our costs could materially adversely affect our business, financial condition, results of operations and cash flows.

Further, a significant portion of our natural gas is sold on or through two pipeline systems, Texas Eastern Transmission and Columbia Gas Transmission, which could experience capacity issues, operational disruptions and unexpected downtime, including from cyberattacks, with either no or little alternative transportation options available for our natural gas. Reductions in capacity on the pipelines, which have occurred in the past, may result in curtailments and reduce our production of natural gas. A reduction in capacity on any downstream pipelines could also reduce the demand for our natural gas, which would reduce the price CNX receives for our production.

CNX has various third-party firm transportation, natural gas processing, gathering and other agreements in place, many of which have minimum volume delivery commitments that obligate us to pay fees on minimum volumes regardless of actual volume throughput. Reductions in our drilling program may result in insufficient production to utilize our full firm transportation and processing capacity, reducing our cash flow from operations, which may require us to reduce or delay our

planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect our business, financial condition, results of operations and cash flows.

Uncertainties exist in the estimation of economic recovery of oil and natural gas reserves. With these uncertainties, estimates of revenues, operating and development costs and profitability may be inaccurate.

Oil and natural gas reserves are economically recoverable when the price at which they are expected to be sold exceeds their expected cost of development and production. Reserves require estimates of underground accumulations of oil and natural gas, and the use of assumptions concerning natural gas and liquid hydrocarbon prices, production levels, recoverable reserve quantities and operating and development costs. For example, a significant amount of our proved oil and natural gas reserves are identified as proved undeveloped reserves and may be more susceptible to positive and negative changes in reserve estimates than our proved developed reserves. A portion of the proved undeveloped reserves booked during the last ten years were due to the addition of undeveloped wells on our Shale acreage more than one offset location away from existing production through the use of reliable, industry standard applications. Also, we make certain assumptions regarding natural gas and liquid hydrocarbon prices, production levels and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas and natural gas liquid reserves, the economically recoverable quantities of natural gas and natural gas liquids attributable to any particular group of properties, the classifications of natural gas reserves based on risk of recovery and estimates of the future net cash flows. The PV-10 measure of pre-tax discounted future net cash flows and the standardized measure of after-tax discounted future net cash flows from our proved reserves included within this Annual Report on Form 10-K are not necessarily the same as the current market value of our estimated natural gas and liquid reserves. CNX bases the estimated discounted future net cash flows from our proved natural gas and natural gas liquid reserves on historical average prices and costs. However, actual future net cash flows from our proved and unproved natural gas and natural gas liquid properties may also be affected by factors such as:

•geological conditions;

•our acreage position, and our ability to acquire additional acreage, including purchases and third-party swaps to develop our position efficiently;

•changes in governmental regulations and taxation;

•the amount and timing of actual production;

•future prices and our hedging position;

•future operating costs;

•operational risks and results; and

•capital costs of drilling, completion and gathering assets.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas, NGLs and oil and/or condensate will affect the timing of actual future net cash flows from proved reserves and thus their actual present value. In addition, the prescribed 10% discount factor used when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved natural gas reserves as of December 31, 2021 would decrease from $8.1 billion to $7.9 billion.

Developing, producing and operating natural gas wells is a high-risk activity, and is subject to operating risks and hazards that could increase expenses, decrease our production levels and expose us to losses or liabilities.

Our financial results are materially dependent upon the success of our development program. The development of natural

gas involves numerous risks, including the risk that an encountered well does not produce in sufficient quantities to make the well economically viable. The cost of drilling, completing and operating wells is substantial and uncertain, and our operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control. Our future development activities may not be successful, and if they are unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. CNX may be unable to develop identified or budgeted wells within our expected time frame, or at all for various reasons, and a final determination with respect to the development of any scheduled or budgeted wells will be dependent on a number of factors, including:

•the results of delineation efforts and the acquisition, review and analysis of data, including seismic data;

•the availability of sufficient capital resources to us and any other participants in a well for the development of the well;

•whether we are able to acquire on a timely basis all of the leasehold interests required for the well, including through swap transactions with other operators;

•whether we are able to obtain, on a timely basis or at all, the permits required for the development of wells;

•whether production levels align with estimates; and

•economic and industry conditions at the time of development, including prevailing and anticipated prices for natural gas, NGLs and oil and the availability and cost of oilfield services.

The exploration, production, and transporting of natural gas involves numerous operational risks. The cost of developing and operating a shale gas well, a shallow oil and gas well or a coalbed methane (CBM) well is often uncertain, and a number of factors can delay, suspend, or prevent development operations, decrease production and/or increase the cost of our natural gas operations at particular sites for varying lengths of time. The operational factors that are most likely to negatively impact our operations include unexpected development and production conditions (including pressure or irregularities in geologic formations or wells, material and equipment failures, fires, ruptures, loss of well control, landslides, mine subsidence, explosions or other accidents and environmental concerns and adverse weather conditions), which conditions and risks may be amplified as we increase the vertical and horizontal length of drilling endeavors; similar operational or design issues relating to pipelines, compressor stations, pump stations, related equipment and surrounding properties; challenges relating to transportation, pipeline infrastructure and capacity for treatment or disposal of waste water generated in operations and failure to obtain, or delays in the issuance of, permits at the state or local level and the resolution of regulatory concerns.

The realization of any of these risks could adversely affect our ability to conduct our operations, materially increase our costs, or result in substantial loss to us as a result of claims for:

•personal injury or loss of life;

•damage to and destruction of property, natural resources and equipment, including our properties and our natural gas production or transportation facilities;

•pollution and other environmental damage to our properties or the properties of others;

•potential legal liability and monetary losses;

•damage to our reputation within the industry or with customers;

•regulatory enforcement, investigations and penalties;

•suspension of our operations; and

•repair and remediation costs.

Although CNX maintains insurance for a number of risks and hazards, we may not be adequately insured against the losses or liabilities that could arise from a significant accident or disruption in our operations. The occurrence of an event that is not fully covered by insurance, such as pollution or environmental issues, could materially adversely affect our business, financial condition, results of operations and cash flows.

Our management team has specifically identified and scheduled certain locations as an estimation of our future multi-year development activities on our existing acreage. These locations represent a significant part of our development strategy. Our ability to develop these locations may be dependent on a number of factors, including natural gas, NGL and oil prices, the availability and cost of capital, drilling and production costs, obtaining required regulatory permits, the acquisition on acceptable terms of any leasehold interests we do not control but that are necessary to complete the drilling unit, including potentially through third-party swap transactions, availability of drilling services and equipment, drilling results, lease expirations for the failure to timely develop or otherwise, transportation constraints, regulatory and zoning approvals and other factors. Because of these uncertain factors, we do not know if the numerous development locations we have identified will ever be drilled. CNX may require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any development activities we are able to conduct on these locations may be unsuccessful, which may result in our inability to add additional proved reserves or may result in a downward revision of our estimated proved reserves, which could materially adversely affect our business and results of operations.

Our capital projects require substantial capital expenditures and are subject to regulatory, environmental, political, legal and economic risks and if CNX fails to generate sufficient cash flow, obtain required capital or financing on satisfactory terms or respond to regulatory and political developments, our natural gas reserves may decline and our operations and financial results may suffer.

As part of our strategic determinations, CNX expects to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves and maintenance, purchase or construction of midstream systems. If CNX is unable to make sufficient or effective capital expenditures, we will be unable to maintain and grow our business. The gas gathering agreements that we have with third-parties may impose obligations on us to invest capital in our midstream systems which are not fully protected against volumetric risks associated with lower-than-forecast volumes flowing through our gathering systems. To the extent our customers are not contractually obligated to, and determine not to, develop their properties in the areas covered by these acreage dedications, or otherwise sell, exchange, farm-out or otherwise dispose of all of, or an undivided interest in, the development of the dedicated acreage, the resulting decrease in the development of reserves by our midstream customers could result in reduced volumes serviced by us and a commensurate decline in revenues and cash flows.

Revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. There is no assurance that CNX will have sufficient cash from operations, borrowing capacity under our credit facilities, or the ability to raise additional funds in the capital markets to meet our capital requirements. If cash flow generated by our operations or available borrowings under our credit facilities are not sufficient to meet our capital requirements, or CNX is unable to obtain additional financing, CNX could be required to curtail the pace of the development of our natural gas properties and midstream activities, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

CNX may not be able to obtain required personnel, services, equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our operations.

CNX relies on third-party contractors to provide key services and equipment for our operations. CNX contracts with third

parties for well services, related equipment and qualified experienced field personnel to drill wells, construct pipelines and conduct field operations. We also utilize third-party contractors to provide land acquisition and related services to support our land operational needs. The demand for these services, equipment and field personnel to drill wells, construct pipelines and conduct field operations and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas, NGL and oil prices, causing periodic shortages. Weather may also play a role with respect to the relative availability of certain materials. Historically, there have been shortages of drilling and work-over rigs, pipe, compressors and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. The costs and delivery times of equipment and supplies are substantially greater in periods of peak demand, including increased demand for plays outside of our area of geographic focus. In addition, accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring increased costs for contractors and/or materials. Accordingly, CNX cannot be assured that we will be able to obtain necessary services, drilling equipment and supplies in a timely manner or on satisfactory terms, and CNX may experience shortages of, or increases in the costs of, drilling equipment, crews and associated supplies, equipment and field services in the future.

CNX attempts to mitigate the risks involved with increased natural gas production activity by entering into “take or pay” contracts with well service providers which commit them to provide field services to us at specified levels and commit us to pay for field services at specified levels even if we do not use those services. However, these types of contracts expose us to economic risk during a downturn in demand or during periods of oversupply. Having to pay for services we do not use decreases our cash flow and increases our costs.

In addition, the COVID-19 pandemic has materially and adversely impacted many businesses, industries, supply chains and economies. For further detail regarding the risks to our business resulting from COVID-19, see Risk Factor titled “Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.”

If CNX cannot find adequate sources of water for our use or CNX is unable to dispose of or recycle water produced from our operations at a reasonable cost and within applicable environmental rules, our ability to produce natural gas economically and in sufficient quantities could be impaired.

As part of our drilling and production in shale formations, CNX uses hydraulic fracturing processes that require access to adequate sources of water, which may not be available in proximity to our operations or at certain times of the year. To ensure adequate water for our operations, CNX may be required to invest substantial amounts of capital in water pipelines which are used for relatively short periods of time. Increased regulation of these water pipelines could cause us to invest additional capital, alter our disposal or transportation method or affect our operations in other manners. Alternatively, CNX may be required to transport water by truck, and CNX may not be able to contract for sufficient water hauling trucks or drivers to meet our needs.

Further, our operations generate significant volumes of wastewater that must be treated, reused or disposed. This waste can be generated from various aspects of our operations, including from drilling fluids, completions activities and normal production over the life of the well, and are associated with all types of natural gas wells, including CBM wells and shale wells. A significant portion of this water can be recycled for use in other hydraulic fracturing operations. To the extent we must dispose of water rather than recycle it, our costs may increase, which will detrimentally affect our cash flows. We attempt to minimize the expense associated with the transportation of wastewater by optimizing the transportation between the sources of wastewater and locations where the wastewater can be reused or disposed. Various interruptions in our planned transportation of this wastewater, including operational issues and regulatory matters, could increase our operating costs, which would detrimentally affect our cash flows. The risk of pollution also exists while handling, transferring, storing, recycling and disposing wastewater and other wastes, as well as in development or production of a well.

Failure to successfully replace our current natural gas, NGL and oil reserves through economic development of our existing

or acquired assets or through acquisition of additional producing assets, would lead to a decline in our natural gas, NGL and oil production levels and reserves.

Producing natural gas, NGL and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline can change if production from our existing wells is different than what has been estimated, operating conditions change or other circumstances arise that affect our ability to produce the wells. Thus, our future natural gas, NGL and oil reserves and production and, therefore, our cash flow and income are highly dependent on our estimates and our success in efficiently developing and selling our current reserves and economically finding or acquiring additional economically recoverable reserves. CNX may not be able to develop, find or acquire additional economically recoverable reserves to replace our current and future production at acceptable costs.

In addition, the level of natural gas, NGL and condensate volumes handled through our midstream systems depends on the level of production from natural gas wells feeding into such midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, CNX must supply natural gas, NGLs and condensate from new wells on acreage in close proximity to our midstream systems. This can take the form of wells we develop on our own, wells developed by others on acreage that is dedicated to our midstream systems or through contracts with third-party customers to flow volumes on our midstream systems. CNX has no control over third party producers’ levels of development and completion activity in areas adjacent to our midstream systems, or the amount of reserves associated with or rate of production decline from those third-party wells – and only limited control over those factors on our own wells.

CNX may incur losses as a result of title defects in the properties in which CNX invests or the loss of certain leasehold or other rights related to our midstream activities.

As is common in the oil and gas industry, it is our practice when CNX acquires natural gas leases or interests not to conduct a comprehensive chain of title examination to the mineral interest. Prior to the drilling of a well, however, it is the normal practice in our industry for the operator of the well to obtain a complete title review to ensure there are no obvious defects in title to the well. As a result of such examinations, certain curative work may be required to correct defects in the marketability of the title and such curative work entails expense. Our inability to cure any title defects in our leases in a timely and cost-efficient manner may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial position.

Additionally, most of the land on which our midstream systems have been constructed is not owned in fee by us; rather, the properties are held by surface use agreements, rights-of-way or other easement rights. CNX is, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. CNX may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew the right-of-way or for other reasons, could materially adversely affect our business, financial condition, results of operations and cash flows.

Legal, Environmental and Regulatory Risks

Climatechange risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation and public policy pressures, that may arise, could adversely impact the market for natural gas, as well as for our securities.

The issue of global climate change continues to attract considerable public and scientific attention, with underlying concern about the impacts of human activity, especially the emissions of greenhouse gases (“GHGs”) such as carbon dioxide (“CO2”) and methane into the environment and is increasingly the subject of civil litigation and regulatory focus.

The EPA, under the Climate Action Plan, elected to regulate GHGs under the Clean Air Act (“CAA”) to limit emissions of CO2 from natural gas-fired power plants. In April 2017, the EPA announced that it was initiating a review of the Clean Power Plan consistent with President Trump’s Executive Order 13783, and in October 2017 published a proposed rule to formally repeal the Clean Power Plan. On August 20, 2018, the EPA issued the proposed “Affordable Clean Energy Rule.” On June 19, 2019, the EPA issued the final Affordable Clean Energy Rule, replacing the Clean Power Plan. The Affordable Clean Energy Rule was vacated by the United States Court of Appeals for the D.C. Circuit on the last day of the Trump administration in

January 2021. Accordingly, the Biden administration is taking a different direction than the Trump administration regarding these regulatory actions. For example, the new administration re-entered the United States in the Paris Climate Accord and may attempt to establish more stringent standards to update or replace the Affordable Clean Energy Rule. In addition, the EPA adopted a new Climate Adaptation Action Plan in October of 2021.

Additionally, some states have issued mandates to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and potential cap-and-trade programs. For example, Pennsylvania has taken steps to bring Pennsylvania into an eleven -state consortium of Northeastern and Mid-Atlantic States - the Regional Greenhouse Gas Initiative (RGGI) -- that set price and declining limits on CO2 emissions from power plants. In December 2021, the Pennsylvania Attorney General approved a proposed regulation which would allow Pennsylvania to join RGGI; however, the Pennsylvania General Assembly is pursuing a concurrent regulatory review resolution process likely to disapprove of the proposed regulation. Most of these types of programs require major sources of emissions or major producers of fuels to acquire and subsequently surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved. The cost of these allowances could increase over time. While new laws and regulations that are aimed at reducing GHG emissions will increase demand for natural gas, they may also result in increased costs for permitting, equipping, monitoring and reporting GHGs associated with natural gas production and use.

In addition, spurred by increasing concerns regarding climate change, the oil and gas industry face growing demand for corporate transparency and a demonstrated commitment to sustainability goals. Environmental, social and governance (ESG) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and stakeholders across the industry.

Finally, there are currently close to two dozen lawsuits filed on behalf of various states and municipalities seeking to hold producers of oil, natural gas and coal liable for the consequences of certain weather-related events, like rising sea levels and more frequent and severe flooding, storms and heatwaves, and seeks money damages for remedial measures aimed at eliminating or ameliorating damages caused by climate change. For further discussion of pending legal proceedings, see Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

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

CNX is subject to various stringent federal, state, and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may impose numerous obligations that are applicable to us and our customers' operations. Failure to comply with these laws, regulations and related permit requirements may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which CNX’s gathering systems pass, and some local municipalities may also have the right to pursue legal actions to enforce compliance, challenge governmental actions, as well as seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. CNX may not be able to recover all or any of these costs from insurance. There is no assurance that changes in or additions to regulations and public policies regarding enforcement and the protection of the environment will not have a significant impact on our operations and profitability.

several liability for costs required to investigate, remediate and restore sites where regulated substances have been disposed, stored or released, as well as fines and penalties for such releases. CNX may be required to remediate contaminated properties currently or formerly operated by us regardless of the cause of contamination or whether such contamination resulted from the conduct of others. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Additionally, the Federal Endangered Species Act (ESA) and similar state laws protect species endangered or threatened with extinction and may cause us to modify a natural gas well pad siting or pipeline right of ways or routes, or to develop and implement species-specific protection and enhancement plans and schedules to avoid or minimize impacts to endangered species or their habitats during construction or operations.

CNX utilizes pipelines extensively for its operations. Stream encroachment and crossing permits from the Army Corps of Engineers (ACOE) are often required for the location of or certain impacts these pipelines cause to streams and wetlands. The EPA and the ACOE have developed a rule that revised the definition of “waters of the United States” under the Clean Water Act. The EPA moved forward with the first step on December 11, 2018, when it issued a proposed, revised rule which would replace a prior 2015 rule with pre-2015 regulations, and which narrowed language defining “waters of the United States” under the Clean Water Act that existed prior to that time. In September 2019, the EPA and the ACOE announced that the agencies were repealing the 2015 rule. This second step was a notice-and-comment rulemaking in which federal agencies conducted a substantive reevaluation of such definition. On June 22, 2020, the Navigable Waters Protection Rule became effective. On June 9, 2021, the EPA announced its intent to revise the rule again. On August 4, 2021, the EPA and ACOE announced a rulemaking process to revise the definition of “waters of the United States.” While CNX cannot at this time predict how this rule will be enforced by the new Biden administration, such rulemaking, its enforcement, and future revisions to, or replacement of, the rulemaking could lead to additional mitigation costs and severely limit CNX’s operations.

For example, currently CNX’s gathering operations are exempt from regulation by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act (NGA). Although FERC has not made any formal determinations with respect to any of our gathering facilities, CNX believes that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish that a natural gas pipeline is a gathering pipeline not subject to FERC jurisdiction. However, this issue has been the subject of substantial litigation, and if FERC were to consider the status of an individual facility and determine that it is not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would become subject to regulation by FERC. Such regulation could decrease revenue, increase operating costs, and depending upon the facility in question, could adversely affect results of operations and cash flows.

the Ohio PUC's authority over rural natural gas gathering lines. These changes in interpretation and regulation affect our midstream activities, requiring changes in reporting, as well as increased costs. Various judicial decisions that may directly or indirectly impact natural gas drilling could also serve to increase our cost of doing business or restrict our operations.

Pennsylvania courts have been considering cases involving concepts of landowner rights, trespass claims and the historic common law concept of “rule of capture” as well as the role that Pennsylvania’s Environmental Rights Amendment (Pa. Const. art. I, § 27) may play in natural gas drilling activities. These cases, and similar cases testing these and other legal principles could result in judicial outcomes that could negatively impact future shale drilling and hydraulic fracturing within the Commonwealth of Pennsylvania if the court finds that hydraulic fracturing could violate the constitutional or property rights of Pennsylvania citizens and residents.

Further, the Biden Administration has taken a different direction than the Trump administration regarding certain regulatory measures impacting air emissions or clean water standards. For example, the new administration re-entered the United States in the Paris Climate Accords and may attempt to establish more stringent standards to replace the Affordable Clean Energy Rule, which was vacated by the United States Court of Appeals for the D.C. Circuit on the last day of the Trump administration in January 2021. For additional detail regarding the risks to our business resulting from governmental regulation, see Risk Factor titled, “Climate change risk, legislation, litigation and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation and public policy pressures that may arise, could adversely impact the market for natural gas, as well as for our securities.” See Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.

CNX may incur significant costs and liabilities as a result of pipeline operations and/or increases in the regulation of natural gas gathering pipelines.

PHMSA also issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and response measures on natural gas and hazardous liquid pipeline operators. In October 2019, PHMSA published a final rule that significantly modifies existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of gas transmission and gathering pipelines. Compliance with the rule could materially adversely affect our operations. In May 2020, PHMSA proposed additional amendments to Federal Pipeline Safety Regulations. In November 2021, PHMSA published a final rule in the Federal Register with an effective date of May 15, 2022, expanding certain federal pipeline safety requirements to all onshore gas gathering pipelines. The adoption of these regulations, which may apply different and/or more comprehensive or stringent safety standards than CNX is currently subject to, could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While CNX cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow.

Changes in federal or state tax laws focused on natural gas exploration and development could cause our financial position and profitability to deteriorate. Additionally, our future tax liability may be greater than expected if our net operating loss (“NOL”) carryforwards are limited, CNX does not generate expected deductions, or tax authorities challenge certain of our tax positions.

CNX is subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, severance, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.

attributable to domestic production activities. Any future tax law legislation could adversely impact our financial position, current and deferred federal and state income tax liabilities and cash flows.

As of December 31, 2021, CNX has U.S. federal and state NOL carryforwards of $1.0 billion and $1.9 billion, respectively, some of which expire at various dates from 2022 to 2041 while others have no expiration date. CNX expects to be able to utilize these NOL carryforwards and generate deductions to offset our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986 or otherwise. Additionally, any significant variance in our interpretation of current income tax laws, including as result of the release of any Treasury Regulations or other interpretive guidance or a challenge of one or more of our tax positions by the IRS or other tax authorities could affect our tax position. While CNX expects to be able to utilize our NOL carryforwards and generate deductions to offset our future taxable income, in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise), or our NOL carryforwards are subject to future limitations, our future tax liability may be greater than expected.

CNX and its subsidiaries are subject to various legal proceedings and investigations, which may have an adverse effect on our business.

CNX is party to a number of legal proceedings and, from time to time, investigations, in the normal course of business activities. Responding to investigations or defending these actions, especially purported class actions, can be costly and can distract management. For example, CNX is a defendant in pending purported class action lawsuits dealing with claimants’ alleged entitlements to, and accounting for, natural gas royalties. Additionally, CNX is a party to four climate change lawsuits being pursued by communities against fossil fuel producers relating to climate change, which are beginning to gain prevalence in the courts. There is also the possibility that CNX may become involved in future investigations or suits regarding its business activities. There is the potential that the costs of defending litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.

Financing, Investment and Indebtedness Risks

Our current long-term debt obligations, and the terms of the agreements that govern that debt, including debt of our subsidiaries, and the risks associated therewith, could adversely affect our business, financial condition, liquidity and results of operations.

As of December 31, 2021, CNX’s total long-term indebtedness was approximately $2.2 billion, excluding unamortized debt issuance costs, of which approximately (i) $500.0 million was under our 6.00% Senior Notes due 2029 (ii) $192.0 million was under our senior secured credit facility (the “Credit Facility”), (iii) $700.0 million was under our 7.25% Senior Notes due 2027 plus $6 million of unamortized bond premium, (iv) $345 million of 2.25% Senior Notes due May 2026 less $91 million of unamortized bond discount and issuance cost,(v) $400 million of 4.75% Senior Notes due April 2030 issued by our midstream business, less $5 million of unamortized bond discount (CNX is not a guarantor of these notes), and (vi) $185 million in outstanding borrowings under our midstream revolver. (CNX is not a guarantor of this revolving credit facility). The degree to which CNX is leveraged could have important consequences, including, but not limited to:

•increasing our vulnerability to general adverse economic and industry conditions;

•limiting our flexibility in planning for, or reacting to, changes in our business and in the natural gas industry;

•placing us at a competitive disadvantage compared to our competitors with lower leverage and better access to capital resources; and

•limiting our ability to implement our business strategy.

The one-month LIBOR rate may be used under our secured credit facilities. The transition from LIBOR to a replacement interest rate “benchmark” is ongoing, and the effect of this transition remains unclear. Originally, the discontinuation of LIBOR was expected to occur at the end of 2021, but on March 5, 2021, the ICE Benchmark Administration (“IBA”) published a feedback statement on its prior December 2020 consultation regarding its intention to cease publication of most tenors of USD LIBOR after June 30, 2023. Despite the extension, U.S. banking regulators have advised that most USD LIBOR originations should end by no later than December 31, 2021, and that new LIBOR originations prior to that date must provide for an alternative reference rate or a hardwired fallback. In accordance with the formal recommendation of the Alternative Reference Rates Committee (“ARRC”) issued on July 29, 2021, USD LIBOR is expected to be replaced with the Secured Overnight Financing Rate (“SOFR”), which is based on rates for overnight loans, collateralized by U.S. treasury securities, and is based on directly observable Treasury-backed repurchase transactions, which is a liquid market with daily volumes regularly in excess of $800 billion. The International Swaps and Derivatives Association, Inc. (“ISDA”) previously announced fallback language for USD LIBOR-referencing derivatives contracts that provides for SOFR as the primary replacement rate for USD LIBOR While many financial industry experts consider SOFR to be a reliable alternative to LIBOR, CNX cannot predict the effects of this transition, and our ability to borrow on favorable terms may be adversely affected.

Our senior secured Credit Facility and the indentures governing our 7.25% Senior Notes due 2027 and 6.00% Senior Notes due 2029 limit the incurrence of additional indebtedness unless specified tests or exceptions are met, compliance with certain financial covenants on a quarterly basis, and impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, stock repurchases, selling assets and engaging in acquisitions. Failure to comply with these covenants could result in an event of default that, if not cured or waived, could materially adversely affect us. Further, CNXM’s existing $600 million revolving credit facility and CNXM’s $400 million of 4.75% Senior Notes, neither of which are guaranteed by CNX, subjects CNXM to similar financial and/or other restrictive covenants and other restrictions.

If our cash flows and capital resources are insufficient to fund our debt service obligations, including repayment of such obligations at maturity, CNX may be: forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our respective scheduled debt service obligations. In the absence of such operating results and resources, CNX could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations; however, our existing debt documents restrict our ability to sell assets and the use of the proceeds from the sales, such that we may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

Our borrowing base under our senior secured credit facility 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. Significant reductions in our borrowing base below $2.0 billion could materially adversely affect our results of operations, financial condition and liquidity.

Our ability to borrow and have letters of credit issued under our $1.3 billion senior secured Credit Facility is generally limited to a borrowing base. Our borrowing base is determined by the required number of lenders in good faith calculating a loan value of the Company’s proved natural gas reserves. The borrowing base under our Credit Facility is currently $2.0 billion. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination is expected to occur in the Spring of 2022. The various matters which we describe in other risk factors that can decrease our proved natural gas reserves including lower natural gas prices, operating difficulties and failure to replace our proved reserves could also decrease our borrowing base. Our borrowing base could also decrease as a result of new lending requirements or regulations or the issuance of new indebtedness. If our borrowing base declined significantly below $2.0 billion, CNX may be unable to implement our development plans, make acquisitions or otherwise execute our business plan which could materially adversely affect our financial condition and results of operations. CNX also could be required to repay any outstanding indebtedness in excess of the redetermined borrowing base. CNX could face substantial liquidity problems, might not be able to access the equity or debt capital markets and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. CNX may not be able to consummate those sales or to obtain the proceeds which CNX could realize from them and those proceeds may not be adequate to meet any debt service obligations then due.

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

cost. The effect of ASC 470-20 on the accounting for the Convertible Notes is that the equity component is required to be included in the Capital in Excess of Par Value section of Stockholders’ Equity on our Consolidated Balance Sheet at the issuance date and the value of the equity component would be treated as debt discount for purposes of accounting for the debt component of the Convertible Notes. As a result, CNX will be required to record non-cash interest expense through the amortization of the excess of the face amount over the carrying amount of the expected life of the Convertible Notes. CNX will report lower net income (or larger net losses) in our financial results because ASC 470-20 requires interest expense to include both the amortization of the debt discount and the instrument’s cash coupon interest rate, which could adversely affect our reported or future financial results, the trading price of our common stock and the trading price of the Convertible Notes.

In addition, under certain circumstances, convertible debt instruments (such as the Convertible Notes) that may be settled entirely or partly in cash may be accounted for utilizing the treasury stock method, the effect of which is that the shares issuable upon conversion of such Convertible Notes are not included in the calculation of diluted earnings per share except to the extent that the conversion value of such Convertible Notes exceeds their principal amount. Under the treasury stock method, for purposes of calculating diluted earnings per share, the transaction is accounted for by including in the denominator the number of shares of common stock that would be necessary to settle such excess, if CNX elected to settle such excess in shares. There is no assurance that the future accounting standards will continue to permit the use of the treasury stock method. If CNX is unable or otherwise elect not to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, then our diluted earnings per share could be adversely affected.

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

In connection with the pricing of the Convertible Notes, CNX entered into capped call transactions with certain financial institutions. The capped call transactions are expected generally to reduce the potential dilution to our common stock upon any conversion of the Convertible Notes and/or offset any potential cash payments CNX 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.

CNX is subject to counterparty performance risk with respect to the capped call transactions.

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

Conversion of the Convertible Notes may dilute the ownership interest of existing stockholders or may otherwise depress the price of our common stock.

The conversion of some or all of the Convertible Notes will dilute the ownership interests of existing stockholders to the extent CNX delivers shares of our common stock upon conversion of any of the Convertible Notes and the potential dilution is not reduced or offset by the capped call transactions CNX entered into. The Convertible Notes may become convertible at the option of holders prior to their scheduled terms under certain circumstances. Any sales in the public market of the common

stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the Convertible Notes may encourage short selling by market participants because the conversion of the Convertible Notes could be used to satisfy short positions, or anticipated conversion of the Convertible Notes into shares of our common stock could depress the price of our common stock.

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

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

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

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

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

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

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

Risks Related to Strategic Transactions

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are subject to risk and uncertainties, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition.

Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce superior rates of return. In developing our business plan, we consider allocating capital and other resources to various aspects of our businesses including well development, reserve acquisitions, exploratory activity, corporate items (including share and debt repurchases) and other ~~alternatives.~~alternatives, including investments into new proprietary technologies and strategies surrounding the generation and monetization of environmental attributes from our operations, including but not limited to carbon credit offsets. We also consider our likely sources of capital, including cash generated from operations and borrowings under our credit facilities.

Notwithstanding the determinations made in the development of our core business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and ~~dispositions.~~ dispositions and opportunities to monetize technological improvements to our operations.

If CNX fails to identify optimal business strategies, ~~or fails to~~ optimize our capital investment and capital raising opportunities, ~~and the~~ use of our other resources in furtherance of our business strategies, make appropriate capital investment decisions, or anticipate regulatory, policy and market changes associated with any of our strategic determinations, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

~~We do~~CNX does not completely control the timing of divestitures that ~~we plan~~CNX plans to engage in, and they may not provide anticipated benefits. Additionally, CNX may be unable to acquire additional properties in the future and any acquired properties may not provide the anticipated benefits.

Our business and financing plans may include divesting certain assets over time. However, ~~we do~~CNX does not completely control the timing of divestitures, and delays in completing divestitures may reduce the benefits CNX may receive from them, such as the timing of the receipt of cash proceeds. Also, there can be no assurance that the assets we divest will produce anticipated proceeds. Further, the terms of our existing indentures may place restrictions on our ability to divest or sell certain assets.

In the future CNX may make acquisitions of assets or businesses that complement or expand our current business. No assurance can be given that CNX will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire the identified targets. The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations and to identify and appropriately manage any liabilities assumed as part of the acquisition. The process of integrating acquired businesses or assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to make acquisitions in the future and successfully integrate the acquired businesses or assets into our existing operations could materially adversely affect our financial condition and results of operations.

There is no guarantee that CNX 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. Any determinations to repurchase shares of our common stock will be at the discretion of our board of directors based upon a review of all relevant considerations.

CNX currently has a repurchase program in place authorized by our board of directors, which is not subject to an expiration date, and for which ~~$245~~$994 million remains available for repurchases as of January ~~26, 2021.~~20, 2022. The repurchase program does not require us to acquire any specific number of shares. Our board of director’s determination to repurchase shares of our common stock will depend upon market conditions, applicable legal requirements, contractual obligations and other factors that the board of directors deems relevant. Based on an evaluation of these factors, our board of directors may determine not to repurchase shares or to repurchase shares at reduced levels from those anticipated by our shareholders. See Note 5 - Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion.

CNX 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; actions taken by the other partner or third-party operator may materially impact our financial position and results of operations; and we may not realize the benefits we expect to realize from a joint venture.

As is common in the natural gas industry, CNX may operate one or more of our properties with a joint venture partner, or contract with a third-party to control operations. These relationships could require us to share operational and other control, such that CNX may no longer have the flexibility to control completely the development of these properties. If ~~we do~~CNX does not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. CNX could also incur liability as a result of actions taken by a joint

venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our ~~business~~.business.

In connection with the separation of our coal business, CONSOL Energy has agreed to indemnify us for certain liabilities, and we have agreed to indemnify CONSOL Energy for certain liabilities. If we are required to pay under these indemnities

to CONSOL Energy, our financial results could be negatively impacted. The CONSOL Energy indemnity may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy has been allocated responsibility, and CONSOL Energy may not be able to satisfy its indemnification obligations in the future.

Pursuant to the Separation and Distribution Agreement and certain other agreements with CONSOL Energy, CNX and CONSOL Energy have agreed to indemnify the other for certain liabilities in each case for uncapped amounts. We remain liable as a guarantor on certain liabilities that were assumed by CONSOL Energy in connection with the separation. The estimated value of these guarantees was approximately ~~$146~~$129 million as of December 31, ~~2020.~~2021. Although CONSOL Energy agreed to indemnify us to the extent that we are called upon to pay any of these liabilities, there is no assurance that CONSOL Energy will satisfy its obligations to indemnify us in these situations. For example, we could be liable for liabilities assumed by Murray Energy and its subsidiaries (Murray Energy) in connection with the disposition of certain mines to Murray Energy in 2013 in the event that both Murray Energy and CONSOL Energy are unable to satisfy those liabilities.

Indemnities that CNX may be required to provide CONSOL Energy are not subject to any cap, may be significant and could negatively impact our business. Third parties could also seek to hold us responsible for any of the liabilities that CONSOL Energy has agreed to retain, including in respect of certain statutory obligations related to, among others, health and environmental matters. For example, see disclosure in Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding a lawsuit filed by the UMWA 1992 Benefit Plan against CNX and CONSOL Energy in May 2020.

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

Other General Risks

Cyber-incidents targeting our systems, oil and natural gas industry systems and infrastructure, or the systems of our ~~third party~~third-party service providers could materially adversely affect our business, financial condition or results of operations.

Cyber-incidents, including cyber-attacks, may significantly affect us or the operations of our customers and business partners, as well as impact general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, including energy-related assets, may be at greater risk of future incidents than other targets in the United States. A cyber incident could result in information theft, data corruption, operational disruption, including environmental and safety issues resulting from a loss of control of field equipment and assets, and/or financial loss. Consequently, it is possible that any of these occurrences, or a combination of them, could materially adversely affect our business, financial condition and ~~results of operations.~~impact our production. Our insurance may not protect us against all such occurrences.

The oil and natural gas industry has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves, monitor and control our field equipment and assets and perform other activities related to our businesses. Our business partners, including vendors, service providers and financial institutions, are also dependent on digital technology.

As dependence on digital technologies has increased the threat of cyber incidents, including deliberate attacks or unintentional events, have also increased. In addition, the risk of cyber-based attacks is heightened with many of our employees and contractors working and accessing our technology infrastructure remotely as a result of the COVID-19 pandemic. A cyber-incident could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA (supervisory control and data acquisition) based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

Our technologies, systems, networks, data centers and those of our business partners and suppliers may become the target of cyber-incidents or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of third-parties or ~~the cloud~~off-premise service providers could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, damage to our reputation, other operational disruptions and third-party liability, including the following:

•a cyber-incident impacting one of our vendors or service providers could result in supply chain disruptions, loss or corruption of our information or other negative consequences, any of which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

•a cyber-incident related to our facilities may result in equipment damage or ~~failure;~~failure.

•a cyber-incident impacting a communications network or power grid could cause operational disruption resulting in ~~loss of revenues;~~impact to our production.

•a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

•business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our stock.

Our implementation of various internal and ~~externally-facing~~externally facing controls and processes, including appropriate internal risk assessment and internal policy implementation, ~~globally~~ incorporating a risk-based cyber security framework to monitor and mitigate security threats and other strategies to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches or other cyber-incidents from occurring. As cyber threats continue to evolve, CNX may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Cyber-attacks continue to evolve in frequency and complexity. While no industry is immune Industrial Networks have come under increased targeted attacks in the last year (examples, Colonial Pipeline and JBS Foods Group). This has led to increased scrutiny by Cyber Insurance Carriers. As a result, securing a policy with sufficient protection has become more challenging. Our ability to obtain insurance to mitigate the financial impact of cyber incidents may be challenged by the future prevalence and nature of incidences experienced by companies and insurance markets willingness to underwrite this risk.

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

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could materially adversely affect our business. Furthermore, competition for experienced technical and other professional personnel, as well as diverse candidates which bring with them valuable perspectives and experiences, remains strong. If CNX cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

Terrorist activities could materially adversely affect our business and results of operations.

Terrorist attacks, including eco-terrorism, and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could affect the energy industry, the environment and industry related economic conditions, including our operations and the operations of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, including energy-related assets, may be at greater risk of future attacks than other targets in the United States. The occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially adversely affect our business and results of operations. Our insurance may not protect us against such occurrences.

ITEM 1B.Unresolved Staff Comments

None.

ITEM 2.Properties

See ~~"Detail~~“Detail of ~~Operations"~~Operations” in Part I. Item 1 of this Form 10-K for a description of CNX's properties.

ITEM 3.Legal Proceedings

The first two paragraphs of “Note ~~20–~~20 – Commitments and Contingent Liabilities” in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K are incorporated herein by reference.

ITEM 4.Mine Safety Disclosures

Not applicable.

PART II

ITEM 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company's common stock is listed on the New York Stock Exchange under the symbol CNX.

As of December 31, ~~2020,~~2021, there were ~~102~~97 holders of record of our common stock.

The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CNX to the cumulative shareholder return for the same period of a peer group and the Standard & Poor's 500 Stock Index. The peer group has changed from the prior year in order to continue to benchmark CNX against core peers found in the Appalachian Basin. The current peer group is comprised of CNX, Antero Resources Corporation, ~~Cabot Oil & Gas~~Chesapeake Energy Corporation, EQT Corporation, Gulfport Energy Corporation, Range Resources Corporation and Southwestern Energy Co. The graph assumes that the value of the investment in CNX common stock and each index was $100 at December 31, ~~2015.~~2016. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, ~~2020.~~2021.


		2015	2016	2017	2018	2019	2020		2016	2017	2018	2019	2020	2021
CNX Resources Corporation	CNX Resources Corporation	100.0	230.9	214.0	167.2	129.6	158.1	CNX Resources Corporation	100.0	92.7	72.4	56.1	68.5	87.1
Peer Group	Peer Group	100.0	130.1	107.3	60.4	39.1	43.2	Peer Group	100.0	69.1	33.0	17.3	18.9	42.3
S&P 500 Stock Index	S&P 500 Stock Index	100.0	109.5	130.7	122.6	158.1	183.8	S&P 500 Stock Index	100.0	119.4	112.0	144.4	167.9	213.1

Previous Peer Group								Previous Peer Group	100.0	82.5	46.4	30.1	33.2	77.8

Cumulative Total Shareholder Return Among CNX Resources Corporation, Peer Group and S&P 500 Stock Index

The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).

The determination to declare and pay dividends is made by CNX's Board of Directors. CNX ~~suspended~~has not paid dividends on its ~~quarterly dividend starting in March 2016 to support the Company's increased emphasis on growth at that time.~~common stock since 2016. Any 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 other factors as the Board of Directors deems relevant.

The Company's Credit Facility currently limits CNX's ability to pay dividends in excess of an annual rate of $0.10 per share when the Company's net leverage ratio exceeds 3.00 to 1.00 and is subject to availability under the Credit Facility of at least ~~15%~~20% of the aggregate ~~commitments. The Company's net leverage ratio was 2.45 to 1.00 at December 31, 2020.~~commitments and there being no borrowing base deficiency. The Credit Facility does not permit such dividend payments ~~in the~~when an event of ~~default.~~default has occurred and is continuing. The indentures to the 7.25% Senior Notes due in March 2027 and the 6.00% Senior Notes due in January 2029 limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults under the Company’s Credit Facility or Notes in the year ended December 31, ~~2020.~~2021.

Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth repurchases of our common stock during the three months ended December 31, ~~2020:~~2021:


ISSUER PURCHASES OF EQUITY SECURITIES	ISSUER PURCHASES OF EQUITY SECURITIES							ISSUER PURCHASES OF EQUITY SECURITIES
Period	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)		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)
October 1, 2020- October 31, 2020		—	$	—	—	$	148,466
November 1, 2020- November 30, 2020		725,784	$	9.63	725,641	$	141,480
December 1, 2020- December 31, 2020		3,418,437	$	10.60	3,412,886	$	105,302
October 1, 2021- October 31, 2021								October 1, 2021- October 31, 2021	788,669	$	12.95	788,009	$	1,123,738
November 1, 2021- November 30, 2021								November 1, 2021- November 30, 2021	4,140,622	$	14.46	4,140,622	$	1,063,853
December 1, 2021- December 31, 2021								December 1, 2021- December 31, 2021	3,551,009	$	13.92	3,551,009	$	1,014,424
Total	Total	4,144,221						Total	8,480,300			8,479,640

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

(2) Shares repurchased as part of the Company's current ~~$750~~$1,900 million share repurchase program authorized by the Board of Directors, ~~on October 30, 2017 and subsequently amended from time to time,~~ which is not subject to an expiration date. ~~The amount of shares that may yet be purchased under the Plan does not include a $150 million increase authorized by the Board of Directors on January 26, 2021 (See~~See Note 5 - Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional ~~information).~~information.

See Part III. Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to CNX's equity compensation plans.

42ITEM 6. Reserved

Not applicable.

~~ITEM 6.Selected Financial Data~~

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2020, 2019, 2018, 2017 and 2016 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2020 presentation. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with Part II. Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Form 10k.

(Dollars in thousands, except per share data) For the Years Ended December 31,
2020 2019 2018 2017 2016
Revenue and Other Operating Income from Continuing Operations $ 1,257,978 $ 1,922,449 $ 1,730,434 $ 1,455,131 $ 759,968
(Loss) Income from Continuing Operations $ (428,744) $ 31,948 $ 883,111 $ 295,039 $ (550,945)
Net (Loss) Income Attributable to CNX Resources Shareholders $ (483,775) $ (80,730) $ 796,533 $ 380,747 $ (848,102)
Earnings per share:
Basic:
(Loss) Income from Continuing Operations $ (2.43) $ (0.42) $ 3.75 $ 1.29 $ (2.40)
Income (Loss) from Discontinued Operations — — — 0.37 (1.30)
Net (Loss) Income $ (2.43) $ (0.42) $ 3.75 $ 1.66 $ (3.70)
Diluted:
(Loss) Income from Continuing Operations $ (2.43) $ (0.42) $ 3.71 $ 1.28 $ (2.40)
Income (Loss) from Discontinued Operations — — — 0.37 (1.30)
Net (Loss) Income $ (2.43) $ (0.42) $ 3.71 $ 1.65 $ (3.70)
Assets from Continuing Operations $ 8,041,764 $ 9,060,806 $ 8,592,170 $ 6,931,913 $ 6,682,770
Assets from Discontinued Operations — — — — 2,496,921
Total Assets $ 8,041,764 $ 9,060,806 $ 8,592,170 $ 6,931,913 $ 9,179,691
Long-Term Debt from Continuing Operations (including current portion) $ 2,424,001 $ 2,754,443 $ 2,378,205 $ 2,187,289 $ 2,422,472
Long-Term Debt from Discontinued Operations (including current portion) — — — — 302,200
Total Long-Term Debt (including current portion) $ 2,424,001 $ 2,754,443 $ 2,378,205 $ 2,187,289 $ 2,724,672
Cash Dividends Declared Per Share of Common Stock $ — $ — $ — $ — $ 0.010

See Part 1. Item 1A. “Risk Factors” and Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of an adjustment to operating income for all periods and other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.

~~OTHER OPERATING DATA~~

~~(unaudited)~~

Years Ended December 31,
2020 2019 2018 2017 2016
Gas:
Net Sales Volumes Produced (in Bcfe) 511.1 539.1 507.1 407.2 394.4
Average Sales Price ($ per Mcfe) (A) $ 2.49 $ 2.66 $ 2.97 $ 2.66 $ 2.63
Average Cost ($ per Mcfe) $ 1.64 $ 1.72 $ 1.82 $ 2.23 $ 2.32
Proved Reserves (in Bcfe) (B) 9,550 8,426 7,881 7,582 6,252

~~____________~~

~~(A) Represents average net sales price including the effect of derivative transactions and excluding hedge monetizations.~~

~~(B) Represents proved developed and undeveloped gas reserves at period end.~~

4344

ITEM 7.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-K. 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 views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from 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.” CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

General

COVID-19 Update:

CNX continues to monitor the current and potential impacts of the coronavirus COVID-19 ~~("COVID-19"~~(“COVID-19”) pandemic on all aspects of our business and geographies, including how it has impacted, and may in the future impact, our operations, financial results, liquidity, contractors, customers, employees and vendors. ~~The Company also continues to monitor a number of factors that may cause actual results of operations to differ from our historical results or current expectations.~~More information regarding these considerations is located in Item 1A Risk Factors. 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-K are not necessarily indicative of future operating results.

While CNX did not incur significant disruptions to operations during the ~~year~~years ended December 31, 2021 or 2020 as a direct result of the COVID-19 pandemic, CNX is unable to predict the full extent of the future impact that the COVID-19 pandemic ~~will~~could have on ~~us,~~the Company, including our financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous ~~uncertainties.~~uncertainties outside the Company’s control.

The full extent of the future impact of the COVID-19 pandemic on the Company’s operational and financial performance is currently uncertain and will depend on many factors outside the Company’s control, including, without limitation, the timing, extent, trajectory and duration of the pandemic, the development and availability of effective treatments and vaccines, the imposition of protective public safety measures, and the impact of the pandemic on the global economy and demand for consumer products. Refer to Part I, Item 1A of this Form 10-K under the heading “Risk Factors,” for more information.

~~2020~~2021 Highlights:

•Increased proved developed reserves to ~~9.5~~5.9 Tcfe, ~~13.3%~~13.5% higher than ~~2019.~~2020.

•Total gas production of ~~511.1~~590.2 Bcfe.

•Shale production of ~~458.3~~540.4 Bcfe.

•Repurchased ~~$43~~$241 million or 18.3 million shares of CNX common stock on the open market.

•On September 28, 2020, CNX completed the acquisition of all of the outstanding common units of CNX Midstream Partners LP ("CNXM") and CNXM became an indirect wholly-owned subsidiary (the “Merger”) (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K).Reduced Long-Term Debt by $187 million.

~~2021~~

2022 Outlook:

•Our ~~2021~~2022 annual gas production is expected to be approximately ~~540-570~~575-605 Bcfe.

•Our ~~2021~~2022 E&P capital expenditures are expected to be approximately ~~$430-~~$470-$~~470~~500 million.

4445

Results of Operations:~~Year Ended~~

The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 2021 to the year ended December 31, 2020. A similar discussion and analysis that compares year ended December 31, 2020 ~~Compared with~~to the ~~Year Ended~~fiscal year ended December 31, 2019 may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Form 10-K for the year ended December 31, 2020, which is incorporated herein by reference.

Net Loss Attributable to CNX Resources Shareholders

CNX reported a net loss attributable to CNX Resources shareholders of $499 million, or a loss per diluted share of $2.31, for the year ended December 31, 2021, compared to a net loss attributable to CNX Resources shareholders of $484 million, or a loss per diluted share of $2.43, for the year ended December 31, ~~2020, compared to a net loss attributable to CNX Resources shareholders of $81 million, or a loss per diluted share of $0.42, for the year ended December 31, 2019.~~2020.


		For the Years Ended December 31,							For the Years Ended December 31,
(Dollars in thousands)	(Dollars in thousands)	2020		2019		Variance		(Dollars in thousands)	2021		2020		Variance
Net (Loss) Income		$	(428,744)	$	31,948	$	(460,692)
Net Loss								Net Loss	$	(498,643)	$	(428,744)	$	(69,899)
Less: Net Income Attributable to Noncontrolling Interests	Less: Net Income Attributable to Noncontrolling Interests	55,031		112,678		(57,647)		Less: Net Income Attributable to Noncontrolling Interests	—		55,031		(55,031)
Net Loss Attributable to CNX Resources Shareholders	Net Loss Attributable to CNX Resources Shareholders	$	(483,775)	$	(80,730)	$	(403,045)	Net Loss Attributable to CNX Resources Shareholders	$	(498,643)	$	(483,775)	$	(14,868)

Included in the loss for the year ended December 31, 2021 was an unrealized loss on commodity derivative instruments of $1,094 million. Included in the loss for the year ended December 31, 2020 was an unrealized loss on commodity derivative instruments of $288 million, a $62 million non-cash impairment charge related to exploration and production properties specific to our Southwestern Pennsylvania (SWPA) CBM asset group (See Note 8 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K), and a $473 million non-cash impairment charge related to goodwill (See Note 9 - Goodwill and ~~an unrealized loss on commodity derivatives of $288 million. Included~~Other Intangible Assets in the ~~loss for~~Notes to the year ended December 31, 2019 was a $327 million non-cash impairment charge related to exploration and production properties and a $119 million non-cash impairment charge related to unproved properties and expirations, both were associated with the Company's Central Pennsylvania (CPA) acreage, offset,Audited Consolidated Financial Statements in ~~part, by an unrealized gain on commodity derivative instruments~~Item 8 of ~~$306 million.~~this Form 10-K).

Prior to the effective time of the Merger on September 28, 2020 (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K), public unitholders held a 46.9% equity interest in CNXM and CNX owned the remaining 53.1% equity ~~interest.~~interest and following the Merger CNX owns 100% of the equity interests of CNXM. . The earnings of CNXM that were attributed to its common units held by the public prior to the Merger are reflected in Net Income Attributable to Noncontrolling Interest in the Consolidated Statements of Income. There were no changes in our ownership interest in CNXM during the year ended December 31, ~~2019.~~2021.

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 excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 21 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). These expenses include, but are not limited to, interest expense, impairment of exploration and production properties, impairment of goodwill, 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 Years Ended December 31,
(Dollars in millions)	2021		2020
Total Revenue and Other Operating Income	$	757	$	1,258
Add (Deduct):
Purchased Gas Revenue	(100)		(106)
Loss on Commodity Derivative Instruments and Monetization	1,094		204
Other Revenue and Operating Income	(106)		(82)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	$	1,645	$	1,274

Total Operating Expense	$	1,235	$	1,697
Add (Deduct):
Depreciation, Depletion and Amortization (DD&A) - Corporate	(11)		(10)
Exploration and Production Related Other Costs	(21)		(15)
Purchased Gas Costs	(94)		(101)
Impairment of Exploration and Production Properties	—		(62)
Impairment of Goodwill	—		(473)
Selling, General and Administrative Costs	(113)		(109)
Other Operating Expense	(68)		(85)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1	$	928	$	842

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.

Selected ~~Operating Revenue~~Natural Gas, NGL and ~~Other Cost~~Oil Production Financial Data

The following table presents a summary of our total sales volumes, ~~revenue,~~sales of natural gas, NGL and oil including cash settlements, natural gas, NGL and oil production costs ~~average sales prices (including the effects of settled derivatives~~ and ~~excluding hedge monetizations)~~natural gas, NGL and ~~average unit costs for~~oil production margin related to our production operations on a total ~~Company basis:~~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 Years Ended December 31,													For the Years Ended December 31,
		2020				2019				Variance					2021				2020				Variance
		in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe			in Millions		Per Mcfe		in Millions		Per Mcfe		in Millions		Per Mcfe
Total Sales Volumes (Bcfe)*	Total Sales Volumes (Bcfe)*			511.1				539.1				(28.0)		Total Sales Volumes (Bcfe)*			590.2				511.1				79.1

Natural Gas, NGL and Oil Revenue	Natural Gas, NGL and Oil Revenue	$	897	$	1.71	$	1,364	$	2.52	$	(467)	$	(0.81)	Natural Gas, NGL and Oil Revenue	$	2,184	$	3.77	$	897	$	1.71	$	1,287	$	2.06
Gain on Commodity Derivative Instruments - Cash Settlement - Gas**		377		0.78		70		0.14		307		0.64
Total Revenue		1,274		2.49		1,434		2.66		(160)		(0.17)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas**														(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas**	(539)		(0.98)		377		0.78		(916)		(1.76)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure														Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure	1,645		2.79		1,274		2.49		371		0.30
Lease Operating Expense	Lease Operating Expense	40		0.08		65		0.12		(25)		(0.04)		Lease Operating Expense	46		0.08		40		0.08		6		—
Production, Ad Valorem, and Other Fees	Production, Ad Valorem, and Other Fees	24		0.04		27		0.05		(3)		(0.01)		Production, Ad Valorem, and Other Fees	34		0.06		24		0.04		10		0.02
Transportation, Gathering and Compression	Transportation, Gathering and Compression	286		0.56		331		0.61		(45)		(0.05)		Transportation, Gathering and Compression	344		0.58		286		0.56		58		0.02
Depreciation, Depletion and Amortization (DD&A)	Depreciation, Depletion and Amortization (DD&A)	492		0.96		506		0.94		(14)		0.02		Depreciation, Depletion and Amortization (DD&A)	504		0.85		492		0.96		12		(0.11)
Average Costs		842		1.64		929		1.72		(87)		(0.08)
Average Margin		$	432	$	0.85	$	505	$	0.94	$	(73)	$	(0.09)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure														Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure	928		1.57		842		1.64		86		(0.07)
Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure														Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure	$	717	$	1.22	$	432	$	0.85	$	285	$	0.37

*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.

**Excluding hedge monetizations.

4547

The ~~decrease~~79.1 Bcfe increase in volumes in the ~~period-to-period~~period-to period comparison was primarily due to the ~~strategic temporary shut-in~~turn-in-line of ~~certain~~new wells ~~to take advantage of higher prices later~~throughout 2020 and 2021. Additionally, in 2020 the ~~year and thereby optimize the overall value of the assets. Twenty-two dry gas turn-in-lines from April and May were~~Company temporarily shut-in ~~through September~~new turn-in-line wells as a result of low natural gas and ~~a portion of CNX's liquids-rich Shirley-Pennsboro~~NGL pricing. The increases were offset in part by normal production ~~was shut-in during May and June of 2020. Normal production declines also contributed to the decrease in total volumes.~~declines.

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

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

•~~Transportation, gathering~~Production, ad valorem and ~~compression expense decreased on a per unit basis primarily due to lower processing costs due to a drier production mix and a decrease in firm transportation costs due to lower gas sales volumes.~~

•~~Depreciation, depletion and amortization expense~~other fees increased on a per unit basis as a result of ~~fixed depreciation~~increased realized prices on natural gas and natural gas liquids as well as the change in production mix by state as new wells were turned-in-line.

•Transportation, gathering and compression expense increased on a per unit basis primarily due to increased processing costs ~~related~~due to ~~CNX's gathering infrastructure being spread over fewer~~a wetter production ~~volumes in 2020. The lower production volumes were the~~mix, and increased firm transportation costs.

•Depreciation, depletion and amortization expense decreased on a per unit basis as a result of low cost reserve additions from development during the ~~strategic temporary shut-in~~2020 period in SWPA, the addition of ~~certain~~proved undeveloped Shale wells ~~as previously discussed.~~in the Central Pennsylvania (CPA), and an impairment recognized in CBM in the 2020 period.

Average Realized Price Reconciliation

The following table ispresents a ~~summary~~breakout of total other revenue and operating income and selected other expense line items that are included in the total loss before income tax on a total company Mcfe equivalent and excluded from the previous table.

For the Years Ended December 31,
2020 2019 Variance
in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe
Total Company Sales Volumes (Bcfe)* 511.1 539.1 (28.0)
Total Other Revenue and Operating Income $ 82 $ 0.16 $ 88 $ 0.16 $ (6) $ 0.00
Depreciation, Depletion and Amortization $ 10 $ 0.02 $ 2 $ 0.00 $ 8 $ 0.02
Exploration and Production Related Other Costs 15 0.03 44 0.08 (29) (0.05)
Selling, General and Administrative Costs 109 0.21 144 0.27 (35) (0.06)
Other Operating Expense 85 0.17 80 0.15 5 0.02
Total Selected Operating Costs and Expenses 219 0.43 270 0.50 (51) (0.07)
Other Expense 24 0.05 3 0.01 21 0.04
Interest Expense 171 0.33 151 0.28 20 0.05
Total Selected Other Expense 195 0.38 154 0.29 41 0.09
Total Selected Costs and Expenses $ 414 $ 0.81 $ 424 $ 0.79 $ (10) $ 0.02
* 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 oilliquids and natural gas ~~which is not indicative~~sales information and settled derivative information to assist in the understanding of the ~~relationship of NGL, condensate, and~~Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives:


	For the Years Ended December 31,
in thousands (unless noted)	2021		2020		Variance		Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe)	35,858		28,062		7,796		27.8	%
Sales Volume (Mbbls)	5,976		4,677		1,299		27.8	%
Gross Price ($/Bbl)	$	33.90	$	13.74	$	20.16	146.7	%
Gross NGL Revenue	$	202,670	$	64,138	$	138,532	216.0	%

Oil/Condensate:
Sales Volume (MMcfe)	2,401		1,584		817		51.6	%
Sales Volume (Mbbls)	400		264		136		51.5	%
Gross Price ($/Bbl)	$	56.32	$	35.91	$	20.41	56.8	%
Gross Oil/Condensate Revenue	$	22,541	$	9,475	$	13,066	137.9	%

GAS
Sales Volume (MMcf)	551,989		481,426		70,563		14.7	%
Sales Price ($/Mcf)	$	3.55	$	1.71	$	1.84	107.6	%
Gross Gas Revenue	$	1,958,718	$	823,132	$	1,135,586	138.0	%

Hedging Impact ($/Mcf)	$	(0.98)	$	0.78	$	(1.76)	(225.6)	%
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement*	$	(539,016)	$	377,219	$	(916,235)	(242.9)	%

*Excluding gains from hedge monetizations

The increase in gross revenue was primarily the result of the $1.84 per Mcf increase in natural gas prices, when excluding the impact of hedging, the 79.1 Bcfe increase in sales volumes and the $20.16 per Bbl increase in NGL prices. These increases were offset, in part, by the impact of the change in the realized (loss) gain on commodity derivative instruments related to the Company's hedging program.

SEGMENT ANALYSIS for the year ended December 31, 2021 compared to the year ended December 31, 2020:


	For the Year Ended								Difference to Year Ended
	December 31, 2021								December 31, 2020
(in millions)	Shale		CBM		Other		Total		Shale		CBM		Other		Total
Natural Gas, NGLs and Oil Revenue	$	1,989	$	194	$	1	$	2,184	$	1,208	$	80	$	(1)	$	1,287
Loss on Commodity Derivative Instruments	(492)		(47)		(1,094)		(1,633)		(829)		(87)		(890)		(1,806)
Purchased Gas Revenue	—		—		100		100		—		—		(6)		(6)
Other Revenue and Operating Income	81		—		25		106		16		—		8		24
Total Revenue and Other Operating Income (Loss)	1,578		147		(968)		757		395		(7)		(889)		(501)
Lease Operating Expense	34		13		(1)		46		8		(1)		(1)		6
Production, Ad Valorem, and Other Fees	27		7		—		34		8		2		—		10
Transportation, Gathering and Compression	303		40		1		344		55		1		2		58
Depreciation, Depletion and Amortization	440		58		17		515		24		(12)		1		13
Impairment of Exploration and Production Properties	—		—		—		—		—		—		(62)		(62)

Impairment of Goodwill	—		—		—		—		—		—		(473)		(473)
Exploration and Production Related Other Costs	—		—		21		21		—		—		6		6
Purchased Gas Costs	—		—		94		94		—		—		(7)		(7)
Selling, General and Administrative Costs	—		—		113		113		—		—		4		4
Other Operating Expense	—		—		68		68		—		—		(17)		(17)
Total Operating Costs and Expenses	804		118		313		1,235		95		(10)		(547)		(462)
Other Expense	—		—		16		16		—		—		(8)		(8)
Gain on Asset Sales and Abandonments, net	—		—		(42)		(42)		—		—		(21)		(21)

Loss on Debt Extinguishment	—		—		34		34		—		—		44		44
Interest Expense	—		—		151		151		—		—		(20)		(20)
Total Other Expenses	—		—		159		159		—		—		(5)		(5)
Total Costs and Expenses	804		118		472		1,394		95		(10)		(552)		(467)
Earnings (Loss) Before Income Tax	$	774	$	29	$	(1,440)	$	(637)	$	300	$	3	$	(337)	$	(34)

~~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 Years Ended December 31,
in thousands (unless noted) 2020 2019 Variance Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe) 28,062 32,571 (4,509) (13.8) %
Sales Volume (Mbbls) 4,677 5,428 (751) (13.8) %
Gross Price ($/Bbl) $ 13.74 $ 19.20 $ (5.46) (28.4) %
Gross NGL Revenue $ 64,138 $ 104,139 $ (40,001) (38.4) %
Oil/Condensate:
Sales Volume (MMcfe) 1,584 1,223 361 29.5 %
Sales Volume (Mbbls) 264 204 60 29.4 %
Gross Price ($/Bbl) $ 35.91 $ 45.00 $ (9.09) (20.2) %
Gross Oil/Condensate Revenue $ 9,475 $ 9,173 $ 302 3.3 %
GAS
Sales Volume (MMcf) 481,426 505,355 (23,929) (4.7) %
Sales Price ($/Mcf) $ 1.71 $ 2.48 $ (0.77) (31.0) %
Gross Gas Revenue $ 823,132 $ 1,251,013 $ (427,881) (34.2) %
Hedging Impact ($/Mcf) $ 0.78 $ 0.14 $ 0.64 457.1 %
Gain on Commodity Derivative Instruments - Cash Settlement* $ 377,219 $ 69,780 $ 307,439 440.6 %

*Excluding gains from hedge monetizations

The decrease in gross revenue was primarily the result of the $0.77 per Mcf decrease in general natural gas prices, when excluding the impact of hedging, in the markets in which CNX sells its natural gas and the 28.0 Bcfe decrease in sales volumes. The decrease in gross revenue was offset, in part, by the increase in the realized gain on commodity derivative instruments related to the Company's hedging program.

~~SEGMENT ANALYSIS for the year ended December 31, 2020 compared to the year ended December 31, 2019:~~

For the Year Ended Difference to Year Ended
December 31, 2020 December 31, 2019
(in millions) Shale CBM Other Total Shale CBM Other Total
Natural Gas, NGLs and Oil Revenue $ 781 $ 114 $ 2 $ 897 $ (418) $ (50) $ 1 $ (467)
Gain (Loss) on Commodity Derivative Instruments 337 40 (204) 173 275 33 (511) (203)
Purchased Gas Revenue — — 106 106 — — 12 12
Other Revenue and Operating Income 65 — 17 82 (9) — 3 (6)
Total Revenue and Other Operating Income 1,183 154 (79) 1,258 (152) (17) (495) (664)
Lease Operating Expense 26 14 — 40 (23) (2) — (25)
Production, Ad Valorem, and Other Fees 19 5 — 24 (2) (2) 1 (3)
Transportation, Gathering and Compression 248 39 (1) 286 (42) (1) (2) (45)
Depreciation, Depletion and Amortization 416 70 16 502 (10) (3) 7 (6)
Impairment of Exploration and Production Properties — — 62 62 — — (265) (265)
Impairment of Unproved Properties and Expirations — — — — — — (119) (119)
Impairment of Goodwill — — 473 473 — — 473 473
Exploration and Production Related Other Costs — — 15 15 — — (29) (29)
Purchased Gas Costs — — 101 101 — — 10 10
Other Operating Expense — — 85 85 — — 5 5
Selling, General and Administrative Costs — — 109 109 — — (35) (35)
Total Operating Costs and Expenses 709 128 860 1,697 (77) (8) 46 (39)
Other Expense — — 24 24 — — 21 21
Gain on Asset Sales and Abandonments, net — — (21) (21) — — 15 15
Gain on Debt Extinguishment — — (10) (10) — — (18) (18)
Interest Expense — — 171 171 — — 20 20
Total Other Expenses — — 164 164 — — 38 38
Total Costs and Expenses 709 128 1,024 1,861 (77) (8) 84 (1)
Earnings (Loss) Before Income Tax $ 474 $ 26 $ (1,103) $ (603) $ (75) $ (9) $ (579) $ (663)

4849

SHALE SEGMENT

The Shale segment had earnings before income tax of $774 million for the year ended December 31, 2021 compared to earnings before income tax of $474 million for the year ended December 31, ~~2020 compared to earnings before income tax of $549 million for the year ended December 31, 2019.~~2020.


		For the Years Ended December 31,									For the Years Ended December 31,
		2020		2019		Variance		Percent Change			2021		2020		Variance		Percent Change
Shale Gas Sales Volumes (Bcf)	Shale Gas Sales Volumes (Bcf)	428.7		449.6		(20.9)		(4.6)	%	Shale Gas Sales Volumes (Bcf)	502.2		428.7		73.5		17.1	%
NGLs Sales Volumes (Bcfe)*	NGLs Sales Volumes (Bcfe)*	28.1		32.6		(4.5)		(13.8)	%	NGLs Sales Volumes (Bcfe)*	35.8		28.1		7.7		27.4	%
Oil/Condensate Sales Volumes (Bcfe)*	Oil/Condensate Sales Volumes (Bcfe)*	1.5		1.2		0.3		25.0	%	Oil/Condensate Sales Volumes (Bcfe)*	2.4		1.5		0.9		60.0	%
Total Shale Sales Volumes (Bcfe)*	Total Shale Sales Volumes (Bcfe)*	458.3		483.4		(25.1)		(5.2)	%	Total Shale Sales Volumes (Bcfe)*	540.4		458.3		82.1		17.9	%

Average Sales Price - Gas (per Mcf)	Average Sales Price - Gas (per Mcf)	$	1.65	$	2.42	$	(0.77)	(31.8)	%	Average Sales Price - Gas (per Mcf)	$	3.51	$	1.65	$	1.86	112.7	%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)		$	0.79	$	0.14	$	0.65	464.3	%
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)										(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(0.98)	$	0.79	$	(1.77)	(224.1)	%
Average Sales Price - NGLs (per Mcfe)*	Average Sales Price - NGLs (per Mcfe)*	$	2.29	$	3.20	$	(0.91)	(28.4)	%	Average Sales Price - NGLs (per Mcfe)*	$	5.65	$	2.29	$	3.36	146.7	%
Average Sales Price - Oil/Condensate (per Mcfe)*	Average Sales Price - Oil/Condensate (per Mcfe)*	$	5.83	$	7.47	$	(1.64)	(22.0)	%	Average Sales Price - Oil/Condensate (per Mcfe)*	$	9.38	$	5.83	$	3.55	60.9	%

Total Average Shale Sales Price (per Mcfe)	Total Average Shale Sales Price (per Mcfe)	$	2.44	$	2.61	$	(0.17)	(6.5)	%	Total Average Shale Sales Price (per Mcfe)	$	2.77	$	2.44	$	0.33	13.5	%
Average Shale Lease Operating Expenses (per Mcfe)	Average Shale Lease Operating Expenses (per Mcfe)	0.06		0.10		(0.04)		(40.0)	%	Average Shale Lease Operating Expenses (per Mcfe)	0.06		0.06		—		—	%
Average Shale Production, Ad Valorem, and Other Fees (per Mcfe)		0.04		0.05		(0.01)		(20.0)	%
Average Shale Production, Ad Valorem and Other Fees (per Mcfe)										Average Shale Production, Ad Valorem and Other Fees (per Mcfe)	0.05		0.04		0.01		25.0	%
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.54		0.60		(0.06)		(10.0)	%	Average Shale Transportation, Gathering and Compression Costs (per Mcfe)	0.56		0.54		0.02		3.7	%
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.91		0.88		0.03		3.4	%	Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)	0.82		0.91		(0.09)		(9.9)	%
Total Average Shale Costs (per Mcfe)		$	1.55	$	1.63	$	(0.08)	(4.9)	%
Average Margin for Shale (per Mcfe)		$	0.89	$	0.98	$	(0.09)	(9.2)	%
Total Average Shale Production Costs (per Mcfe)										Total Average Shale Production Costs (per Mcfe)	$	1.49	$	1.55	$	(0.06)	(3.9)	%
Total Average Shale Production Margin (per Mcfe)										Total Average Shale Production Margin (per Mcfe)	$	1.28	$	0.89	$	0.39	43.8	%

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,989 million for the year ended December 31, 2021 compared to $781 million for the year ended December 31, ~~2020 compared to $1,199~~2020. The $1,208 million ~~for the year ended December 31, 2019. The $418 million decrease~~increase was due ~~primary~~primarily to a ~~31.8% decrease in the average sales price for natural gas, a 5.2% decrease~~17.9% increase in total Shale gas sales volumes, and a ~~28.4% decrease~~13.5% increase in the total average Shale sales ~~price of NGLs.~~price.

The ~~decrease~~increase in total Shale gas sales volumes ~~in the period-to-period comparison~~ was primarily due to the ~~strategic~~turn-in-line of new wells throughout 2020 and 2021. The increase was also due to the temporary shut-in of ~~certain~~new turn-in-line wells in 2020 due to ~~take advantage of higher~~low natural gas prices, ~~later~~offset in the year and thereby optimize the overall value of the assets. Twenty-two dry gas turn-in-lines from April and May were temporarily shut-in through September and a portion of CNX's liquids-rich Shirley-Pennsboropart by normal production ~~was shut-in during May and June of 2020. Normal production declines also contributed to the decrease in total volumes.~~declines.

The ~~decrease~~increase in total average Shale sales price was primarily due to a ~~$0.77~~$1.86 per Mcf ~~decrease~~increase in average gas sales price and a ~~$0.91~~$3.36 per Mcfe ~~decrease~~increase in the average NGL sales price. These ~~decreases~~increases were offset in part by a ~~$0.65~~$1.77 per Mcf ~~increase~~change in the realized (loss) gain on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately ~~412.1~~429.4 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, ~~2020~~2021 at an average ~~realized gain~~loss of ~~$0.82~~$1.15 per Mcf hedged. For the year ended December 31, ~~2019,~~2020, these financial hedges represented approximately ~~348.1~~412.1 Bcf at an average ~~realized~~ gain of ~~$0.18~~$0.82 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $804 million for the year ended December 31, 2021 compared to $709 million for the year ended December 31, ~~2020 compared to $786 million for the year ended December 31, 2019.~~2020. The ~~decrease~~increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:

•Shale lease operating ~~expense was~~expenses were $34 million for the year ended December 31, 2021 compared to $26 million for the year ended December 31, ~~2020, compared~~2020. The increase in total dollars was primarily related to ~~$49~~an increase in production volumes.

•Shale production, ad valorem and other fees were $27 million for the year ended December 31, ~~2019.~~2021 compared to $19 million for the year ended December 31, 2020. The ~~decrease~~increases in total dollars ~~was~~and unit costs were primarily due to ~~a decrease~~increased realized prices on natural gas and natural gas liquids as well as the change in ~~water disposal costs in the current period resulting from an increase in the reuse of produced water in well completions activity. The decrease in unit costs was driven~~production mix by ~~the decrease in total dollars.~~state as new wells were turned-in-line.

4950

•Shale transportation, gathering and compression costs were $303 million for the year ended December 31, 2021 compared to $248 million for the year ended December 31, ~~2020 compared to $290 million for the year ended December 31, 2019.~~2020. The ~~decreases~~increase in total dollars ~~and unit costs were~~was primarily related to ~~lower~~the increase in total production volumes and increased processing costs due to a ~~drier~~wetter production mix. ~~Lower~~The increase in unit costs was primarily due to increased processing costs due to a wetter production mix and an increase in firm transportation ~~costs from lower gas sales volumes also contributed to the decrease in total dollars.~~costs.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $440 million for the year ended December 31, 2021 compared to $416 million for the year ended December 31, ~~2020 compared to $426 million for the year ended December 31, 2019.~~2020. The ~~decrease is~~increase in total dollars was due to ~~lower~~the increase in production volumes. These amounts ~~each~~ included depletion on a unit of production basis of $0.71 per Mcfe and $0.81 per ~~Mcfe.~~Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of low-cost reserve additions from development in 2020 in SWPA as well as the addition of proved undeveloped Shale reserves in CPA. 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 $81 million for the year ended December 31, 2021 compared to $65 million for the year ended December 31, ~~2020 compared to $74 million for the year ended December 31, 2019.~~2020. The ~~decrease~~increase in the period-to-period comparison was primarily due to ~~a reduction in volumes transported due to~~ temporary production curtailments by ~~third-party producers~~third party customers that occurred in early 2020 due to low prices. Those curtailments were restored to full production in the ~~2020 period.~~latter half of 2020.

COALBED METHANE (CBM) SEGMENT

The CBM segment had earnings before income tax of $29 million for the year ended December 31, 2021 compared to earnings before income tax of $26 million for the year ended December 31, ~~2020 compared to earnings before income tax of $35 million for the year ended December 31, 2019.~~2020.


		For the Years Ended December 31,									For the Years Ended December 31,
		2020		2019		Variance		Percent Change			2021		2020		Variance		Percent Change
CBM Gas Sales Volumes (Bcf)	CBM Gas Sales Volumes (Bcf)	52.6		55.4		(2.8)		(5.1)	%	CBM Gas Sales Volumes (Bcf)	49.5		52.6		(3.1)		(5.9)	%

Average Sales Price - Gas (per Mcf)	Average Sales Price - Gas (per Mcf)	$	2.17	$	2.96	$	(0.79)	(26.7)	%	Average Sales Price - Gas (per Mcf)	$	3.91	$	2.17	$	1.74	80.2	%
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)		$	0.76	$	0.13	$	0.63	484.6	%
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)										(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)	$	(0.93)	$	0.76	$	(1.69)	(222.4)	%

Total Average CBM Sales Price (per Mcf)	Total Average CBM Sales Price (per Mcf)	$	2.93	$	3.09	$	(0.16)	(5.2)	%	Total Average CBM Sales Price (per Mcf)	$	2.97	$	2.93	$	0.04	1.4	%
Average CBM Lease Operating Expenses (per Mcf)	Average CBM Lease Operating Expenses (per Mcf)	0.27		0.29		(0.02)		(6.9)	%	Average CBM Lease Operating Expenses (per Mcf)	0.26		0.27		(0.01)		(3.7)	%
Average CBM Production, Ad Valorem and Other Fees (per Mcf)	Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.10		0.12		(0.02)		(16.7)	%	Average CBM Production, Ad Valorem and Other Fees (per Mcf)	0.14		0.10		0.04		40.0	%
Average CBM Transportation, Gathering and Compression Costs (per Mcf)	Average CBM Transportation, Gathering and Compression Costs (per Mcf)	0.73		0.72		0.01		1.4	%	Average CBM Transportation, Gathering and Compression Costs (per Mcf)	0.80		0.73		0.07		9.6	%
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.33		1.32		0.01		0.8	%	Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)	1.18		1.33		(0.15)		(11.3)	%
Total Average CBM Costs (per Mcf)		$	2.43	$	2.45	$	(0.02)	(0.8)	%
Average Margin for CBM (per Mcf)		$	0.50	$	0.64	$	(0.14)	(21.9)	%
Total Average CBM Production Costs (per Mcf)										Total Average CBM Production Costs (per Mcf)	$	2.38	$	2.43	$	(0.05)	(2.1)	%
Total Average CBM Production Margin (per Mcf)										Total Average CBM Production Margin (per Mcf)	$	0.59	$	0.50	$	0.09	18.0	%

The CBM segment had natural gas revenue of $194 million for the year ended December 31, 2021 compared to $114 million for the year ended December 31, ~~2020 compared to $164~~2020. The $80 million ~~for the year ended December 31, 2019. The $50 million decrease~~increase was primarily due to ~~a 5.1% decrease in total CBM sales volumes and a 26.7% decrease~~an 80.2% increase in the average sales price for natural gas in the current period. The natural gas price increases were partially offset by the 5.9% decrease in CBM gas sales volumes ~~was primarily~~ due to normal production declines.

The total average CBM sales price ~~decreased $0.16~~increased $0.04 per Mcf due to a ~~$0.79~~$1.74 per Mcf ~~decrease~~increase in average gas sales price, ~~for natural gas,~~ offset in part by a ~~$0.63~~$1.69 per Mcf ~~increase~~change in the realized (loss) gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately ~~48.7~~40.4 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, ~~2020~~2021 at an average ~~gain~~loss of ~~$0.82~~$1.15 per Mcf hedged. For the year ended December 31, ~~2019,~~2020, these financial hedges represented approximately ~~40.9~~48.7 Bcf at an average gain of ~~$0.18~~$0.82 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $118 million for the year ended December 31, 2021 compared to $128 million for the year ended December 31, ~~2020 compared~~2020. The decrease in total dollars and unit costs for the CBM segment were due to ~~$136~~the following items:

•CBM lease operating expense was $13 million for the year ended December 31, ~~2019.~~2021 compared to $14 million for the year ended December 31, 2020. The ~~decrease~~decreases in total dollars was primarily due to ~~decreases in employee costs, electrical power expense and repairs and maintenance. The~~a decrease in water disposal costs.

•CBM transportation, gathering and compression costs were $40 million for the year ended December 31, 2021 compared to $39 million for the year ended December 31, 2020. The increases in total dollars and unit costs ~~was driven by the decrease~~were primarily due to an increase in ~~total dollars.~~firm transportation expense.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $58 million for the year ended December 31, 2021 compared to $70 million for the year ended December 31, ~~2020 compared to $73 million for the year ended December 31, 2019.~~2020. These amounts included depletion on a

unit of production basis of ~~$0.68~~$0.66 per Mcfe and ~~$0.70~~$0.68 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate was primarily due ~~in part,~~ to an impairment in the ~~first quarter~~2020 period that reduced the carrying value of ~~2020 related~~the underlying SWPA CBM asset group (See Note 8 - Property, Plant and Equipment in the Notes to the ~~Southwest Pennsylvania (SWPA) CBM asset group.~~Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairment occurred in the current period). The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

OTHER SEGMENT

The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, realized gain on commodity derivative instruments that were monetized prior to their contractual settlement dates, exploration and production related other costs, impairments, 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 a loss before income tax of $1,440 million for the year ended December 31, 2021 compared to a loss before income tax of $1,103 million for the year ended December 31, ~~2020 compared to a loss before income tax of $524 million for the year ended December 31, 2019.~~2020. The decrease in total dollars is discussed below.


		For the Years Ended December 31,						For the Years Ended December 31,
		2020	2019	Variance	Percent Change			2021	2020	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	Other Gas Sales Volumes (Bcf)	0.1	0.3	(0.2)	(66.7)	%	Other Gas Sales Volumes (Bcf)	0.3	0.1	0.2	200.0	%
Oil/Condensate Sales Volumes (Bcfe)*	Oil/Condensate Sales Volumes (Bcfe)*	0.1	—	0.1	100.0	%	Oil/Condensate Sales Volumes (Bcfe)*	—	0.1	(0.1)	(100.0)	%
Total Other Sales Volumes (Bcfe)*	Total Other Sales Volumes (Bcfe)*	0.2	0.3	(0.1)	(33.3)	%	Total Other Sales Volumes (Bcfe)*	0.3	0.2	0.1	50.0	%

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

~~Gain or~~ Loss on Commodity Derivative Instruments and Monetization

For the year ended December 31, 2021, the Other Segment recognized an unrealized loss on commodity derivative instruments of $1,094 million. For the year ended December 31, 2020, the Other ~~segment~~Segment recognized an unrealized loss on commodity derivative instruments of $288 million as well as cash settlements received of $84 million related to natural gas hedges ~~and financial basis hedges~~ that were partially monetized ~~or terminated~~ prior to their settlement ~~date. For the year ended December 31, 2019, the Other segment recognized an unrealized gain on commodity derivative instruments of $306 million as well as cash settlements received of $1 million.~~dates. 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. See Note 19 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the cash settlements.

Purchased Gas

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 ~~revenues were~~revenue was $100 million for the year ended December 31, 2021 compared to $106 million for the year ended December 31, ~~2020 compared to~~2020. Purchased gas costs were $94 million for the year ended December 31, ~~2019. Purchased gas costs were~~2021 compared to $101 million for the year ended December 31, ~~2020 compared to $91 million for the year ended December 31, 2019.~~2020. The period-to-period ~~increase~~decrease in purchased gas revenue was due to ~~an increase~~a decrease in purchased gas sales volumes, offset in part by ~~a decrease~~an increase in average sales price.

For the Years Ended December 31,
2020 2019 Variance Percent Change
Purchased Gas Sales Volumes (in Bcf) 66.6 40.6 26.0 64.0 %
Average Sales Price (per Mcf) $ 1.59 $ 2.32 $ (0.73) (31.5) %
Average Cost (per Mcf) $ 1.52 $ 2.23 $ (0.71) (31.8) %

5152


	For the Years Ended December 31,
	2021		2020		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	26.6		66.6		(40.0)		(60.1)	%
Purchased Gas Average Sales Price (per Mcf)	$	3.75	$	1.59	$	2.16	135.8	%
Purchased Gas Average Cost (per Mcf)	$	3.53	$	1.52	$	2.01	132.2	%

Other Operating Income


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2020		2019		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Equity Income (Loss) from Affiliates										Equity Income (Loss) from Affiliates	$	6	$	(1)	$	7	700.0	%
Water Income	Water Income	$	6	$	2	$	4	200.0	%	Water Income	7		6		1		16.7	%
Excess Firm Transportation Income	Excess Firm Transportation Income	12		10		2		20.0	%	Excess Firm Transportation Income	12		12		—		—	%
Equity in (Loss) Earnings of Affiliates		(1)		2		(3)		(150.0)	%

Total Other Operating Income	Total Other Operating Income	$	17	$	14	$	3	21.4	%	Total Other Operating Income	$	25	$	17	$	8	47.1	%

•~~Water~~Equity income ~~increased $4 million~~(loss) 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 ~~2020 period due~~facility is sold into wholesale electricity markets during times of peak energy consumption. Due to ~~increased revenue~~the plant consuming coal mine methane gas, the plant qualifies for ~~accepting deliveries of produced water from third-parties for reuse in the Company's hydraulic fracturing.~~Pennsylvania Tier I Renewable Energy Credits.

•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 ~~(gathering income)~~ from released capacity helps offset the ~~unutilized firm transportation~~Unutilized Firm Transportation and ~~processing fees~~Processing Fees in ~~total other operating expense.~~Total Other Operating Expense.

Impairment of Exploration and Production Properties

During the year ended December 31, 2020, CNX recognized certain indicators of impairments specific to our SWPA CBM asset group and determined that the carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a result, an impairment of $62 million was recognized and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of ~~Income.~~Income for the year ended December 31, 2020. The impairment was related to an economic decision to temporarily idle certain wells and the related processing facility during the first quarter.

~~During the year ended December 31, 2019, CNX identified certain indicators of impairment specific to our CPA Marcellus asset group~~ See Note 8 - Property, Plant and determined that carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a result, an impairment of $327 million was recognized within the CPA Marcellus proved properties and is included in Impairment of Exploration and Production PropertiesEquipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of ~~Income. This~~this Form 10-K for additional information. No such impairment was related to 56 operated wells and approximately 51,000 acres within our CPA Marcellus proved properties in Armstrong, Indiana, Jefferson and Westmoreland counties. The majority of these properties were developed prior to 2013 and the last of these properties were developed in 2015.

~~Impairment of Unproved Properties and Expirations~~

Capitalized costs of unproved oil and gas properties are evaluated periodically for indicators of potential impairment. Indicators of potential impairment include, but are not limited to, changes brought about by economic factors, commodity price outlooks, our geologists’ evaluation of the property, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire.

No impairments related to unproved properties were recorded for the year-ended December 31, 2020. For the year ended December 31, 2019, CNX recorded an impairment related to unproved properties of $119 million that was included in Impairment of Unproved Properties and Expirationsoccurred in the ~~Consolidated Statements of Income. These unproved properties are within CNX's CPA operating region and east of the acreage associated with the proved property impairment described above.~~current period.

Impairment of Goodwill

In connection with the Midstream Acquisition that occurred in January 2018, CNX recorded $796 million of goodwill. ~~(See Note 4 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).~~

Goodwill is tested for impairment annually during the fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount using the qualitative assessment, a quantitative impairment test is performed. From time to time, CNX may also bypass the qualitative assessment and proceed directly to the quantitative impairment test.

In connection with CNX's assessment of goodwill in the first quarter of 2020 in relation to the deteriorating macroeconomic conditions, and the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceed its estimated fair value, and as a result, an impairment of $473 million was included in Impairment of Goodwill in the Consolidated Statements of ~~Income. No such impairment occurred in~~Income for the ~~prior period.~~year ended December 31, 2020. See Note 9 - Goodwill and Other Intangible Assets in the Notes to the Audited Consolidated Financial Statements in Item 8 of this ~~Annual Report on~~ Form 10-K for additional information. No such impairment occurred in the current period.

Exploration and Production Related Other Costs


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2020		2019		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Exploratory Well Costs										Exploratory Well Costs	$	9	$	—	$	9	100.0	%
Land Rentals										Land Rentals	3		3		—		—	%
Permitting Expense										Permitting Expense	1		2		(1)		(50.0)	%

Lease Expiration Costs	Lease Expiration Costs	$	10	$	31	$	(21)	(67.7)	%	Lease Expiration Costs	8		10		(2)		(20.0)	%
Seismic Activity		1		8		(7)		(87.5)	%
Land Rentals		3		3		—		—	%

Other		1		2		(1)		(50.0)	%
Total Exploration and Production Related Other Costs	Total Exploration and Production Related Other Costs	$	15	$	44	$	(29)	(65.9)	%	Total Exploration and Production Related Other Costs	$	21	$	15	$	6	40.0	%

•Exploratory well costs relate to the write off of an exploratory well that was still being evaluated at the end of 2020. During the year ended December 31, 2021, the Company determined it would be more economical to access the underlying reserves from a different location.

•Lease ~~Expiration Costs~~expiration costs relate to leases where the primary term expired or will expire within the next 12 months. The $21 million decrease in the period-to-period comparison is due to a decrease in the number of leases that were allowed to expire in the year ended December 31, 2020, or will expire within the next 12 months, because they were no longer in the Company's future drilling plan. Additionally, approximately $15 million of the $21 million decrease is associated with leases which expired

•~~Seismic activity decreased in the period-to-period comparison due to additional geophysical research in the prior period.~~

Selling, General and Administrative ("(“SG~~&A"~~&A”)

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


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2020		2019		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	Long-Term Equity-Based Compensation (Non-Cash)	$	14	$	38	$	(24)	(63.2)	%	Long-Term Equity-Based Compensation (Non-Cash)	$	17	$	14	$	3	21.4	%
Short-Term Incentive Compensation										Short-Term Incentive Compensation	20		20		—		—	%
Salaries, Wages and Employee Benefits	Salaries, Wages and Employee Benefits	31		40		(9)		(22.5)	%	Salaries, Wages and Employee Benefits	27		31		(4)		(12.9)	%
Short-Term Incentive Compensation		20		21		(1)		(4.8)	%
Other	Other	44		45		(1)		(2.2)	%	Other	49		44		5		11.4	%
Total SG&A	Total SG&A	$	109	$	144	$	(35)	(24.3)	%	Total SG&A	$	113	$	109	$	4	3.7	%

•Long-term equity-based compensation ~~decreased $24 million~~(non-cash) increased in the period-to-period comparison due to ~~a change~~an increase in control event that occurred in the second quarter of 2019 and resulted in the acceleration of vesting of certain restricted stock units and performance share units held by certain employees. See Note 15 - Stock-Based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.equity awards.

•Salaries, wages and employee benefits decreased ~~$9 million~~in the period-to-period comparison primarily due to a decrease in employees.

•Other increased in the period-to-period comparison primarily due to an ~~overall reduction~~increase in ~~employees~~legal and ~~employee-related costs resulting from a reduction in staff.~~consulting professional services.

Other Operating Expense


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2020		2019		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	Unutilized Firm Transportation and Processing Fees	$	70	$	55	$	15	27.3	%	Unutilized Firm Transportation and Processing Fees	$	53	$	70	$	(17)	(24.3)	%
Insurance Expense		3		4		(1)		(25.0)	%
Severance Expense		—		1		(1)		(100.0)	%
Idle Equipment and Service Charges	Idle Equipment and Service Charges	10		12		(2)		(16.7)	%	Idle Equipment and Service Charges	—		10		(10)		(100.0)	%

Insurance Expense										Insurance Expense	2		3		(1)		(33.3)	%

Water Expense										Water Expense	2		1		1		100.0	%
Litigation Settlements										Litigation Settlements	10		—		10		100.0	%
Other	Other	2		8		(6)		(75.0)	%	Other	1		1		—		—	%
Total Other Operating Expense	Total Other Operating Expense	$	85	$	80	$	5	6.3	%	Total Other Operating Expense	$	68	$	85	$	(17)	(20.0)	%

•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 ~~Gathering~~Excess Firm Transportation Income in Total ~~Revenue and~~ Other Operating ~~Income above.~~Income. The ~~increase~~decrease in unutilized firm transportation and processing fees in the period-to-period comparison was primarily due to an increase in ~~previously acquired~~utilization of firm transportation capacity ~~that was not able to be utilized during~~in the current ~~period~~year due to ~~transport the Company's flowing~~ production orincreases in 2021 compared to process the Company’s wet natural gas production. One contributing factor was the strategic temporary shut-in of certain wells to take advantage of higher prices later in the year and thereby optimize the overall value of the assets. Twenty-two dry gas turn-in-lines from April and May were temporarily shut-in through September and a portion of CNX's liquids-rich Shirley-Pennsboro production was shut-in during May and June of 2020. ~~Normal production declines also contributed to the decrease in total volumes.~~

•~~Other decreased $6 million~~Idle equipment and service charges relate to temporary idling of certain of the Company’s natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process. The decrease in the period-to-period comparison ~~primarily due to a tax refund that~~ was ~~received~~the result of two of CNX’s drilling rigs being idled in the ~~2020~~prior period.

•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 this Form 10-K for additional information). The increase in the period-to-period comparison was the result of various items, none of which were individually material.

OTHER SEGMENT

The Other ~~Expense~~

For the Years Ended December 31,
(in millions) 2020 2019 Variance Percent Change
Other Income
Right-of-Way Sales $ 3 $ 9 $ (6) (66.7) %
Royalty Income — 4 (4) (100.0) %
Interest Income 2 2 — — %
Other 8 4 4 100.0 %
Total Other Income $ 13 $ 19 $ (6) (31.6) %
Other Expense
Merger Related Costs $ 11 $ — $ 11 100.0 %
Professional Services 9 4 5 125.0 %
Bank Fees 12 11 1 9.1 %
Other Land Rental Expense 4 4 — — %
Other Corporate Expense 1 3 (2) (66.7) %
Total Other Expense $ 37 $ 22 $ 15 68.2 %
Total Other Expense $ 24 $ 3 $ 21 700.0 %

•~~Right-of-way sales relate~~Segment includes nominal shallow oil and gas production which is not significant to ~~revenue generated from~~ the ~~sale of~~Company. It also includes the Company's ~~unutilized surface rights. The decrease of $6 million in the period-to-period comparison was due to a decrease in sales.~~

•Royalty income is comprised of royalties CNX received on non-operated properties unrelated to natural gas. The decrease of $4 million in the period-to-period comparison was due to a reduction in third-party prices.

•~~Other income increased $4 million in the period-to-period comparison primarily due to various items that occurred throughout both periods, none of which were individually material.~~

•Merger-related costs consist of transaction costs directly attributable to the CNXM Merger (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), including financial advisory, legal service and other professional fees, which were recorded to Other Expense in the Consolidated Statements of Income.

•~~Professional services increased $5 million in the period-to-period comparison primarily due to fees related to an agreement to eliminate CNXM's incentive distribution rights,~~purchased gas activities, unrealized gain or ~~IDRs, in January of 2020, prior to the Merger.~~

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

A gain on asset sales of $21 million related to the sale of various non-core assets, primarily surface properties, was recognized in the year ended December 31, 2020 compared to a gain of $36 million in the year ended December 31, 2019.

~~Loss on Debt Extinguishment~~

~~A gain on debt extinguishment of $10 million was recognized in the year ended December 31, 2020 compared to a~~ loss on debt extinguishment of $8 million in the year ended December 31, 2019. During the year ended December 31, 2020, CNX purchased the remaining $894 million of its 5.875% Senior Notes due April 2022 at an average price equal to 98.6% of the principal amount. During the year ended December 31, 2019 CNX purchased $400 million of its 5.875% Senior Notes due April 2022 at an average price equal to 101.5% of the principal amount. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

~~Interest Expense~~

For the Years Ended December 31,
(in millions) 2020 2019 Variance Percent Change
Total Interest Expense $ 171 $ 151 $ 20 13.2 %

•The $20 million increase was primarily due to interest related to the addition, in the current period, of $345 million of Convertible Senior Notes due 2026, the $125 million Cardinal States Facility, the $50 million CSG Holdings Facility, $500 million of senior notes due 2029, and $200 million of senior notes due 2027. The amortization of debt discount in connection with the Convertible Senior Notes and realized and unrealized losses on interest rate swap agreements during the year ended December 31, 2020 also contributed to the increase. These increases were offset in part by the purchase of the remaining $894 million of the 5.875% senior notes due in April 2022 during the year ended December 31, 2020, as well as lower borrowings on the CNX credit facility. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

~~Income Taxes~~

For the Years Ended December 31,
(in millions) 2020 2019 Variance Percent Change
Total Company (Loss) Earnings Before Income Tax $ (603) $ 60 $ (663) (1,105.0) %
Income Tax (Benefit) Expense $ (174) $ 28 $ (202) (721.4) %
Effective Income Tax Rate 28.9 % 46.5 % (17.6) %

The effective income tax rate was 28.9% for the year ended December 31, 2020, compared to 46.5% for the year ended December 31, 2019. The effective rates for the years ended December 31, 2020 and 2019 differs from the U.S. federal statutory rate of 21% primarily due to the impact of state income taxes, equity compensation and state valuation allowances, partially offset by the benefit from non-controlling interest.

~~See Note 6 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.~~

~~Results of Operations:~~ ~~Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018~~

~~Net (Loss) Income Attributable to CNX Resources Shareholders~~

CNX reported a net loss attributable to CNX Resources shareholders of $81 million, or a loss per diluted share of $0.42, for the year ended December 31, 2019, compared to net income attributable to CNX Resources shareholders of $797 million, or earnings per diluted share of $3.71, for the year ended December 31, 2018.

For the Years Ended December 31,
(Dollars in thousands) 2019 2018 Variance
Net Income $ 31,948 $ 883,111 $ (851,163)
Less: Net Income Attributable to Noncontrolling Interest 112,678 86,578 26,100
Net (Loss) Income Attributable to CNX Resources Shareholders $ (80,730) $ 796,533 $ (877,263)

Included in the loss for the year ended December 31, 2019 was a $327 million non-cash impairment charge related to exploration and production properties and a $119 million non-cash impairment charge related to unproved properties and expirations, both of which were associated with the Company's Central Pennsylvania (CPA) acreage, offset, in part, by an unrealized gain on commodity derivative instruments, of $306 million. Included in the earnings for the year ended December 31, 2018 was a $19 million non-cash impairment charge related to the other intangible asset - customer relationship in connection with the AEA with HG Energy and an unrealized gain on commodity derivative instruments of $40 million. (See Note 4 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

As a result of the Midstream Acquisition (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus the Company began consolidating CNXM on January 3, 2018. The resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $624 million was included in the Gain on Previously Held Equity Interest line of the Consolidated Statements of Income in the 2018 period and was part of CNX's unallocated expenses. No such transactions occurred during the year ended December 31, 2019. Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment.

~~Selected Operating Revenue and Other Cost Data~~

The following table presents sales volumes, revenue, costs, average sales prices (including the effects of settled derivatives) and average unit costs for production operations on a total Company basis:

For the Years Ended December 31,
2019 2018 Variance
in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe
Total Sales Volumes (Bcfe)* 539.1 507.1 32.0
Natural Gas, NGL and Oil Revenue $ 1,364 $ 2.52 $ 1,578 $ 3.12 $ (214) $ (0.60)
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement - Gas 70 0.14 (70) (0.15) 140 0.29
Total Revenue 1,434 2.66 1,508 2.97 (74) (0.31)
Lease Operating Expense 65 0.12 95 0.19 (30) (0.07)
Production, Ad Valorem and Other Fees 27 0.05 33 0.06 (6) (0.01)
Transportation, Gathering and Compression 331 0.61 303 0.60 28 0.01
Depreciation, Depletion and Amortization (DD&A) 506 0.94 493 0.97 13 (0.03)
Average Costs 929 1.72 924 1.82 5 (0.10)
Average Margin $ 505 $ 0.94 $ 584 $ 1.15 $ (79) $ (0.21)

~~The 32.0 Bcfe increase in total sales volumes was primarily due to additional natural gas wells that were turned-in-line in the latter half of the 2018 period as well as throughout the 2019 period.~~

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

•Lease operating expense decreased on a per unit basis primarily due to a decrease in water disposal costs in the period-to-period comparison due to an increase in the reuse of produced water in well completions in the 2019 period, and also due to the sale of the majority of CNX's shallow oil and gas assets and the sale of substantially all of CNX's Ohio Utica JV assets in 2018.

•Depreciation, Depletion and Amortization decreased on a per unit basis due to positive reserve revisions within the core SWPA Shale development area, partially offset by negative reserve revisions within CNX's Ohio Shale operations, as well as an increase in capital expenditures.

•Transportation, gathering and compression expense increased on a per unit basis primarily due to new firm transportation contracts which began in the fourth quarter of 2018 and the first quarter of 2019.

The following table is a summary of total other revenue and operating income and selected other expense line items that are included in the total (loss) earnings before income tax on a total company Mcfe equivalent and excluded from the previous table.

For the Years Ended December 31,
2019 2018 Variance
in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe
Total Company Sales Volumes (Bcfe)* 539.1 507.1 32.0
Total Other Revenue and Operating Income $ 88 $ 0.16 $ 116 $ 0.23 $ (28) $ (0.07)
Depreciation, Depletion and Amortization $ 2 $ 0.00 $ — $ 0.00 $ 2 $ 0.00
Exploration and Production Related Other Costs 44 0.08 12 0.02 32 0.06
Selling, General and Administrative Costs 144 0.27 135 0.27 9 0.00
Other Operating Expense 80 0.15 72 0.14 8 0.01
Total Selected Operating Costs and Expenses 270 0.50 219 0.43 51 0.07
Other Expense (Income) 3 0.01 (15) (0.03) 18 0.04
Interest Expense 151 0.28 146 0.29 5 (0.01)
Total Selected Other Expense 154 0.29 131 0.26 23 0.03
Total Selected Costs and Expenses $ 424 $ 0.79 $ 350 $ 0.69 $ 74 $ 0.10

* 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.

~~Average Realized Price Reconciliation~~

For the Years Ended December 31,
in thousands (unless noted) 2019 2018 Variance Percent Change
LIQUIDS
NGL:
Sales Volume (MMcfe) 32,571 36,489 (3,918) (10.7) %
Sales Volume (Mbbls) 5,428 6,081 (653) (10.7) %
Gross Price ($/Bbl) $ 19.20 $ 27.30 $ (8.10) (29.7) %
Gross Revenue $ 104,139 $ 165,883 $ (61,744) (37.2) %
Oil/Condensate:
Sales Volume (MMcfe) 1,223 2,389 (1,166) (48.8) %
Sales Volume (Mbbls) 204 398 (194) (48.7) %
Gross Price ($/Bbl) $ 45.00 $ 51.72 $ (6.72) (13.0) %
Gross Revenue $ 9,173 $ 20,595 $ (11,422) (55.5) %
GAS
Sales Volume (MMcf) 505,355 468,226 37,129 7.9 %
Sales Price ($/Mcf) $ 2.48 $ 2.97 $ (0.49) (16.5) %
Gross Revenue $ 1,251,013 $ 1,391,459 $ (140,446) (10.1) %
Hedging Impact ($/Mcf) $ 0.14 $ (0.15) $ 0.29 193.3 %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement $ 69,780 $ (69,720) $ 139,500 200.1 %

The decrease in gross revenue was primarily the result of the $0.49 per Mcf decrease in general natural gas prices, when excluding the impact of hedging, in the markets in which CNX sells its natural gas and the $8.10 per Bbl decrease in NGL prices. These decreases were offset, in-part, by the 32.0 Bcfe increase in sales volumes and the increase in the realized gain on commodity derivative instruments that were monetized prior to their contractual settlement dates, exploration and production related toother costs, impairments, as well as various other expenses that are managed outside the ~~Company's hedging program.~~

~~SEGMENT ANALYSIS for the year ended December 31, 2019 compared to the year ended December 31, 2018:~~

For the Year Ended Difference to Year Ended
December 31, 2019 December 31, 2018
(in millions) Shale CBM Other Total Shale CBM Other Total
Natural Gas, NGLs and Oil Revenue $ 1,199 $ 164 $ 1 $ 1,364 $ (150) $ (49) $ (15) $ (214)
Gain on Commodity Derivative Instruments 62 7 307 376 122 16 268 406
Purchased Gas Revenue — — 94 94 — — 28 28
Other Revenue and Operating Income 74 — 14 88 (16) — (12) (28)
Total Revenue and Other Operating Income 1,335 171 416 1,922 (44) (33) 269 192
Lease Operating Expense 49 16 — 65 (22) (6) (2) (30)
Production, Ad Valorem and Other Fees 21 7 (1) 27 (4) — (2) (6)
Transportation, Gathering and Compression 290 40 1 331 39 (8) (3) 28
Depreciation, Depletion and Amortization 426 73 9 508 21 (4) (2) 15
Impairment of Exploration and Production Properties — — 327 327 — — 327 327
Impairment of Unproved Properties and Expirations — — 119 119 — — 119 119
Impairment of Other Intangible Assets — — — — — — (19) (19)
Exploration and Production Related Other Costs — — 44 44 — — 32 32
Purchased Gas Costs — — 91 91 — — 26 26
Other Operating Expense — — 80 80 — — 8 8
Selling, General and Administrative Costs — — 144 144 — — 9 9
Total Operating Costs and Expenses 786 136 814 1,736 34 (18) 493 509
Other Expense — — 3 3 — — 18 18
Gain on Asset Sales and Abandonments, net — — (36) (36) — — 121 121
Gain on Previously Held Equity Interest — — — — — — 624 624
Loss on Debt Extinguishment — — 8 8 — — (46) (46)
Interest Expense — — 151 151 — — 5 5
Total Other Expenses — — 126 126 — — 722 722
Total Costs and Expenses 786 136 940 1,862 34 (18) 1,215 1,231
Earnings (Loss) Before Income Tax $ 549 $ 35 $ (524) $ 60 $ (78) $ (15) $ (946) $ (1,039)

~~SHALE SEGMENT~~

Shale and CBM segments such as SG&A, interest expense and income taxes.

The ~~Shale segment~~Other Segment had ~~earnings~~a loss before income tax of ~~$549~~$1,440 million for the year ended December 31, ~~2019~~2021 compared to ~~earnings~~a loss before income tax of ~~$627~~$1,103 million for the year ended December 31, ~~2018.~~2020. The decrease in total dollars is discussed below.

For the Years Ended December 31,
2019 2018 Variance Percent
Change
Shale Gas Sales Volumes (Bcf) 449.6 403.2 46.4 11.5 %
NGLs Sales Volumes (Bcfe)* 32.6 36.5 (3.9) (10.7) %
Oil/Condensate Sales Volumes (Bcfe)* 1.2 2.2 (1.0) (45.5) %
Total Shale Sales Volumes (Bcfe)* 483.4 441.9 41.5 9.4 %
Average Sales Price - Gas (per Mcf) $ 2.42 $ 2.89 $ (0.47) (16.3) %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.14 $ (0.15) $ 0.29 193.3 %
Average Sales Price - NGLs (per Mcfe)* $ 3.20 $ 4.55 $ (1.35) (29.7) %
Average Sales Price - Oil/Condensate (per Mcfe)* $ 7.47 $ 8.48 $ (1.01) (11.9) %
Total Average Shale Sales Price (per Mcfe) $ 2.61 $ 2.92 $ (0.31) (10.6) %
Average Shale Lease Operating Expenses (per Mcfe) 0.10 0.16 (0.06) (37.5) %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) 0.05 0.06 (0.01) (16.7) %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe) 0.60 0.57 0.03 5.3 %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) 0.88 0.91 (0.03) (3.3) %
Total Average Shale Costs (per Mcfe) $ 1.63 $ 1.70 $ (0.07) (4.1) %
Average Margin for Shale (per Mcfe) $ 0.98 $ 1.22 $ (0.24) (19.7) %


	For the Years Ended December 31,
	2021	2020	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	0.3	0.1	0.2	200.0	%
Oil/Condensate Sales Volumes (Bcfe)*	—	0.1	(0.1)	(100.0)	%
Total Other Sales Volumes (Bcfe)*	0.3	0.2	0.1	50.0	%

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

~~The Shale segment had natural gas, NGLs~~Loss on Commodity Derivative Instruments and ~~oil/condensate revenue of $1,199 million for~~Monetization

For the year ended December 31, ~~2019 compared to $1,349 million for~~2021, the Other Segment recognized an unrealized loss on commodity derivative instruments of $1,094 million. For the year ended December 31, ~~2018.~~2020, the Other Segment recognized an unrealized loss on commodity derivative instruments of $288 million as well as cash settlements received of $84 million related to natural gas hedges that were partially monetized prior to their settlement dates. The ~~$150 million decrease was due primarily to a 16.3% decrease~~unrealized loss on commodity derivative instruments represents changes in the ~~average sales price for natural gas. This decrease was offset in part by~~fair value of all the Company's existing commodity hedges on a 9.4% increase in total Shale sales volumes. The increase in total Shale sales volumes was primarily due to additional wells being turned-in-line throughout 2018 and 2019, partially offset by the sale of substantially all of CNX's Ohio JV assets in the third quarter of 2018 (Seemark-to-market basis. See Note 419 - ~~Acquisitions and Dispositions~~Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional ~~information) as well as normal production declines in~~information related to the ~~remaining dry Shale wells.~~cash settlements.

The decrease in total average Shale sales price was primarily due to a $0.47 per Mcf decrease in average gas sales price. Additionally, there was a $0.10 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging due to the sale of the previously mentioned Ohio JV assets in the third quarter of 2018, which consisted primarily of wet Shale production. The decreases were partially offset by a $0.29 per Mcf increase in the realized gain (loss) on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 348.1 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2019 at an average gain of $0.18 per Mcf hedged. For the year ended December 31, 2018, these financial hedges represented approximately 308.3 Bcf at an average loss of $0.20 per Mcf hedged.Purchased Gas

~~Total operating costs~~Purchased gas volumes represent volumes of natural gas purchased at market prices from third-parties and ~~expenses for the Shale segment were $786~~then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $100 million for the year ended December 31, ~~2019~~2021 compared to ~~$752~~$106 million for the year ended December 31, ~~2018. The increase in total dollars and decrease in unit~~2020. Purchased gas costs ~~for the Shale segment~~ were ~~due to the following items:~~

•~~Shale lease operating expenses were $49~~$94 million for the year ended December 31, ~~2019~~2021 compared to ~~$71~~$101 million for the year ended December 31, ~~2018.~~2020. The period-to-period decrease in ~~total dollars~~purchased gas revenue was ~~primarily~~ due to a decrease in ~~water disposal costs due to~~purchased gas sales volumes, offset in part by an increase in ~~reuse~~average sales price.


	For the Years Ended December 31,
	2021		2020		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	26.6		66.6		(40.0)		(60.1)	%
Purchased Gas Average Sales Price (per Mcf)	$	3.75	$	1.59	$	2.16	135.8	%
Purchased Gas Average Cost (per Mcf)	$	3.53	$	1.52	$	2.01	132.2	%

Other Operating Income


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Equity Income (Loss) from Affiliates	$	6	$	(1)	$	7	700.0	%
Water Income	7		6		1		16.7	%
Excess Firm Transportation Income	12		12		—		—	%



Total Other Operating Income	$	25	$	17	$	8	47.1	%

•Equity income (loss) from affiliates primarily represents CNX’s share of ~~produced water~~earnings from a 50% interest in ~~well completions~~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.

•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.

Impairment of Exploration and Production Properties

During the year ended December 31, 2020, CNX recognized certain indicators of impairments specific to our SWPA CBM asset group and determined that the carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a ~~reduction~~result, an impairment of $62 million was recognized and is included in ~~employee costs.~~Impairment of Exploration and Production Properties in the Consolidated Statements of Income for the year ended December 31, 2020. The ~~decrease~~impairment was related to an economic decision to temporarily idle certain wells and the related processing facility during the first quarter. See Note 8 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairment occurred in the current period.

Impairment of Goodwill

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

Goodwill is tested for impairment annually during the fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit ~~costs~~is less than its carrying value. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount using the qualitative assessment, a quantitative impairment test is performed. From time to time, CNX may also bypass the qualitative assessment and proceed directly to the quantitative impairment test.

In connection with CNX's assessment of goodwill in the first quarter of 2020 in relation to the deteriorating macroeconomic conditions, and the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceed its estimated fair value, and as a result, an impairment of $473 million was ~~driven by~~included in Impairment of Goodwill in the ~~decrease~~Consolidated Statements of Income for the year ended December 31, 2020. See Note 9 - Goodwill and Other Intangible Assets in ~~total dollars.~~the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairment occurred in the current period.

6053

Exploration and Production Related Other Costs


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Exploratory Well Costs	$	9	$	—	$	9	100.0	%
Land Rentals	3		3		—		—	%
Permitting Expense	1		2		(1)		(50.0)	%

Lease Expiration Costs	8		10		(2)		(20.0)	%

Total Exploration and Production Related Other Costs	$	21	$	15	$	6	40.0	%

•~~Shale transportation, gathering and compression~~Exploratory well costs ~~were $290 million for~~relate to the write off of an exploratory well that was still being evaluated at the end of 2020. During the year ended December 31, ~~2019 compared~~2021, the Company determined it would be more economical to ~~$251 million for~~access the ~~year ended December 31, 2018. The $39 million increase in total dollars~~underlying reserves from a different location.

•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months.

Selling, General and ~~$0.03 per Mcfe increase in unit~~Administrative (“SG&A”)

SG&A costs ~~were both due to the overall increase in Shale volumes~~include costs such as overhead, including employee labor and ~~the new firm transportation contracts which began in the fourth quarter~~benefit costs, short-term incentive compensation, costs of ~~2018~~maintaining our headquarters, audit and ~~first quarter of 2019.~~other professional fees, and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	$	17	$	14	$	3	21.4	%
Short-Term Incentive Compensation	20		20		—		—	%
Salaries, Wages and Employee Benefits	27		31		(4)		(12.9)	%
Other	49		44		5		11.4	%
Total SG&A	$	113	$	109	$	4	3.7	%

•Depreciation, depletion and amortization costs attributable to the Shale segment were $426 million for the year ended December 31, 2019 compared to $405 million for the year ended December 31, 2018. These amounts included depletion on a unit of production basis of $0.81 per Mcfe and $0.83 per Mcfe, respectively. The decreaseLong-term equity-based compensation (non-cash) increased in the ~~units of production depreciation, depletion and amortization rate was~~period-to-period comparison due to ~~positive reserve revisions within the core SWPA development area, partially offset by~~ an increase in equity awards.

•Salaries, wages and employee benefits decreased in the ~~units of production depreciation, depletion and amortization rate~~period-to-period comparison primarily due to ~~negative reserve revisions within~~a decrease in employees.

•Other increased in the ~~Ohio operations,~~period-to-period comparison primarily due to an increase in ~~capital expenditures~~legal and a higher depreciation, depletion and amortization rate on deep dry Shale wells compared to the lower capital cost wells which were part of the Ohio JV asset sale in 2018. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.consulting professional services.

~~Total Shale other revenue~~Other Operating Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	53	$	70	$	(17)	(24.3)	%
Idle Equipment and Service Charges	—		10		(10)		(100.0)	%

Insurance Expense	2		3		(1)		(33.3)	%

Water Expense	2		1		1		100.0	%
Litigation Settlements	10		—		10		100.0	%
Other	1		1		—		—	%
Total Other Operating Expense	$	68	$	85	$	(17)	(20.0)	%

•Unutilized firm transportation and ~~operating income relates~~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 ~~gathering services provided~~into a market or to ~~third-parties.~~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 ~~Shale segment had~~Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when

possible and when beneficial. The revenue ~~and operating income of $74 million for the year ended December 31, 2019 compared to $90 million for the year ended December 31, 2018.~~received when this capacity is released (sold) is included in Excess Firm Transportation Income in Total Other Operating Income. The decrease in unutilized firm transportation and processing fees in the period-to-period comparison was primarily due to ~~a reduction~~an increase in ~~third-party volumes transported~~utilization of firm transportation capacity in the current year due to ~~normal~~ production ~~declines.~~

~~COALBED METHANE (CBM) SEGMENT~~

~~The CBM segment had earnings before income tax of $35 million for the year ended December 31, 2019~~increases in 2021 compared to ~~earnings before income tax~~2020.

•Idle equipment and service charges relate to temporary idling of ~~$50 million for~~certain of the ~~year ended December 31, 2018.~~

For the Years Ended December 31,
2019 2018 Variance Percent
Change
CBM Gas Sales Volumes (Bcf) 55.4 60.3 (4.9) (8.1) %
Average Sales Price - Gas (per Mcf) $ 2.96 $ 3.53 $ (0.57) (16.1) %
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf) $ 0.13 $ (0.14) $ 0.27 192.9 %
Total Average CBM Sales Price (per Mcf) $ 3.09 $ 3.39 $ (0.30) (8.8) %
Average CBM Lease Operating Expenses (per Mcf) 0.29 0.37 (0.08) (21.6) %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) 0.12 0.12 — — %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) 0.72 0.79 (0.07) (8.9) %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.32 1.28 0.04 3.1 %
Total Average CBM Costs (per Mcf) $ 2.45 $ 2.56 $ (0.11) (4.3) %
Average Margin for CBM (per Mcf) $ 0.64 $ 0.83 $ (0.19) (22.9) %

~~The CBM segment had~~Company’s natural gas ~~revenue of $164 million for~~drilling rigs as well as related equipment and other services that may be needed in the ~~year ended December 31, 2019 compared to $213 million for the year ended December 31, 2018.~~natural gas drilling and completions process. The ~~$49 million decrease was due to an 8.1% decrease in total CBM sales volumes and the 16.1%~~ decrease in the ~~average gas sales price. The decrease~~period-to-period comparison was the result of two of CNX’s drilling rigs being idled in ~~CBM sales volumes was primarily due~~the prior period.

•CNX and its subsidiaries are subject to various lawsuits and claims in the normal ~~well declines,~~course of business. CNX accrues the estimated loss for these lawsuits and claims as ~~well as~~litigation settlements when the ~~sale of certain CBM assets that were sold along with the majority of CNX's shallow oil~~loss is probable and ~~gas assets in 2018~~can be estimated. (See Note 420 - ~~Acquisitions~~Commitments and ~~Dispositions~~Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).

The ~~total average CBM sales price decreased $0.30 per Mcf due to a $0.57 per Mcf decrease in average gas sales price, offset in part by a $0.27 per Mcf~~ increase in the ~~gain (loss) on commodity derivative instruments resulting from~~period-to-period comparison was the ~~Company's hedging program. The notional amounts associated with these financial hedges represented approximately 40.9 Bcf~~result of ~~the Company's produced CBM sales volumes for the year ended December 31, 2019 at an average gain~~various items, none of ~~$0.18 per Mcf hedged. For the year ended December 31, 2018, these financial hedges represented approximately 44.8 Bcf at an average loss of $0.20 per Mcf hedged.~~

~~Total operating costs and expenses for the CBM segment~~which were $136 million for the year ended December 31, 2019 compared to $154 million for the year ended December 31, 2018. The decrease in total dollars and decrease in unit costs for the CBM segment were due to the following items:

•CBM lease operating expense was $16 million for the year ended December 31, 2019 compared to $22 million for the year ended December 31, 2018. The $6 million decrease was primarily due to reductions in contract services, a decrease in repairs and maintenance costs, and a reduction in employee costs. The decrease in unit costs was also due to the decrease in total dollars.individually material.

•CBM transportation, gathering and compression costs were $40 million for the year ended December 31, 2019 compared to $48 million for the year ended December 31, 2018. The $8 million decrease in total dollars as well as the $0.07 per Mcf decrease in unit costs were primarily related to a decrease in electrical power expense as well as a decrease in contractor services.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $73 million for the year ended December 31, 2019 compared to $77 million for the year ended December 31, 2018. These amounts each included depletion on a unit of production basis of $0.70 per Mcfe. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

OTHER SEGMENT

The Other Segment had a loss before income tax of ~~$524~~$1,440 million for the year ended December 31, ~~2019~~2021 compared to ~~earnings~~a loss before income tax of ~~$422~~$1,103 million for the year ended December 31, ~~2018.~~2020. The decrease in total dollars is discussed below.


		For the Years Ended December 31,						For the Years Ended December 31,
		2019	2018	Variance	Percent Change			2021	2020	Variance	Percent Change
Other Gas Sales Volumes (Bcf)	Other Gas Sales Volumes (Bcf)	0.3	4.7	(4.4)	(93.6)	%	Other Gas Sales Volumes (Bcf)	0.3	0.1	0.2	200.0	%
Oil/Condensate Sales Volumes (Bcfe)*	Oil/Condensate Sales Volumes (Bcfe)*	—	0.2	(0.2)	(100.0)	%	Oil/Condensate Sales Volumes (Bcfe)*	—	0.1	(0.1)	(100.0)	%
Total Other Sales Volumes (Bcfe)*	Total Other Sales Volumes (Bcfe)*	0.3	4.9	(4.6)	(93.9)	%	Total Other Sales Volumes (Bcfe)*	0.3	0.2	0.1	50.0	%

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

Other Gas sales volumes were primarily related to shallow oil and gas production. CNX sold substantially all of these assets on March 30, 2018 (See Note 4 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). There was $1 million of natural gas and oil revenue related to the Other Gas segment for the year ended December 31, 2019 compared to $16 million for the year ended December 31, 2018. Total operating costs and expenses related to these other gas sales volumes were $6 million for the year ended December 31, 2019 compared to $18 million for the year ended December 31, 2018. The decrease in natural gas and oil revenue was due to the asset sale.

~~Gain or~~ Loss on Commodity Derivative Instruments and Monetization

~~The Other Segment recognized an unrealized gain on commodity derivative instruments of $306 million and cash settlements received of $1 million for the year ended December 31, 2019.~~ For the year ended December 31, ~~2018,~~2021, the Other Segment recognized an unrealized ~~gain~~loss on commodity derivative instruments of ~~$40~~$1,094 million. For the year ended December 31, 2020, the Other Segment recognized an unrealized loss on commodity derivative instruments of $288 million ~~and~~as well as cash settlements ~~paid~~received of ~~$1 million.~~$84 million related to natural gas hedges that were partially monetized prior to their settlement dates. 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. See Note 19 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the cash settlements.

Purchased Gas

~~the year ended December 31, 2019 compared to $65 for the year ended December 31, 2018.~~2020. The period-to-period ~~increase~~decrease in purchased gas revenue was due to ~~an increase~~a decrease in purchased gas sales volumes, offset in part by ~~a decrease~~an increase in average sales price.

For the Years Ended December 31,
2019 2018 Variance Percent Change
Purchased Gas Sales Volumes (in Bcf) 40.6 20.5 20.1 98.0 %
Average Sales Price (per Mcf) $ 2.32 $ 3.23 $ (0.91) (28.2) %
Average Cost (per Mcf) $ 2.23 $ 3.17 $ (0.94) (29.7) %


	For the Years Ended December 31,
	2021		2020		Variance		Percent Change
Purchased Gas Sales Volumes (in Bcf)	26.6		66.6		(40.0)		(60.1)	%
Purchased Gas Average Sales Price (per Mcf)	$	3.75	$	1.59	$	2.16	135.8	%
Purchased Gas Average Cost (per Mcf)	$	3.53	$	1.52	$	2.01	132.2	%

Other Operating Income


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2019		2018		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Equity Income (Loss) from Affiliates										Equity Income (Loss) from Affiliates	$	6	$	(1)	$	7	700.0	%
Water Income	Water Income	$	2	$	11	$	(9)	(81.8)	%	Water Income	7		6		1		16.7	%
Equity in Earnings of Affiliates		2		5		(3)		(60.0)	%
Excess Firm Transportation Income	Excess Firm Transportation Income	10		10		—		—	%	Excess Firm Transportation Income	12		12		—		—	%

Total Other Operating Income	Total Other Operating Income	$	14	$	26	$	(12)	(46.2)	%	Total Other Operating Income	$	25	$	17	$	8	47.1	%

•~~Water~~Equity income ~~decreased $9 million due~~(loss) 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 ~~nominal~~the plant consuming coal mine methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy Credits.

•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 ~~of freshwater~~volumes increase. In order to ~~third~~minimize this unutilized firm transportation expense, CNX is able to release (sell) unutilized firm transportation capacity to other parties ~~for hydraulic fracturing~~when possible and when beneficial. The revenue from released capacity helps offset the Unutilized Firm Transportation and Processing Fees in ~~2019 compared to 2018.~~Total Other Operating Expense.

Impairment of Exploration and Production Properties

During the ~~fourth quarter of 2019,~~year ended December 31, 2020, CNX ~~identified~~recognized certain indicators of ~~impairment~~impairments specific to our ~~CPA Marcellus~~SWPA CBM asset group and determined that the carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a result, an impairment of ~~$327~~$62 million was recognized ~~within the CPA Marcellus proved properties~~ and is included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. This impairment was related to 56 operated wells and approximately 51,000 acres within our CPA Marcellus proved properties in Armstrong, Indiana, Jefferson and Westmoreland counties. The majority of these properties were developed prior to 2013 and the last of these properties were developed in 2015.

~~Impairment of Unproved Properties and Expirations~~

~~Capitalized costs of unproved oil and gas properties are evaluated periodically~~Income for indicators of potential impairment. Indicators of potential impairment include, but are not limited to, changes brought about by economic factors, commodity price outlooks, our geologists’ evaluation of the property, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire.

~~For~~ the year ended December 31, ~~2019, CNX recorded an~~2020. The impairment was related to ~~unproved properties of $119 million that was included in Impairment of Unproved Properties~~an economic decision to temporarily idle certain wells and ~~Expirations in~~ the ~~Consolidated Statements of Income. These unproved properties are within CNX's CPA operating region~~related processing facility during the first quarter. See Note 8 - Property, Plant and ~~east of the acreage associated with the proved property impairment described above.~~

~~Impairment of Other Intangible Assets~~

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

~~In connection with the AEA with HG Energy (See Note 4 - Acquisitions and Dispositions~~Equipment in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional ~~information)~~information. No such impairment occurred in the current period.

Impairment of Goodwill

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

Goodwill is tested for impairment annually during the ~~year ended December 31, 2018,~~fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount using the qualitative assessment, a quantitative impairment test is performed. From time to time, CNX ~~determined~~may also bypass the qualitative assessment and proceed directly to the quantitative impairment test.

In connection with CNX's assessment of goodwill in the first quarter of 2020 in relation to the deteriorating macroeconomic conditions, and the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value ~~of the other intangible asset - customer relationship exceeded~~exceed its estimated fair value, and as a result, an impairment of ~~$19~~$473 million was included in Impairment of Goodwill in the Consolidated Statements of Income for the year ended December 31, 2020. See Note 9 - Goodwill and Other Intangible Assets in the Notes to the Audited Consolidated ~~Statement~~Financial Statements in Item 8 of ~~Income.~~this Form 10-K for additional information. No such ~~transactions~~impairment occurred in the ~~2019~~current period.

Exploration and Production Related Other Costs


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2019		2018		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Exploratory Well Costs										Exploratory Well Costs	$	9	$	—	$	9	100.0	%
Land Rentals										Land Rentals	3		3		—		—	%
Permitting Expense										Permitting Expense	1		2		(1)		(50.0)	%

Lease Expiration Costs	Lease Expiration Costs	$	31	$	5	$	26	520.0	%	Lease Expiration Costs	8		10		(2)		(20.0)	%
Seismic Activity		8		—		8		100.0	%
Land Rentals		3		4		(1)		(25.0)	%

Other		2		3		(1)		(33.3)	%
Total Exploration and Production Related Other Costs	Total Exploration and Production Related Other Costs	$	44	$	12	$	32	266.7	%	Total Exploration and Production Related Other Costs	$	21	$	15	$	6	40.0	%

•Lease ~~Expiration Costs~~expiration costs relate to leases where the primary term expired or will expire within the next 12 months. The $26 million increase in the period-to-period comparison is due to an increase in the number of leases that were allowed to expire in the year ended December 31, 2019, or will expire within the next 12 months, because they were no longer in the Company's future drilling plan. Additionally, approximately $15 million of the $26 million increase is associated with leases which have ceased production.

•~~Seismic activity increased in the period-to-period comparison due to additional geophysical research in the 2019 period.~~

Selling, General and Administrative (“SG&A&A”)


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2019		2018		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	Long-Term Equity-Based Compensation (Non-Cash)	$	38	$	21	$	17	81.0	%	Long-Term Equity-Based Compensation (Non-Cash)	$	17	$	14	$	3	21.4	%
Short-Term Incentive Compensation										Short-Term Incentive Compensation	20		20		—		—	%
Salaries, Wages and Employee Benefits	Salaries, Wages and Employee Benefits	40		40		—		—	%	Salaries, Wages and Employee Benefits	27		31		(4)		(12.9)	%
Short-Term Incentive Compensation		21		24		(3)		(12.5)	%
Other	Other	45		50		(5)		(10.0)	%	Other	49		44		5		11.4	%
Total SG&A	Total SG&A	$	144	$	135	$	9	6.7	%	Total SG&A	$	113	$	109	$	4	3.7	%

•Long-term equity-based compensation (non-cash) increased ~~$17 million~~ in the period-to-period comparison due to ~~the Company incurring~~ an additional $20 million of long-term equity-based compensation (non-cash) expense during the year ended December 31, 2019. The additional expense was a result of the acceleration of vesting of certain pre-2019 restricted stock units and performance share units held by certain employees related to the trigger of a contractual changeincrease in control event. See Note 15 - Stock-Based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. The remaining variance was due to various items that occurred throughout both periods, none of which were individually material.equity awards.

•~~Short-term incentive compensation~~Salaries, wages and employee benefits decreased ~~$3 million~~in the period-to-period comparison primarily due to a ~~reduction~~decrease in employees.

•Other increased in the ~~number of employees~~period-to-period comparison primarily due to an increase in legal and ~~lower projected payouts in the 2019 period.~~consulting professional services.

Other Operating Expense


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2019		2018		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	Unutilized Firm Transportation and Processing Fees	$	55	$	42	$	13	31.0	%	Unutilized Firm Transportation and Processing Fees	$	53	$	70	$	(17)	(24.3)	%
Idle Equipment and Service Charges	Idle Equipment and Service Charges	12		5		7		140.0	%	Idle Equipment and Service Charges	—		10		(10)		(100.0)	%

Insurance Expense	Insurance Expense	4		3		1		33.3	%	Insurance Expense	2		3		(1)		(33.3)	%
Severance Expense		1		1		—		—	%

Litigation Expense		—		4		(4)		(100.0)	%
Water Expense	Water Expense	—		6		(6)		(100.0)	%	Water Expense	2		1		1		100.0	%
Litigation Settlements										Litigation Settlements	10		—		10		100.0	%
Other	Other	8		11		(3)		(27.3)	%	Other	1		1		—		—	%
Total Other Operating Expense	Total Other Operating Expense	$	80	$	72	$	8	11.1	%	Total Other Operating Expense	$	68	$	85	$	(17)	(20.0)	%

•Unutilized ~~Firm Transportation~~firm transportation and ~~Processing Fees~~processing fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. ~~The increase in the period-to-period comparison was primarily due to previously-acquired capacity which was not utilized during the 2019 period to transport the Company's flowing production.~~ In some instances, the Company may have the opportunity to realize more favorable net pricing by strategically choosing to sell natural gas into a market or to a customer that does not require the use of the Company’s own firm transportation capacity. Such sales would result in an increase in unutilized firm transportation expense. The Company attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when

possible and when beneficial. The revenue received when this capacity is released (sold) is included in ~~Gathering~~Excess Firm Transportation Income in Total Other Operating ~~Income above.~~Income. The decrease in unutilized firm transportation and processing fees in the period-to-period comparison was primarily due to an increase in utilization of firm transportation capacity in the current year due to production increases in 2021 compared to 2020.

•Idle ~~Equipment~~equipment and ~~Service Charges primarily~~service charges relate to ~~the~~ temporary idling of ~~some~~certain of the ~~Company's~~Company’s natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process. The ~~increase of $7 million~~decrease in the period-to-period comparison was ~~primarily~~ the result ~~CNX terminating one~~ of ~~its~~two of CNX’s drilling ~~rig contracts early, as well as additional idle service expense related to the Shaw 1G Utica Shale well that occurred~~rigs being idled in the ~~first quarter of 2019.~~prior period.

•~~Water Expense decreased $6 million due~~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 ~~associated costs related to~~Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The increase in the ~~sales~~period-to-period comparison was the result of ~~freshwater to third-parties for hydraulic fracturing during 2018 in Total Other Operating Income above. There~~various items, none of which were ~~nominal sales during 2019.~~individually material.

Other Expense ~~(Income)~~


		For the Years Ended December 31,									For the Years Ended December 31,
(in millions)	(in millions)	2019		2018		Variance		Percent Change		(in millions)	2021		2020		Variance		Percent Change
Other Income	Other Income									Other Income
Royalty Income		$	4	$	15	$	(11)	(73.3)	%
Right of Way Sales		9		14		(5)		(35.7)	%
Interest Income	Interest Income	2		—		2		100.0	%	Interest Income	$	—	$	2	$	(2)	(100.0)	%

Right-of-Way Sales										Right-of-Way Sales	2		3		(1)		(33.3)	%
Other	Other	4		8		(4)		(50.0)	%	Other	7		8		(1)		(12.5)	%
Total Other Income	Total Other Income	$	19	$	37	$	(18)	(48.6)	%	Total Other Income	$	9	$	13	$	(4)	(30.8)	%

Other Expense	Other Expense									Other Expense
Merger-Related Costs										Merger-Related Costs	$	—	$	11	$	(11)	(100.0)	%
Professional Services										Professional Services	7		9		(2)		(22.2)	%
Bank Fees	Bank Fees	$	11	$	11	$	—	—	%	Bank Fees	12		12		—		—	%
Professional Services		4		7		(3)		(42.9)	%
Other Land Rental Expense	Other Land Rental Expense	4		4		—		—	%	Other Land Rental Expense	4		4		—		—	%
Other Corporate Expense	Other Corporate Expense	3		—		3		100.0	%	Other Corporate Expense	2		1		1		100.0	%
Total Other Expense	Total Other Expense	$	22	$	22	$	—	—	%	Total Other Expense	$	25	$	37	$	(12)	(32.4)	%

Total Other Expense (Income)		$	3	$	(15)	$	18	120.0	%
Total Other Expense										Total Other Expense	$	16	$	24	$	(8)	(33.3)	%

•

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

~~A gain on asset sales of $36 million related to non-core assets was recognized~~Interest income decreased in the ~~year ended December 31, 2019 compared to a gain of $157 million in the year ended December 31, 2018,~~period-to-period comparison primarily due to the ~~$131 million gain that was recognized~~receipt of interest in the prior year in connection with a severance tax refund related to a prior period and additional interest income related to the ~~sale of substantially all of CNX's Ohio Utica JV assets as well as the sale of various other non-core assets~~alternative minimum tax credit refund CNX received in the ~~2018 period. See~~prior year.

•Professional services decreased in the period-to-period comparison primarily due to the prior year containing fees related to the elimination of CNXM's incentive distribution rights (“IDRs”) prior to the CNXM Merger discussed below.

•Merger-related costs in the prior period consisted of transaction costs, including financial advisory, legal service and other professional fees directly attributable to the CNXM Merger (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional ~~information.~~information), which were recorded to Other Expense in the Consolidated Statements of Income.

Gain on ~~Previously Held Equity Interest~~Asset Sales and Abandonments, net

~~CNX~~A gain on asset sales of $42 million related to the sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests) was recognized in the year ended December 31, 2021 compared to a gain ~~on previously held equity interest~~ of ~~$624~~$21 million in the year ended December 31, 2018 due to the Midstream Acquisition that occurred in January 2018. No such transactions occurred in the 2019 period. See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.2020.

Loss (Gain) on Debt Extinguishment

A loss on debt extinguishment of $8$34 million was recognized in the year ended December 31, ~~2019~~2021 compared to a ~~loss~~gain on debt extinguishment of ~~$54~~$10 million in the year ended December 31, ~~2018.~~2020. During the year ended December 31, ~~2019,~~2021, CNXM purchased all of the 6.50% Senior Notes due March 2026 and CNX repaid in full and terminated the Cardinal States

Gathering Company LLC and CSG Holdings II LLC non-revolving credit facilities. During the year ended December 31, 2020, CNX purchased ~~$400~~the remaining $894 million of its 5.875% ~~senior notes~~Senior Notes due in April 2022 at an average price equal to 101.5% of the principal amount. During the year ended December 31, 2018, CNX purchased $411 million of its 5.875% senior notes due in April 2022 at an average price equal to 103.5% of the principal amount and redeemed the $500 million 8.00% senior notes due in April 2023 at a call price equal to 106.0%98.6% of the principal amount. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Interest Expense

For the Years Ended December 31,
(in millions) 2019 2018 Variance Percent Change
Total Interest Expense $ 151 $ 146 $ 5 3.4 %


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Total Interest Expense	$	151	$	171	$	(20)	(11.7)	%

•The $5$20 million ~~increase~~decrease was primarily due to ~~additional borrowings on~~ the CNX and CNXM credit facilities as well as a completed private offering of $500 million of 7.25% senior notes due March 2027 during the year ended December 31, 2019. These increases were partially offset by the reduction in higher cost long-term debt, resulting from the $500 million purchase of the ~~outstanding 8.00% senior notes due in April 2023 and the $411~~remaining $894 million ~~purchase~~ of the ~~outstanding~~ 5.875% ~~senior notes~~Senior Notes due in April 2022 during the year ended December 31, ~~2018. Additionally,~~2020 and the ~~Company purchased~~purchase of the $400 million ~~of its outstanding 5.875% senior notes~~6.500% CNXM Senior Notes due ~~in April 2022~~March 2026 during the year ended December 31, ~~2019.~~2021. Lower borrowings on the CNX Credit Facility and higher unrealized gains on interest rate swap agreements also contributed to the decrease. These decreases were offset in part by $400 million of 4.750% CNXM Senior Notes due 2030 issued in 2021, interest related to the addition in 2020 of $345 million of Convertible Notes due 2026, $500 million of 6.00% Senior Notes due 2029 issued in 2020, and an additional $200 million of 7.25% Senior Notes due 2027 issued in 2020. The amortization of debt discount in connection with the Convertible Notes also contributed to the offsetting increase. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Income Taxes


		For the Years Ended December 31,												For the Years Ended December 31,
(in millions)	(in millions)	2019			2018			Variance			Percent Change		(in millions)	2021			2020			Variance			Percent Change
Total Company Earnings Before Income Tax		$	60		$	1,099		$	(1,039)		(94.5)	%
Income Tax Expense		$	28		$	216		$	(188)		(87.0)	%
Total Company Loss Before Income Tax													Total Company Loss Before Income Tax	$	(637)		$	(603)		$	(34)		(5.6)	%
Income Tax Benefit													Income Tax Benefit	$	(138)		$	(174)		$	36		20.7	%
Effective Income Tax Rate	Effective Income Tax Rate	46.5		%	19.6		%	26.9		%			Effective Income Tax Rate	21.7		%	28.9		%	(7.2)		%

The effective income tax rate was ~~46.5%~~21.7% for the year ended December 31, ~~2019,~~2021 compared to ~~19.6%~~28.9% for the year ended December 31, ~~2018.~~2020. The effective rate for the year ended December 31, ~~2019~~2021 differs from the U.S. federal statutory rate of 21% primarily due to federal tax credits, state income taxes, equity compensation and the increase in certain state valuation allowances as a result of higher-than-expected unrealized losses on commodity derivative instruments during the current period. The unrealized losses represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis. The effective rate for the year ended December 31, 2020 differs from the U.S. federal statutory rate of 21% primarily due to state income taxes, equity compensation and state valuation allowances, partially offset by the benefit from non-controlling interest. During the year ended December 31, 2018, CNX obtained a controlling interest in CNX Gathering LLC and, through CNX Gathering's ownership of the general partner, control over CNXM. All of CNXM’s income is included in the Company's pre-tax income. However, the Company is not required to record income tax expense with respect to the portions of CNXM’s income allocated to the noncontrolling public limited partners of CNXM, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the Company's effective tax rate in periods when the Company has consolidated pre-tax loss. The effective rate for the year ended December 31, 2018 differs from the U.S. federal statutory 21% primarily due to a benefit from the filing of a Federal 10-year net operating loss (“NOL”)

carryback which resulted in the Company being able to utilize previously valued tax attributes at a tax rate differential of 14%, noncontrolling interest, the reversal of the alternative minimum tax ("AMT") credit sequestration valuation allowance, and the release of certain state valuation allowances as a result of a corporate reorganization during the year.

See Note 6 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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, including the current COVID-19 pandemic, some of which are beyond CNX’s control.

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

Company's borrowing facility capacity.

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 December 31, 2021, 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. As of December 31, 2021, cash and cash equivalents totaled $3.6 million.

•Accounts and notes receivable - trade as of December 31, 2021 and 2020 was $330.1 million and $145.9 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 $470 million to $500 million for the year ended December 31, 2022, compared to capital expenditures of $465.9 million in fiscal year 2021. In addition, accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring an increase in costs in the future.

•Production volumes are expected to range between 575.0 Bcfe and 605.0 Bcfe for the year ended December 31, 2022, compared to production volumes of 590.2 Bcfe in fiscal year 2021.

•Prices for natural gas and NGLs are volatile, and an extended decline in the prices we receive for our natural gas and NGLs will adversely affect our financial condition and cash flows.

•In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of $976 million at December 31, 2021 and a net asset of $118 million at December 31, 2020. The Company has not experienced any issues of non-performance by derivative counterparties. See Item 7A., “Quantitative and Qualitative Disclosures About Market Risk” for further discussion of our commodity risk management.

Cash Flows (in millions)


	For the Years Ended December 31,
	2021		2020		Change
Cash Provided by Operating Activities	$	926	$	795	$	131
Cash Used in Investing Activities	$	(421)	$	(439)	$	18
Cash Used in Financing Activities	$	(524)	$	(351)	$	(173)

Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:

•Net loss increased $70 million in the period-to-period comparison.

•Adjustments to reconcile net loss to cash provided by operating activities primarily consisted of a $473 million impairment of goodwill and a $62 million impairment of exploration and production properties in the prior year, an $805 million net change in commodity derivative instruments, a $20 million change in deferred income taxes, a $44 million change in gain/loss on debt extinguishment, as well as various other changes in working capital.

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

•Capital expenditures decreased $21 million in the period-to-period comparison primarily due to decreased expenditures in the Shale segment resulting from decreased drilling and completions activity as well as decreased midstream activity.

•Proceeds from asset sales decreased $3 million mainly due to decreased sales of rights-of-way, surface acreage and other non-core oil and gas interests in the year ended December 31, 2021.

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

•During the year ended December 31, 2021, CNXM paid $421 million to purchase $400 million of CNXM 6.50% Senior Notes due in March 2026 at 105.3% of the principal amount. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•During the year ended December 31, 2021, CNXM completed a private offering of $400 million aggregate principal amount of CNXM 4.75% Senior Notes due April 2030 at a price of 98.8% for cash proceeds of $395 million. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•In the year ended December 31, 2021, there were $106 million of net payments on the CNXM Credit Facility compared to $21 million of net payments during the year ended December 31, 2020.

•In the year ended December 31, 2021, there were $31 million of net proceeds on the CNX Credit Facility compared to $500 million of net payments during the year ended December 31, 2020.

•During the year ended December 31, 2021, there were $161 million of net payments on the Cardinal States Facility and CSG Holdings Facility compared to $159 million of net proceeds in the year ended December 31, 2020. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•During the years ended December 31, 2021 and 2020, CNX repurchased $245 million and $37 million, respectively, of its common stock on the open market.

•During the year ended December 30, 2020, CNX paid $882 million to purchase $894 million of Senior Notes due in 2022 at 98.6% of the principal amount. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•During the year ended December 31, 2020, CNX received proceeds of $500 million from the issuance of its 6.00% Senior Notes due January 2029.

•During the year ended December 31, 2020, CNX completed a private offering of $200 million aggregate principal amount of its 7.25% Senior Notes due March 2027 at a price of 103.5% for cash proceeds of $207 million. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•During the year ended December 31, 2020, CNX received proceeds of $335 million from the issuance of Convertible Notes due 2026. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•During the year ended December 31, 2020, CNX paid $36 million for capped call transactions related to the issuance of the Convertible Notes as mentioned above. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•During the year ended December 31, 2020 there were $42 million of payments to CNXM noncontrolling interest holders compared to no payments during the year ended December 31, 2021 due to the Merger with CNXM. See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Commitments and Significant Contractual Obligations

The following is a summary of the Company's significant contractual obligations at December 31, 2021 (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	$	777	$	642	$	—	$	—	$	1,419
Gas Firm Transportation and Processing	257,796		437,921		387,027		896,943		1,979,687
Long-Term Debt	—		—		630,716		1,600,801		2,231,517
Interest on Long-Term Debt	116,792		231,156		225,258		167,720		740,926
Finance Lease Obligations	555		883		333		2		1,773
Interest on Finance Lease Obligations	30		51		25		—		106
Operating Lease Obligations	23,460		9,395		9,116		24,591		66,562
Interest on Operating Lease Obligations	2,366		4,015		3,056		2,988		12,425
Long-Term Liabilities—Employee Related (a)	2,039		4,296		4,580		33,504		44,419
Other Long-Term Liabilities (b)	230,804		10,000		10,000		68,859		319,663
Total Contractual Obligations (c)	$	634,619	$	698,359	$	1,270,111	$	2,795,408	$	5,398,497

_________________________

(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.

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 Audited 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 December 31, 2021. Management believes these items will expire without being funded. See Note 20 - Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CNX.

Debt

At December 31, 2021, CNX had total long-term debt of $2,232 million, excluding unamortized debt issuance costs. This long-term debt consisted of:

•An aggregate principal amount of $700 million of 7.25% Senior Notes due March 2027 plus $6 million of unamortized bond premium. Interest on the notes is payable March 14 and September 14 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $500 million of 6.00% Senior Notes due January 2029. Interest on the notes is payable January 15 and July 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $400 million of 4.75% Senior Notes due April 2030 issued by CNXM, less $5 million of unamortized bond discount. Interest on the notes is payable April 15 and October 15 of each year. Payment on 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 $345 million of 2.25% Convertible Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $91 million of unamortized bond discount and issuance costs. Interest on the notes is payable May 1 and November 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $192 million in outstanding borrowings under the CNX Credit Facility. Payment of the principal and interest on the CNX Credit Facility is guaranteed by most of CNX's subsidiaries but does not include

CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $185 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 $3,700 million at December 31, 2021 compared to $4,422 million at December 31, 2020. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.

On September 28, 2020, the Merger of CNXM was completed (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). CNX accounted for the change in our ownership interest in CNXM as an equity transaction which was reflected as a reduction of noncontrolling interest with corresponding increases to common stock and capital in excess of par value.

~~Critical Accounting Policies~~Impairment of Goodwill

~~The preparation~~In connection with the Midstream Acquisition that occurred in January 2018, CNX recorded $796 million of ~~financial statements in conformity~~goodwill.

In connection with ~~accounting principles generally accepted~~CNX's assessment of goodwill in the ~~United States~~first quarter of ~~America requires management~~2020 in relation to ~~make judgments, estimates~~the deteriorating macroeconomic conditions, and ~~assumptions~~the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that ~~affect reported amounts~~utilized a combination of ~~assets~~the income and ~~liabilities, revenues~~market approaches to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceed its estimated fair value, and ~~expenses and related disclosure~~as a result, an impairment of ~~contingent assets and liabilities~~$473 million was included in Impairment of Goodwill in the Consolidated ~~Financial~~ Statements ~~and at~~of Income for the ~~date of the financial statements.~~year ended December 31, 2020. See Note ~~1-Significant Accounting Policies~~9 - Goodwill and Other Intangible Assets in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates on an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates usedadditional information. No such impairment occurred in the ~~preparation of the Consolidated Financial Statements.~~current period.

~~Asset Retirement Obligations~~

Exploration and Production Related Other Costs


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Exploratory Well Costs	$	9	$	—	$	9	100.0	%
Land Rentals	3		3		—		—	%
Permitting Expense	1		2		(1)		(50.0)	%

Lease Expiration Costs	8		10		(2)		(20.0)	%

Total Exploration and Production Related Other Costs	$	21	$	15	$	6	40.0	%

~~Accounting for Asset Retirement Obligations requires that~~•Exploratory well costs relate to the ~~fair value~~write off of an exploratory well that was still being evaluated at the end of 2020. During the year ended December 31, 2021, the Company determined it would be more economical to access the underlying reserves from a different location.

•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”)


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	$	17	$	14	$	3	21.4	%
Short-Term Incentive Compensation	20		20		—		—	%
Salaries, Wages and Employee Benefits	27		31		(4)		(12.9)	%
Other	49		44		5		11.4	%
Total SG&A	$	113	$	109	$	4	3.7	%

•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in equity awards.

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

•Other increased in the period-to-period comparison primarily due to an increase in legal and consulting professional services.

Other Operating Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	53	$	70	$	(17)	(24.3)	%
Idle Equipment and Service Charges	—		10		(10)		(100.0)	%

Insurance Expense	2		3		(1)		(33.3)	%

Water Expense	2		1		1		100.0	%
Litigation Settlements	10		—		10		100.0	%
Other	1		1		—		—	%
Total Other Operating Expense	$	68	$	85	$	(17)	(20.0)	%

possible and when beneficial. The revenue received when this capacity is released (sold) is included in Excess Firm Transportation Income in Total Other Operating Income. The decrease in unutilized firm transportation and processing fees in the period-to-period comparison was primarily due to an increase in utilization of firm transportation capacity in the current year due to production increases in 2021 compared to 2020.

•Idle equipment and service charges relate to temporary idling of certain of the Company’s natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process. The decrease in the period-to-period comparison was the result of two of CNX’s drilling rigs being idled in the prior period.

Other Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Other Income
Interest Income	$	—	$	2	$	(2)	(100.0)	%

Right-of-Way Sales	2		3		(1)		(33.3)	%
Other	7		8		(1)		(12.5)	%
Total Other Income	$	9	$	13	$	(4)	(30.8)	%

Other Expense
Merger-Related Costs	$	—	$	11	$	(11)	(100.0)	%
Professional Services	7		9		(2)		(22.2)	%
Bank Fees	12		12		—		—	%
Other Land Rental Expense	4		4		—		—	%
Other Corporate Expense	2		1		1		100.0	%
Total Other Expense	$	25	$	37	$	(12)	(32.4)	%

Total Other Expense	$	16	$	24	$	(8)	(33.3)	%

•Interest income decreased in the period-to-period comparison primarily due to the receipt of interest in the prior year in connection with a severance tax refund related to a prior period and additional interest income related to the alternative minimum tax credit refund CNX received in the prior year.

•Merger-related costs in the prior period consisted of transaction costs, including financial advisory, legal service and other professional fees directly attributable to the CNXM Merger (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), which were recorded to Other Expense in the Consolidated Statements of Income.

Gain on Asset Sales and Abandonments, net

A gain on asset ~~retirement obligation be~~sales of $42 million related to the sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests) was recognized in the ~~period in which it is incurred if~~year ended December 31, 2021 compared to a ~~reasonable estimate~~gain of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of gas wells and the reclamation of land upon exhaustion of gas reserves. Changes$21 million in the variables used to calculate the liabilities can have a significant effect on the gas well closing liability. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.year ended December 31, 2020.

Loss (Gain) on Debt Extinguishment

A loss on debt extinguishment of $34 million was recognized in the year ended December 31, 2021 compared to a gain on debt extinguishment of $10 million in the year ended December 31, 2020. During the year ended December 31, 2021, CNXM purchased all of the 6.50% Senior Notes due March 2026 and CNX repaid in full and terminated the Cardinal States

Gathering Company LLC and CSG Holdings II LLC non-revolving credit facilities. During the year ended December 31, 2020, CNX purchased the remaining $894 million of its 5.875% Senior Notes due April 2022 at an average price equal to 98.6% of the principal amount. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Interest Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Total Interest Expense	$	151	$	171	$	(20)	(11.7)	%

•The ~~Company believes that~~$20 million decrease was primarily due to the ~~accounting estimates~~purchase of the remaining $894 million of the 5.875% Senior Notes due April 2022 during the year ended December 31, 2020 and the purchase of the $400 million 6.500% CNXM Senior Notes due March 2026 during the year ended December 31, 2021. Lower borrowings on the CNX Credit Facility and higher unrealized gains on interest rate swap agreements also contributed to the decrease. These decreases were offset in part by $400 million of 4.750% CNXM Senior Notes due 2030 issued in 2021, interest related to ~~asset retirement obligations are “critical accounting estimates” because~~ the ~~Company must assess~~addition in 2020 of $345 million of Convertible Notes due 2026, $500 million of 6.00% Senior Notes due 2029 issued in 2020, and an additional $200 million of 7.25% Senior Notes due 2027 issued in 2020. The amortization of debt discount in connection with the ~~expected amount and timing of asset retirement obligations. In addition,~~Convertible Notes also contributed to the ~~Company must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes~~offsetting increase. See Note 12 - Long-Term Debt in the ~~Company’s assumptions.~~Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Income Taxes


	For the Years Ended December 31,
(in millions)	2021			2020			Variance			Percent Change
Total Company Loss Before Income Tax	$	(637)		$	(603)		$	(34)		(5.6)	%
Income Tax Benefit	$	(138)		$	(174)		$	36		20.7	%
Effective Income Tax Rate	21.7		%	28.9		%	(7.2)		%

~~Deferred~~The effective income tax ~~assets and liabilities are recognized using enacted tax rates~~rate was 21.7% for the ~~estimated future~~year ended December 31, 2021 compared to 28.9% for the year ended December 31, 2020. The effective rate for the year ended December 31, 2021 differs from the U.S. federal statutory rate of 21% primarily due to federal tax ~~effects~~credits, state income taxes, equity compensation and the increase in certain state valuation allowances as a result of ~~temporary differences between~~higher-than-expected unrealized losses on commodity derivative instruments during the ~~book and tax basis~~current period. The unrealized losses represents changes in the fair value of ~~recorded assets and liabilities. Deferred tax assets are reduced by~~all the Company's existing commodity hedges on a ~~valuation allowance if it is more likely than not that some portion of~~mark-to-market basis. The effective rate for the ~~deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At~~year ended December 31, 2020 ~~CNX had deferred tax liabilities in excess~~differs from the U.S. federal statutory rate of ~~deferred tax assets of approximately $343 million. At December 31, 2020, CNX had a~~21% primarily due to state income taxes, equity compensation and state valuation ~~allowance of $123 million on deferred tax assets.~~allowances, partially offset by the benefit from non-controlling interest.

CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation of the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. See Note 6 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional ~~information regarding the Company’s uncertain tax liabilities.~~information.

~~The Company~~

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 ~~accounting estimates related to income taxes are “critical accounting estimates” because~~cash generated from operations, asset sales and the ~~Company must assess the likelihood that deferred tax assets~~Company's borrowing capacity will be ~~recovered from~~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 ~~taxable income~~operating performance, which will be affected by prevailing economic conditions in the natural gas industry and ~~exercise~~other financial and business factors, including the current COVID-19 pandemic, some of which are beyond CNX’s control.

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judgment regarding the amount of financial statement benefit to record for uncertain tax positions. When evaluating whether or not a valuation allowance must be established on deferred tax assets, the Company exercises judgment in determining whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed, including carrybacks, tax planning strategies and reversal of deferred tax assets and liabilities. In making the determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.Company's borrowing facility capacity.

~~Natural Gas, NGL, Condensate~~CNX continuously reviews its liquidity and ~~Oil Reserve ("Natural Gas Reserve") Values~~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.

~~Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities~~As of ~~oil and natural gas which, by analysis~~December 31, 2021, CNX was in compliance with all of ~~geoscience and engineering data, can be estimated~~its debt covenants. After considering the potential effect of a significant decline in commodity prices, CNX currently expects to remain in compliance 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.its debt covenants.

~~There are numerous uncertainties inherent in estimating quantities~~CNX frequently evaluates potential acquisitions. CNX has historically funded acquisitions with cash generated from operations and ~~values~~a variety of economically recoverable natural gas reserves, including many factors beyond our control. As a result, estimates of economically recoverable natural gas reserves are by their nature uncertain. Information about our reserves consists of estimates basedother sources, depending on ~~engineering, economic and geological data assembled and analyzed by our staff. Our natural gas reserves are reviewed by independent experts each year. Some~~the size of the ~~factors~~transaction, including debt and ~~assumptions~~equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CNX on terms which ~~impact economically recoverable reserve estimates include:~~CNX finds acceptable, or at all.

Factors that may Impact our Liquidity

•~~geological conditions;~~The Company’s cash on hand and access to additional liquidity. As of December 31, 2021, cash and cash equivalents totaled $3.6 million.

•~~historical production from~~Accounts and notes receivable - trade as of December 31, 2021 and 2020 was $330.1 million and $145.9 million, respectively. Our accounts and notes receivable balance may fluctuate as of any balance sheet date depending on the ~~area compared with production from other producing areas;~~prices we receive for our natural gas and NGLs and the volumes sold.

•~~the assumed effects of regulations and taxes by governmental agencies;~~

•~~assumptions governing future prices; and~~

•~~future operating costs.~~

~~Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of gas attributable~~Capital expenditures are expected to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respectrange between $470 million to ~~our reserves will likely vary from estimates, and these variances may be material. See "Risk Factors" in Item 1A of this Form 10-K~~$500 million for ~~a discussion of the uncertainties in estimating our reserves.~~

The Company believes that the accounting estimate related to oil and gas reserves is a “critical accounting estimate” because the Company must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the estimated timing of development expenditures. Future results of operations and strength of the balance sheet for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. See "~~Impairment of Long-lived Assets" below for additional information regarding the Company’s oil and gas reserves.~~

~~Impairment of Long-lived Assets~~

The carrying values of the Company's proved oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Impairment tests require that the Company first compare future undiscounted cash flows by asset group to their respective carrying values. The Company groups its assets by geological and geographical characteristics. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital. For the year ended December 31, ~~2020,~~2022, compared to capital expenditures of $465.9 million in fiscal year 2021. In addition, accelerated levels of inflation may lead to price increases beyond CNX’s control that could lead to CNX incurring an ~~impairment of $62 million was included~~increase in ~~Impairment of Exploration and Production Properties~~costs in the ~~Consolidated Statements of Income. This impairment was related~~future.

•Production volumes are expected to ~~our Southwest Pennsylvania (SWPA) coalbed methane (CBM) asset group. For~~range between 575.0 Bcfe and 605.0 Bcfe for the year ended December 31, ~~2019,~~2022, compared to production volumes of 590.2 Bcfe in fiscal year 2021.

•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.

Cash Flows (in millions)


	For the Years Ended December 31,
	2021		2020		Change
Cash Provided by Operating Activities	$	926	$	795	$	131
Cash Used in Investing Activities	$	(421)	$	(439)	$	18
Cash Used in Financing Activities	$	(524)	$	(351)	$	(173)

Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:

•Net loss increased $70 million in the period-to-period comparison.

•Adjustments to reconcile net loss to cash provided by operating activities primarily consisted of a $473 million impairment of ~~$327~~goodwill and a $62 million ~~was included in Impairment~~impairment of ~~Exploration~~exploration and ~~Production Properties~~production properties in the ~~Consolidated Statements~~prior year, an $805 million net change in commodity derivative instruments, a $20 million change in deferred income taxes, a $44 million change in gain/loss on debt extinguishment, as well as various other changes in working capital.

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

•Proceeds from asset sales decreased $3 million mainly due to decreased sales of ~~Income. This impairment was related~~rights-of-way, surface acreage and other non-core oil and gas interests in the year ended December 31, 2021.

Cash used in financing activities changed in the period-to-period comparison primarily due to ~~56 operated wells and approximately 51,000 acres within our CPA Marcellus proved properties~~the following items:

•During the year ended December 31, 2021, CNXM paid $421 million to purchase $400 million of CNXM 6.50% Senior Notes due in ~~Armstrong, Indiana, Jefferson and Westmoreland counties.~~March 2026 at 105.3% of the principal amount. See Note 112 - ~~Significant Accounting Policies~~Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for ~~more~~additional information.

•In the year ended December 31, 2021, there were $106 million of net payments on the CNXM Credit Facility compared to $21 million of net payments during the year ended December 31, 2020.

•In the year ended December 31, 2021, there were $31 million of net proceeds on the CNX Credit Facility compared to $500 million of net payments during the year ended December 31, 2020.

•During the years ended December 31, 2021 and 2020, CNX repurchased $245 million and $37 million, respectively, of its common stock on the open market.

•During the year ended December 31, 2020, CNX received proceeds of $500 million from the issuance of its 6.00% Senior Notes due January 2029.

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Commitments and Significant Contractual Obligations

The following is a summary of the Company's significant contractual obligations at December 31, 2021 (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	$	777	$	642	$	—	$	—	$	1,419
Gas Firm Transportation and Processing	257,796		437,921		387,027		896,943		1,979,687
Long-Term Debt	—		—		630,716		1,600,801		2,231,517
Interest on Long-Term Debt	116,792		231,156		225,258		167,720		740,926
Finance Lease Obligations	555		883		333		2		1,773
Interest on Finance Lease Obligations	30		51		25		—		106
Operating Lease Obligations	23,460		9,395		9,116		24,591		66,562
Interest on Operating Lease Obligations	2,366		4,015		3,056		2,988		12,425
Long-Term Liabilities—Employee Related (a)	2,039		4,296		4,580		33,504		44,419
Other Long-Term Liabilities (b)	230,804		10,000		10,000		68,859		319,663
Total Contractual Obligations (c)	$	634,619	$	698,359	$	1,270,111	$	2,795,408	$	5,398,497

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(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.

Off-Balance Sheet Transactions

Debt

At December 31, 2021, CNX had total long-term debt of $2,232 million, excluding unamortized debt issuance costs. This long-term debt consisted of:

~~There were no other impairments related to proved properties~~CNXM (or its subsidiaries or general partner).

•An aggregate principal amount of $185 million in outstanding borrowings under the ~~years ended December 31, 2020, 2019 or 2018.~~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 ~~evaluates capitalized costs~~had total equity of ~~unproved gas properties~~$3,700 million at December 31, 2021 compared to $4,422 million at December 31, 2020. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for ~~recoverability~~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 ~~a prospective basis. Indicators~~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 ~~potential impairment include, but are not limited~~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 ~~changes brought about by economic factors, commodity price outlooks, our geologists’ evaluation~~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 ~~property, favorable or unfavorable activity on~~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 ~~property being evaluated and/or adjacent properties, potential shifts~~7.25% Senior Notes due March 2027 and the 6.00% Senior Notes due January 2029 limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. For the year ended December 31, 2019, an impairment of $119 million was included in Impairment of Unproved Properties and Expirations in the Consolidated Statements of Income. There were no other impairments related to unproved properties in the years ended December 31, 2020, 2019 or 2018.2021.

The Company believes that the accounting estimates related to the impairment of long-lived assets are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. In addition, the Company must determine the estimated undiscounted future cash flows as well as the impact of commodity price outlooks. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates, such as different assumptions in projected revenues, future commodity prices or the weighted average costs of capital, could materially impact the calculated fair value and the resulting determinations about the impairment of long-lived assets which could materially impact the Company’s results of operations and financial position. Additionally, future estimates may differ materially from current estimates and assumptions.

Impairment of Goodwill

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

In connection with CNX's assessment of goodwill in the first quarter of 2020 in relation to the deteriorating macroeconomic conditions, and the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceed its estimated fair value, and as a result, an impairment of $473 million was included in Impairment of Goodwill in the Consolidated Statements of Income for the year ended December 31, 2020. See Note 9 - Goodwill and Other Intangible Assets in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairment occurred in the current period.

Exploration and Production Related Other Costs


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Exploratory Well Costs	$	9	$	—	$	9	100.0	%
Land Rentals	3		3		—		—	%
Permitting Expense	1		2		(1)		(50.0)	%

Lease Expiration Costs	8		10		(2)		(20.0)	%

Total Exploration and Production Related Other Costs	$	21	$	15	$	6	40.0	%

•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”)


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Long-Term Equity-Based Compensation (Non-Cash)	$	17	$	14	$	3	21.4	%
Short-Term Incentive Compensation	20		20		—		—	%
Salaries, Wages and Employee Benefits	27		31		(4)		(12.9)	%
Other	49		44		5		11.4	%
Total SG&A	$	113	$	109	$	4	3.7	%

•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in equity awards.

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

•Other increased in the period-to-period comparison primarily due to an increase in legal and consulting professional services.

Other Operating Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Unutilized Firm Transportation and Processing Fees	$	53	$	70	$	(17)	(24.3)	%
Idle Equipment and Service Charges	—		10		(10)		(100.0)	%

Insurance Expense	2		3		(1)		(33.3)	%

Water Expense	2		1		1		100.0	%
Litigation Settlements	10		—		10		100.0	%
Other	1		1		—		—	%
Total Other Operating Expense	$	68	$	85	$	(17)	(20.0)	%

Other Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Other Income
Interest Income	$	—	$	2	$	(2)	(100.0)	%

Right-of-Way Sales	2		3		(1)		(33.3)	%
Other	7		8		(1)		(12.5)	%
Total Other Income	$	9	$	13	$	(4)	(30.8)	%

Other Expense
Merger-Related Costs	$	—	$	11	$	(11)	(100.0)	%
Professional Services	7		9		(2)		(22.2)	%
Bank Fees	12		12		—		—	%
Other Land Rental Expense	4		4		—		—	%
Other Corporate Expense	2		1		1		100.0	%
Total Other Expense	$	25	$	37	$	(12)	(32.4)	%

Total Other Expense	$	16	$	24	$	(8)	(33.3)	%

•Merger-related costs in the prior period consisted of transaction costs, including financial advisory, legal service and other professional fees directly attributable to the CNXM Merger (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information), which were recorded to Other Expense in the Consolidated Statements of Income.

Gain on Asset Sales and Abandonments, net

A gain on asset sales of $42 million related to the sale of various non-core assets (primarily rights-of-way, surface acreage and other non-core oil and gas interests) was recognized in the year ended December 31, 2021 compared to a gain of $21 million in the year ended December 31, 2020.

Loss (Gain) on Debt Extinguishment

Interest Expense


	For the Years Ended December 31,
(in millions)	2021		2020		Variance		Percent Change
Total Interest Expense	$	151	$	171	$	(20)	(11.7)	%

•The $20 million decrease was primarily due to the purchase of the remaining $894 million of the 5.875% Senior Notes due April 2022 during the year ended December 31, 2020 and the purchase of the $400 million 6.500% CNXM Senior Notes due March 2026 during the year ended December 31, 2021. Lower borrowings on the CNX Credit Facility and higher unrealized gains on interest rate swap agreements also contributed to the decrease. These decreases were offset in part by $400 million of 4.750% CNXM Senior Notes due 2030 issued in 2021, interest related to the addition in 2020 of $345 million of Convertible Notes due 2026, $500 million of 6.00% Senior Notes due 2029 issued in 2020, and an additional $200 million of 7.25% Senior Notes due 2027 issued in 2020. The amortization of debt discount in connection with the Convertible Notes also contributed to the offsetting increase. See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Income Taxes


	For the Years Ended December 31,
(in millions)	2021			2020			Variance			Percent Change
Total Company Loss Before Income Tax	$	(637)		$	(603)		$	(34)		(5.6)	%
Income Tax Benefit	$	(138)		$	(174)		$	36		20.7	%
Effective Income Tax Rate	21.7		%	28.9		%	(7.2)		%

The effective income tax rate was 21.7% for the year ended December 31, 2021 compared to 28.9% for the year ended December 31, 2020. The effective rate for the year ended December 31, 2021 differs from the U.S. federal statutory rate of 21% primarily due to federal tax credits, state income taxes, equity compensation and the increase in certain state valuation allowances as a result of higher-than-expected unrealized losses on commodity derivative instruments during the current period. The unrealized losses represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis. The effective rate for the year ended December 31, 2020 differs from the U.S. federal statutory rate of 21% primarily due to state income taxes, equity compensation and state valuation allowances, partially offset by the benefit from non-controlling interest.

See Note 6 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Liquidity and Capital Resources

Overview, Sources and Uses

Company's borrowing facility capacity.

Factors that may Impact our Liquidity

•The Company’s cash on hand and access to additional liquidity. As of December 31, 2021, cash and cash equivalents totaled $3.6 million.

•Production volumes are expected to range between 575.0 Bcfe and 605.0 Bcfe for the year ended December 31, 2022, compared to production volumes of 590.2 Bcfe in fiscal year 2021.

•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.

Cash Flows (in millions)


	For the Years Ended December 31,
	2021		2020		Change
Cash Provided by Operating Activities	$	926	$	795	$	131
Cash Used in Investing Activities	$	(421)	$	(439)	$	18
Cash Used in Financing Activities	$	(524)	$	(351)	$	(173)