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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
OR

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

For the transition period from to
Commission file number: 001-14901
__________________________________________________
CNX Resources Corporation
(Exact name of registrant as specified in its charter)

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

CNX Center
1000 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, 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.
The number of shares outstanding of the registrant's common stock as of January 20, 2021 is 219,707,417 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 | 40
ITEM 2. | Properties | 40
ITEM 3. | Legal Proceedings | 41
ITEM 4. | Mine Safety Disclosures | 41
PART II |
ITEM 5. | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 41
ITEM 6. | Selected Financial Data | 43
ITEM 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations | 44
ITEM 7A. | Quantitative and Qualitative Disclosures About Market Risk | 76
ITEM 8. | Financial Statements and Supplementary Data | 78
ITEM 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosures | 134
ITEM 9A. | Controls and Procedures | 134
ITEM 9B. | Other Information | 136
PART III |
ITEM 10. | Directors, Executive Officers and Corporate Governance | 136
ITEM 11. | Executive Compensation | 137
ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 137
ITEM 13. | Certain Relationships and Related Transactions and Director Independence | 137
ITEM 14. | Principal Accountant Fees and Services | 137
PART IV |
ITEM 15. | Exhibits and Financial Statement Schedules | 138
ITEM 16. | Form 10-K Summary | 143
SIGNATURES | 143

2

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 - 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 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.
3

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 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 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.
4

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 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;
•events beyond our control, including a global or domestic health crisis;
•dependence on gathering, processing and transportation facilities and other midstream facilities owned by others, and disruption of, capacity constraints in, or proximity to pipeline, 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 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;
5

•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 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;
•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;
•acquisitions and divestitures, we anticipate may not occur or produce anticipated benefits;
•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 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file with the Securities and Exchange Commission.
6

PART I
ITEM 1.Business
General
CNX Resources Corporation (“CNX”, the “Company,” or “we,” “us,” or “our”) is an independent oil and natural gas 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”) 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 base, coupled with these core values, allows management to create long-term per share value. CNX believes that natural gas is central to a low-cost, reliable, secure, lower-carbon energy future. Widespread 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.
2020 Operational Highlights and Outlook
•Over the past ten years, CNX's natural gas production has grown by approximately 300% to a total of 511.1 net Bcfe in 2020.
•Total average production of 1,396,371 Mcfe per day;
•94% Natural Gas, 6% Liquids; and
•90% Shale, 10% coalbed methane.
At December 31, 2020, our proved natural gas, NGL, condensate and oil reserves (collectively, "natural gas reserves") had the following characteristics:
•9.5 Tcfe of proved reserves;
•94.6% natural gas;
•54.4% proved developed;
•98.7% operated; and
•A reserve life ratio of 18.69 years (based on 2020 production).
In 2021, CNX expects capital expenditures of approximately $430 million to $470 million. The Company continuously evaluates multiple factors to determine activity throughout the year, and as such, may update guidance accordingly.
7

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 net Marcellus Shale acres and approximately 610,000 net Utica Shale acres at December 31, 2020. Approximately 349,000 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 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 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 net acres at December 31, 2020. 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

|  | Shale |  | CBM |  | Other Gas |  |
|  | Segment |  | Segment |  | Segment |  | Total
Estimated Net Proved Reserves (MMcfe) |  | 8,443,926 |  |  | 1,099,627 |  |  | 6,205 |  |  | 9,549,758 |
Percent Developed (1) |  | 52 | % |  | 71 | % |  | 100 | % |  | 54 | %
Net Producing Wells (including oil and gob wells) |  | 491 |  |  | 3,852 |  |  | 57 |  |  | 4,400 |
Net Acreage Position: |  |  |  |  |  |  |  |
Net Proved Developed Acres |  | 77,369 |  |  | 235,388 |  |  | 38,780 |  |  | 351,537 |
Net Proved Undeveloped Acres |  | 43,713 |  |  | — |  |  | — |  |  | 43,713 |
Net Unproved Acres(2) |  | 716,581 |  |  | 1,943,671 |  |  | 977,730 |  |  | 3,637,982 |
Total Net Acres(3) |  | 837,663 |  |  | 2,179,059 |  |  | 1,016,510 |  |  | 4,033,232 |

_________
(1) Percent developed is calculated as net proved developed reserves divided by net proved reserves, measured in MMcfe.
(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.
(3) Acreage amounts are only included under the target strata CNX expects to produce with the exception of certain CBM acres governed by separate leases.
8

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, the number of producing wells, developed acreage and undeveloped acreage:

|  | Gross(1) |  | Net(2)
Producing Gas Wells (including gob wells) - Working Interest |  | 4,712 |  |  | 4,401 |
Producing Oil Wells - Working Interest |  | — |  |  | — |
Producing Gas Wells - Royalty Interest |  | 1,810 |  |  | — |
Producing Oil Wells - Royalty Interest |  | 152 |  |  | — |
Net Acreage Position: |  |  |  |
Proved Developed Acreage |  | 351,537 |  |  | 351,537 |
Proved Undeveloped Acreage |  | 43,713 |  |  | 43,713 |
Unproved Acreage |  | 4,986,196 |  |  | 3,637,982 |
Total Acreage |  | 5,381,446 |  |  | 4,033,232 |

_________
(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
Held by Production/Fee |  | 4,889,527 |  |  | 3,578,943 |  |  | 30,594 |  |  | 30,594 |
Expiration Within 2 Years |  | 55,298 |  |  | 30,429 |  |  | 4,732 |  |  | 4,732 |
Expiration Beyond 2 Years |  | 41,370 |  |  | 28,610 |  |  | 8,387 |  |  | 8,387 |
Total Acreage |  | 4,986,195 |  |  | 3,637,982 |  |  | 43,713 |  |  | 43,713 |

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, 2020, 2019 and 2018, we drilled 29.0, 75.7 and 83.9 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, there were 17.0 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 or 2018 and 1.0 net dry development well in 2019. As of December 31, 2020, there are 24.0 gross completed developmental wells ready to be turned in-line.
9

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

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

Exploratory Wells (Net)
There were 2.0 and 5.0 net exploratory wells drilled during the years ended December 31, 2020 and 2019, respectively. There were 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,
|  | 2020 |  | 2019 |  | 2018
|  | Producing |  | Dry |  | Still Eval*. |  | Producing |  | Dry |  | Still Eval. |  | Producing |  | Dry |  | Still Eval.
Shale Segment |  | — |  |  | — |  |  | 2.0 |  |  | 4.0 |  |  | — |  |  | 1.0 |  |  | — |  |  | — |  |  | — |
CBM Segment |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other Gas Segment |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Total Exploratory Wells (Net) |  | — |  |  | — |  |  | 2.0 |  |  | 4.0 |  |  | — |  |  | 1.0 |  |  | — |  |  | — |  |  | — |

_________
* Still evaluating in 2020 includes 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 evaluating the partially constructed 2019 well to determine the most economic approach to access the natural gas reserves. The company expects to make a determination in 2021 to either finalize the well or to access the natural gas reserves from an alternative location.
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,
|  | 2020 |  | 2019 |  | 2018
Proved Developed Reserves |  | 5,199,748 |  |  | 4,838,858 |  |  | 4,494,878 |
Proved Undeveloped Reserves |  | 4,350,010 |  |  | 3,586,809 |  |  | 3,386,457 |
Total Proved Developed and Undeveloped Reserves (1) |  | 9,549,758 |  |  | 8,425,667 |  |  | 7,881,335 |

___________
(1) For additional information on our reserves, see Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.
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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,
|  | 2020 |  | 2019 |  | 2018
|  | (Dollars in millions)
Future Net Cash Flows |  | $ | 6,313 |  |  | $ | 7,744 |  |  | $ | 13,132 |
Total PV-10 Measure of Pre-Tax Discounted Future Net Cash Flows (1) |  | $ | 3,603 |  |  | $ | 4,176 |  |  | $ | 6,172 |
Total Standardized Measure of After-Tax Discounted Future Net Cash Flows |  | $ | 2,636 |  |  | $ | 3,070 |  |  | $ | 4,655 |

____________
(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,
|  | 2020 |  | 2019 |  | 2018
|  | (Dollars in millions)
NYMEX Natural Gas Prices (MMbtu) |  | $ | 1.985 |  |  | $ | 2.578 |  |  | $ | 3.100 |
Future Cash Inflows |  | $ | 16,578 |  |  | $ | 19,490 |  |  | $ | 26,610 |
Future Production Costs |  | (6,072) |  |  | (7,903) |  |  | (7,730) |
Future Development Costs (including Abandonments)* |  | (1,958) |  |  | (1,121) |  |  | (1,600) |
Future Net Cash Flows (pre-tax) |  | 8,548 |  |  | 10,466 |  |  | 17,280 |
10% Discount Factor |  | (4,945) |  |  | (6,290) |  |  | (11,108) |
PV-10 (Non-GAAP Measure) |  | 3,603 |  |  | 4,176 |  |  | 6,172 |
Undiscounted Income Taxes |  | (2,235) |  |  | (2,721) |  |  | (4,147) |
10% Discount Factor |  | 1,268 |  |  | 1,615 |  |  | 2,630 |
Discounted Income Taxes |  | (967) |  |  | (1,106) |  |  | (1,517) |
Standardized GAAP Measure |  | $ | 2,636 |  |  | $ | 3,070 |  |  | $ | 4,655 |

*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 addition of Midstream capital is the 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).
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Gas Production
The following table sets forth net sales volumes produced for the periods indicated:

|  | For the Year
|  | Ended December 31,
|  | 2020 |  | 2019 |  | 2018
Natural Gas |  |  |  |  |  |
Sales Volume (MMcf) |  |  |  |  |  |
Shale |  | 428,679 |  |  | 449,669 |  |  | 403,244 |
CBM |  | 52,609 |  |  | 55,445 |  |  | 60,268 |
Other |  | 138 |  |  | 241 |  |  | 4,714 |
Total |  | 481,426 |  |  | 505,355 |  |  | 468,226 |
NGL |  |  |  |  |  |
Sales Volume (Mbbls) |  |  |  |  |  |
Shale |  | 4,675 |  |  | 5,428 |  |  | 6,080 |
Other |  | 2 |  |  | — |  |  | 1 |
Total |  | 4,677 |  |  | 5,428 |  |  | 6,081 |
Oil and Condensate |  |  |  |  |  |
Sales Volume (Mbbls) |  |  |  |  |  |
Shale |  | 250 |  |  | 195 |  |  | 364 |
Other |  | 14 |  |  | 8 |  |  | 35 |
Total |  | 264 |  |  | 203 |  |  | 399 |
Total Sales Volume (MMcfe) |  |  |  |  |  |
Shale |  | 458,231 |  |  | 483,413 |  |  | 441,907 |
CBM |  | 52,609 |  |  | 55,445 |  |  | 60,268 |
Other |  | 232 |  |  | 291 |  |  | 4,929 |
Total |  | 511,072 |  |  | 539,149 |  |  | 507,104 |

*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 of production related to assets that were sold during that year. For additional information, see Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K, which is incorporated herein by reference.
CNX expects 2021 annual natural gas production volumes to be approximately 540-570 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 Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K for a breakdown by segment.
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|  | For the Year
|  | Ended December 31,
|  | 2020 |  | 2019 |  | 2018
Average Sales Price - Gas (Mcf) |  | $ | 1.71 |  |  | $ | 2.48 |  |  | $ | 2.97 |
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)* |  | $ | 0.78 |  |  | $ | 0.14 |  |  | $ | (0.15) |
Average Sales Price - NGLs (Mcfe)** |  | $ | 2.29 |  |  | $ | 3.20 |  |  | $ | 4.55 |
Average Sales Price - Oil (Mcfe)** |  | $ | 6.55 |  |  | $ | 8.13 |  |  | $ | 9.89 |
Average Sales Price - Condensate (Mcfe)** |  | $ | 5.85 |  |  | $ | 7.47 |  |  | $ | 8.43 |
Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments* |  | $ | 2.49 |  |  | $ | 2.66 |  |  | $ | 2.97 |
Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments |  | $ | 1.75 |  |  | $ | 2.53 |  |  | $ | 3.11 |
Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe) |  | $ | 0.08 |  |  | $ | 0.12 |  |  | $ | 0.19 |
Average Sales Price - NGLs (Bbl) |  | $ | 13.74 |  |  | $ | 19.20 |  |  | $ | 27.30 |
Average Sales Price - Oil (Bbl) |  | $ | 39.30 |  |  | $ | 48.78 |  |  | $ | 59.34 |
Average Sales Price - Condensate (Bbl) |  | $ | 35.10 |  |  | $ | 44.82 |  |  | $ | 50.58 |

*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 $0.04 per Mcfe, $0.05 per Mcfe, 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 461.1 Bcf of our produced 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, 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 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, approximately 263.1 Bcf of our estimated 2024 production at an average price of $2.28 per Mcf, and approximately 103.0 Bcf of our estimated 2025 production at an average price of $2.10 per Mcf.
CNX's hedging strategy and information regarding derivative instruments used are outlined in Part II. Item 7A. "Qualitative and Quantitative Disclosures About Market 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
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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.
Marketing
Substantially all of our natural gas is sold at market prices primarily under short-term sales contracts and is subject to seasonal price swings. The principal markets for our natural gas are in the Appalachian Basin where we sell natural gas to 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, 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.
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Water Division
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.
Human Capital Management
At December 31, 2020, CNX had 451 employees, none of whom are subject to a collective bargaining agreement. CNX recognizes that our future success depends on the services of our key employees. CNX, is emphatic about the health and safety of not only our employees and service providers, but also the communities in which we operate.
Training and Education. CNX has a variety of programs 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 management, employees and the service provider workforce to continually focus attention and actions on daily safety behavior. This is accomplished through an evergreen approach with constant evaluation and adaptation for employee, safety and business needs. Fundamentally, the daily safety meetings, job safety analyses (JSA) and empowerment to stop work foster a culture of Health, Safety, and Environmental (HSE) awareness and accountability embraced at all levels of CNX; from individual contributors and service providers to management and executive leadership. In addition to our culture of continual assessment, CNX expects all employees and service providers to meet HSE expectations and CNX empowers our employees to make adjustments or stop work as needed in order to correct, or prevent, adverse safety or environmental conditions. CNX expects all of our service providers to meet the training requirements outlined by OSHA and other governing agencies. The safety training content is published on the corporate website to allow service providers constant access to CNX’s message of empowerment and accountability.
Diversity and Inclusion. CNX values diversity throughout the organization. We recognize that a diverse, extensive talent pool provides the best opportunity to acquire unique perspectives, experiences, ideas and solutions that 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 diversity within our executive management team, the highest proportion among our peer group. Of the limited new hires in 2020, 38 percent were diverse.
Employee Attraction and Retention. CNX recognizes the importance of attracting and retaining the best employees to make the most 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 gone to great lengths to establish relationships with local colleges and universities, increasing interest in our organization and industry amongst upcoming graduates. The continued success of CNX is not only contingent upon seeking out the best possible candidates, but retaining and developing the talent that lies within the organization as well. CNX is proud to offer opportunities for employees to improve their skills to achieve their career goals, including continuing education assistance 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. CNX is committed to fostering a culture of accountability and continuous improvement. In 2019, CNX began the implementation 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 of accountability for quality and excellence in all aspects of our business. The Quality Management System 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
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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. No job or activity is considered a success if we compromise the safety of our employees. 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 empowerment through new employee on-boarding, CNX Hazard Training and reinforcement, including an employee recognition 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 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 and emergency medical responders.
Emergency Preparedness and 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 with local municipalities and emergency responders to ensure they are fluent in 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. 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, 2020, 2019 and 2018 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 and disposal of materials used or generated by natural gas operations; the calculation, reporting and payment of taxes on gas production; gathering of natural gas production. In addition to a variety of laws and regulations governing our natural gas operations, we are 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.
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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 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 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 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 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”) 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, 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 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
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natural gas and hydraulic fracturing and completion processes, as well as fugitive emissions from operations. We obtain permits, typically from state or local authorities, to conduct these activities. Additionally, we are 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 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”) 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 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”) pursuant to the Natural Gas Pipeline Safety Act of 1968, (“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”), 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”). 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 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 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. We 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.
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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 certain natural gas pipeline facilities that we believe 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. We 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 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 a legislative and regulatory focus. There are a number of proposed and final laws and regulations that 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 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 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, 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 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. 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 a thorough title examination and perform curative work with respect to significant title defects. Our discovering title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimated gas reserves including our proved undeveloped reserves. In accordance with the foregoing, we have completed title work on substantially all of our natural gas and CBM properties that are currently producing and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry. See “Risk Factors - We may incur losses 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.”
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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 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 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. 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 for our natural gas and NGLs will adversely affect our business, operating results, financial condition and cash flows.
•If natural gas prices decrease or drilling efforts are unsuccessful, we 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 or industry 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.
Risks Related to our Business Operations
•The disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas and NGLs and cash flows from operations.
•Uncertainties exist in the estimation of economical recovery of natural gas 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 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 projects, require substantial capital expenditures and are subject to regulatory, environmental, political, legal and economic risks.
•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 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.
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•Failure to successfully replace our current natural gas and natural gas liquid 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 and natural gas liquid production levels and reserves.
•We may incur losses 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.
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.
•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 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.
•We 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.
•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
•Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are subject to risks and uncertainties.
•We do not completely control the timing of divestitures that we plan 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 we are 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.
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•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. 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, 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;
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•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.
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.
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, we will evaluate this goodwill and other intangible assets for impairment by first assessing qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Estimated fair values could change if, for example, there are changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market capitalization. The future impairment of these assets could require material non-cash charges to our results of operations, which could 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.
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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 customers 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;
•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 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 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.
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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.
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 our Form 10-K, such as those relating to our financial performance and debt obligations. The 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 we are not able to predict, including the length of time that the pandemic continues, its effect on the demand
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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.
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 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
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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
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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 to generate sufficient cash flow, obtain required capital or financing on satisfactory terms or deal with the regulatory and political environment, 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
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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.
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.”
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If CNX cannot find adequate sources of water for our use or we are 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, 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 and natural gas liquid 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 and natural gas liquid 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.
We may incur losses 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.
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.
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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
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.
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.
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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 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
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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 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.
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
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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.
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
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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.
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.
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 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 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
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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 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 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 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.
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.
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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. 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 business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. 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, 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 not completely control the timing of divestitures that we plan 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 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 million remains available for repurchases as of January 26, 2021. 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 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
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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.
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 million as of December 31, 2020. 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 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. 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. 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.
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Our technologies, systems, networks, data centers and those of our business partners 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 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;
•a cyber-incident impacting a communications network or power grid could cause operational disruption resulting in loss of revenues;
•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 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.
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 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 of Operations" in Part I. Item 1 of this Form 10-K for a description of CNX's properties.
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ITEM 3.Legal Proceedings
The first two paragraphs of “Note 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, there were 102 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 current peer group is comprised of CNX, Antero Resources Corporation, Cabot Oil & Gas 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. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2020.

|  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 |  | 2020
CNX Resources Corporation |  | 100.0 |  |  | 230.9 |  |  | 214.0 |  |  | 167.2 |  |  | 129.6 |  |  | 158.1 |
Peer Group |  | 100.0 |  |  | 130.1 |  |  | 107.3 |  |  | 60.4 |  |  | 39.1 |  |  | 43.2 |
S&P 500 Stock Index |  | 100.0 |  |  | 109.5 |  |  | 130.7 |  |  | 122.6 |  |  | 158.1 |  |  | 183.8 |

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).
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The determination to declare and pay dividends is made by CNX's Board of Directors. CNX suspended its quarterly dividend starting in March 2016 to support the Company's increased emphasis on growth at that time. 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% of the aggregate commitments. The Company's net leverage ratio was 2.45 to 1.00 at December 31, 2020. The Credit Facility does not permit dividend payments in the event of default. 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.
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:

ISSUER PURCHASES OF EQUITY SECURITIES
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (000's omitted)
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 |
Total | 4,144,221 |  |  |  |

(1) Includes shares withheld from employees to satisfy minimum tax withholding obligations associated with the vesting of restricted stock during the period.
(2) Shares repurchased as part of the Company's current $750 million share repurchase program authorized by the Board of Directors 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 Note 5 - Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional 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.
42

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.
43

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") 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. 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 ended December 31, 2020 as a direct result of the COVID-19 pandemic, CNX is unable to predict the impact that the COVID-19 pandemic will have on us, including our financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous uncertainties.
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 Highlights:
•Increased proved reserves to 9.5 Tcfe, 13.3% higher than 2019.
•Total gas production of 511.1 Bcfe.
•Shale production of 458.3 Bcfe.
•Repurchased $43 million 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).
2021 Outlook:
•Our 2021 annual gas production is expected to be approximately 540-570 Bcfe.
•Our 2021 E&P capital expenditures are expected to be approximately $430-$470 million.
44

Results of Operations: Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019
Net Loss Attributable to CNX Resources Shareholders
CNX reported 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.

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

Included in the loss for the year ended December 31, 2020 was a $62 million non-cash impairment charge related to exploration and production properties specific to our Southwestern Pennsylvania (SWPA) CBM asset group, a $473 million non-cash impairment charge related to goodwill and an unrealized loss on commodity derivatives of $288 million. 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 were associated with the Company's Central Pennsylvania (CPA) acreage, offset, in part, by an unrealized gain on commodity derivative instruments of $306 million.
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. 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.
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 excluding hedge monetizations) and average unit costs for production operations on a total Company basis:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | Variance
| in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe |  | in Millions |  | Per Mcfe
Total Sales Volumes (Bcfe)* |  |  | 511.1 |  |  |  | 539.1 |  |  |  | (28.0) |
Natural Gas, NGL and Oil Revenue | $ | 897 |  |  | $ | 1.71 |  |  | $ | 1,364 |  |  | $ | 2.52 |  |  | $ | (467) |  |  | $ | (0.81) |
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) |
Lease Operating Expense | 40 |  |  | 0.08 |  |  | 65 |  |  | 0.12 |  |  | (25) |  |  | (0.04) |
Production, Ad Valorem, and Other Fees | 24 |  |  | 0.04 |  |  | 27 |  |  | 0.05 |  |  | (3) |  |  | (0.01) |
Transportation, Gathering and Compression | 286 |  |  | 0.56 |  |  | 331 |  |  | 0.61 |  |  | (45) |  |  | (0.05) |
Depreciation, Depletion and Amortization (DD&A) | 492 |  |  | 0.96 |  |  | 506 |  |  | 0.94 |  |  | (14) |  |  | 0.02 |
Average Costs | 842 |  |  | 1.64 |  |  | 929 |  |  | 1.72 |  |  | (87) |  |  | (0.08) |
Average Margin | $ | 432 |  |  | $ | 0.85 |  |  | $ | 505 |  |  | $ | 0.94 |  |  | $ | (73) |  |  | $ | (0.09) |

*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.
45

The decrease in volumes in the period-to-period comparison was primarily due to 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.
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 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 increased on a per unit basis as a result of fixed depreciation costs related to CNX's gathering infrastructure being spread over fewer production volumes in 2020. The lower production volumes were the result of the strategic temporary shut-in of certain wells as previously discussed.
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 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 oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
46

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.
47

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) |

48

SHALE SEGMENT
The Shale segment had 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.

| For the Years Ended December 31,
| 2020 |  | 2019 |  | Variance |  | Percent Change
Shale Gas Sales Volumes (Bcf) | 428.7 |  |  | 449.6 |  |  | (20.9) |  |  | (4.6) | %
NGLs Sales Volumes (Bcfe)* | 28.1 |  |  | 32.6 |  |  | (4.5) |  |  | (13.8) | %
Oil/Condensate Sales Volumes (Bcfe)* | 1.5 |  |  | 1.2 |  |  | 0.3 |  |  | 25.0 | %
Total Shale Sales Volumes (Bcfe)* | 458.3 |  |  | 483.4 |  |  | (25.1) |  |  | (5.2) | %
Average Sales Price - Gas (per Mcf) | $ | 1.65 |  |  | $ | 2.42 |  |  | $ | (0.77) |  |  | (31.8) | %
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | 0.79 |  |  | $ | 0.14 |  |  | $ | 0.65 |  |  | 464.3 | %
Average Sales Price - NGLs (per Mcfe)* | $ | 2.29 |  |  | $ | 3.20 |  |  | $ | (0.91) |  |  | (28.4) | %
Average Sales Price - Oil/Condensate (per Mcfe)* | $ | 5.83 |  |  | $ | 7.47 |  |  | $ | (1.64) |  |  | (22.0) | %
Total Average Shale Sales Price (per Mcfe) | $ | 2.44 |  |  | $ | 2.61 |  |  | $ | (0.17) |  |  | (6.5) | %
Average Shale Lease Operating Expenses (per Mcfe) | 0.06 |  |  | 0.10 |  |  | (0.04) |  |  | (40.0) | %
Average Shale Production, Ad Valorem, and Other Fees (per Mcfe) | 0.04 |  |  | 0.05 |  |  | (0.01) |  |  | (20.0) | %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe) | 0.54 |  |  | 0.60 |  |  | (0.06) |  |  | (10.0) | %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) | 0.91 |  |  | 0.88 |  |  | 0.03 |  |  | 3.4 | %
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) | %

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $781 million for the year ended December 31, 2020 compared to $1,199 million for the year ended December 31, 2019. The $418 million decrease was due primary to a 31.8% decrease in the average sales price for natural gas, a 5.2% decrease in total Shale sales volumes, and a 28.4% decrease in the average sales price of NGLs.
The decrease in volumes in the period-to-period comparison was primarily due to 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.
The decrease in total average Shale sales price was primarily due to a $0.77 per Mcf decrease in average gas sales price and a $0.91 per Mcfe decrease in the average NGL sales price. These decreases were offset in part by a $0.65 per Mcf increase in the realized gain on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 412.1 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2020 at an average realized gain of $0.82 per Mcf hedged. For the year ended December 31, 2019, these financial hedges represented approximately 348.1 Bcf at an average realized gain of $0.18 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $709 million for the year ended December 31, 2020 compared to $786 million for the year ended December 31, 2019. The decrease in total dollars and decrease in unit costs for the Shale segment were due to the following items:
•Shale lease operating expense was $26 million for the year ended December 31, 2020, compared to $49 million for the year ended December 31, 2019. The decrease in total dollars was primarily due to a decrease 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 by the decrease in total dollars.
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•Shale transportation, gathering and compression costs were $248 million for the year ended December 31, 2020 compared to $290 million for the year ended December 31, 2019. The decreases in total dollars and unit costs were primarily related to lower processing costs due to a drier production mix. Lower firm transportation costs from lower gas sales volumes also contributed to the decrease in total dollars.
•Depreciation, depletion and amortization costs attributable to the Shale segment were $416 million for the year ended December 31, 2020 compared to $426 million for the year ended December 31, 2019. The decrease is due to lower production volumes. These amounts each included depletion on a unit of production basis of $0.81 per Mcfe. 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 $65 million for the year ended December 31, 2020 compared to $74 million for the year ended December 31, 2019. The decrease in the period-to-period comparison was primarily due to a reduction in volumes transported due to temporary production curtailments by third-party producers that occurred early in the 2020 period.
COALBED METHANE (CBM) SEGMENT
The CBM segment had 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.

| For the Years Ended December 31,
| 2020 |  | 2019 |  | Variance |  | Percent Change
CBM Gas Sales Volumes (Bcf) | 52.6 |  |  | 55.4 |  |  | (2.8) |  |  | (5.1) | %
Average Sales Price - Gas (per Mcf) | $ | 2.17 |  |  | $ | 2.96 |  |  | $ | (0.79) |  |  | (26.7) | %
Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) | $ | 0.76 |  |  | $ | 0.13 |  |  | $ | 0.63 |  |  | 484.6 | %
Total Average CBM Sales Price (per Mcf) | $ | 2.93 |  |  | $ | 3.09 |  |  | $ | (0.16) |  |  | (5.2) | %
Average CBM Lease Operating Expenses (per Mcf) | 0.27 |  |  | 0.29 |  |  | (0.02) |  |  | (6.9) | %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) | 0.10 |  |  | 0.12 |  |  | (0.02) |  |  | (16.7) | %
Average CBM Transportation, Gathering and Compression Costs (per Mcf) | 0.73 |  |  | 0.72 |  |  | 0.01 |  |  | 1.4 | %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) | 1.33 |  |  | 1.32 |  |  | 0.01 |  |  | 0.8 | %
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) | %

The CBM segment had natural gas revenue of $114 million for the year ended December 31, 2020 compared to $164 million for the year ended December 31, 2019. The $50 million decrease was due to a 5.1% decrease in total CBM sales volumes and a 26.7% decrease in the average sales price for natural gas in the current period. The decrease in CBM sales volumes was primarily due to normal production declines.
The total average CBM sales price decreased $0.16 per Mcf due to a $0.79 per Mcf decrease in average sales price for natural gas, offset in part by a $0.63 per Mcf increase in the gain on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 48.7 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2020 at an average gain of $0.82 per Mcf hedged. For the year ended December 31, 2019, these financial hedges represented approximately 40.9 Bcf at an average gain of $0.18 per Mcf hedged.
Total operating costs and expenses for the CBM segment were $128 million for the year ended December 31, 2020 compared to $136 million for the year ended December 31, 2019. The decrease in total dollars was primarily due to decreases in employee costs, electrical power expense and repairs and maintenance. The decrease in unit costs was driven by the decrease in total dollars.
•Depreciation, depletion and amortization costs attributable to the CBM segment were $70 million for the year ended December 31, 2020 compared to $73 million for the year ended December 31, 2019. These amounts included depletion on a
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unit of production basis of $0.68 per Mcfe and $0.70 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate was due, in part, to an impairment in the first quarter of 2020 related to the Southwest Pennsylvania (SWPA) CBM asset group. 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 $1,103 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. The decrease in total dollars is discussed below.

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

*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.
Gain or Loss on Commodity Derivative Instruments and Monetization
For the year ended December 31, 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 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. 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 $106 million for the year ended December 31, 2020 compared to $94 million for the year ended December 31, 2019. Purchased gas costs were $101 million for the year ended December 31, 2020 compared to $91 million for the year ended December 31, 2019. The period-to-period increase in purchased gas revenue was due to an increase in purchased gas sales volumes, offset in part by a decrease 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) | %

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Other Operating Income

| For the Years Ended December 31,
(in millions) | 2020 |  | 2019 |  | Variance |  | Percent Change
Water Income | $ | 6 |  |  | $ | 2 |  |  | $ | 4 |  |  | 200.0 | %
Excess Firm Transportation Income | 12 |  |  | 10 |  |  | 2 |  |  | 20.0 | %
Equity in (Loss) Earnings of Affiliates | (1) |  |  | 2 |  |  | (3) |  |  | (150.0) | %
Total Other Operating Income | $ | 17 |  |  | $ | 14 |  |  | $ | 3 |  |  | 21.4 | %

•Water income increased $4 million in the 2020 period due to increased revenue for accepting deliveries of produced water from third-parties for reuse in the Company's hydraulic fracturing.
•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 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 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 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 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 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 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 Expirations 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.
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).
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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 the prior period. 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.
Exploration and Production Related Other Costs

| For the Years Ended December 31,
(in millions) | 2020 |  | 2019 |  | Variance |  | Percent Change
Lease Expiration Costs | $ | 10 |  |  | $ | 31 |  |  | $ | (21) |  |  | (67.7) | %
Seismic Activity | 1 |  |  | 8 |  |  | (7) |  |  | (87.5) | %
Land Rentals | 3 |  |  | 3 |  |  | — |  |  | — | %
Other | 1 |  |  | 2 |  |  | (1) |  |  | (50.0) | %
Total Exploration and Production Related Other Costs | $ | 15 |  |  | $ | 44 |  |  | $ | (29) |  |  | (65.9) | %

•Lease 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")
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,
(in millions) | 2020 |  | 2019 |  | Variance |  | Percent Change
Long-Term Equity-Based Compensation (Non-Cash) | $ | 14 |  |  | $ | 38 |  |  | $ | (24) |  |  | (63.2) | %
Salaries, Wages and Employee Benefits | 31 |  |  | 40 |  |  | (9) |  |  | (22.5) | %
Short-Term Incentive Compensation | 20 |  |  | 21 |  |  | (1) |  |  | (4.8) | %
Other | 44 |  |  | 45 |  |  | (1) |  |  | (2.2) | %
Total SG&A | $ | 109 |  |  | $ | 144 |  |  | $ | (35) |  |  | (24.3) | %

•Long-term equity-based compensation decreased $24 million in the period-to-period comparison due to a change 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.
•Salaries, wages and employee benefits decreased $9 million due to an overall reduction in employees and employee-related costs resulting from a reduction in staff.
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Other Operating Expense

| For the Years Ended December 31,
(in millions) | 2020 |  | 2019 |  | Variance |  | Percent Change
Unutilized Firm Transportation and Processing Fees | $ | 70 |  |  | $ | 55 |  |  | $ | 15 |  |  | 27.3 | %
Insurance Expense | 3 |  |  | 4 |  |  | (1) |  |  | (25.0) | %
Severance Expense | — |  |  | 1 |  |  | (1) |  |  | (100.0) | %
Idle Equipment and Service Charges | 10 |  |  | 12 |  |  | (2) |  |  | (16.7) | %
Other | 2 |  |  | 8 |  |  | (6) |  |  | (75.0) | %
Total Other Operating Expense | $ | 85 |  |  | $ | 80 |  |  | $ | 5 |  |  | 6.3 | %

•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 Income in Total Revenue and Other Operating Income above. The increase in the period-to-period comparison was primarily due to an increase in previously acquired capacity that was not able to be utilized during the current period to transport the Company's flowing production or 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 in the period-to-period comparison primarily due to a tax refund that was received in the 2020 period.
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 to revenue generated from the sale of 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.
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•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, 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.
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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) |

*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.
56

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.
57

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) | 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 related to the Company's hedging program.
58

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) |

59

SHALE SEGMENT
The Shale segment had earnings before income tax of $549 million for the year ended December 31, 2019 compared to earnings before income tax of $627 million for the year ended December 31, 2018.

| 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) | %

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,199 million for the year ended December 31, 2019 compared to $1,349 million for the year ended December 31, 2018. The $150 million decrease was due primarily to a 16.3% decrease in the average sales price for natural gas. This decrease was offset in part by 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 (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) as well as normal production declines in the remaining dry Shale wells.
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.
Total operating costs and expenses for the Shale segment were $786 million for the year ended December 31, 2019 compared to $752 million for the year ended December 31, 2018. The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items:
•Shale lease operating expenses were $49 million for the year ended December 31, 2019 compared to $71 million for the year ended December 31, 2018. The decrease in total dollars was primarily due to a decrease in water disposal costs due to an increase in reuse of produced water in well completions and a reduction in employee costs. The decrease in unit costs was driven by the decrease in total dollars.
60

•Shale transportation, gathering and compression costs were $290 million for the year ended December 31, 2019 compared to $251 million for the year ended December 31, 2018. The $39 million increase in total dollars and $0.03 per Mcfe increase in unit costs were both due to the overall increase in Shale volumes and the new firm transportation contracts which began in the fourth quarter of 2018 and first quarter of 2019.
•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 decrease in the units of production depreciation, depletion and amortization rate was due to positive reserve revisions within the core SWPA development area, partially offset by an increase in the units of production depreciation, depletion and amortization rate due to negative reserve revisions within the Ohio operations, an increase in capital expenditures 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.
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 $74 million for the year ended December 31, 2019 compared to $90 million for the year ended December 31, 2018. The decrease in the period-to-period comparison was primarily due to a reduction in third-party volumes transported 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 compared to earnings before income tax of $50 million for 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 natural gas revenue of $164 million for the year ended December 31, 2019 compared to $213 million for the year ended December 31, 2018. 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 in CBM sales volumes was primarily due to normal well declines, as well as the sale of certain CBM assets that were sold along with the majority of CNX's shallow oil and gas assets in 2018 (See Note 4 - Acquisitions and Dispositions 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 the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 40.9 Bcf of the Company's produced CBM 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 44.8 Bcf at an average loss of $0.20 per Mcf hedged.
61

Total operating costs and expenses for the CBM segment 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.
•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 includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, 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 $524 million for the year ended December 31, 2019 compared to earnings before income tax of $422 million for the year ended December 31, 2018.

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

*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
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, the Other Segment recognized an unrealized gain on commodity derivative instruments of $40 million and cash settlements paid of $1 million. The unrealized gain or loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Purchased Gas
Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were $94 million for the year ended December 31, 2019 compared to $66 million for the year ended December 31, 2018. Purchased gas costs were $91 million for
62

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

Other Operating Income

| For the Years Ended December 31,
(in millions) | 2019 |  | 2018 |  | Variance |  | Percent Change
Water Income | $ | 2 |  |  | $ | 11 |  |  | $ | (9) |  |  | (81.8) | %
Equity in Earnings of Affiliates | 2 |  |  | 5 |  |  | (3) |  |  | (60.0) | %
Excess Firm Transportation Income | 10 |  |  | 10 |  |  | — |  |  | — | %
Total Other Operating Income | $ | 14 |  |  | $ | 26 |  |  | $ | (12) |  |  | (46.2) | %

•Water income decreased $9 million due to nominal sales of freshwater to third parties for hydraulic fracturing in 2019 compared to 2018.
Impairment of Exploration and Production Properties
During the fourth quarter of 2019, CNX identified certain indicators of impairment specific to our CPA Marcellus asset group 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 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 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 impairment related to unproved properties of $119 million that was included in Impairment of Unproved Properties and Expirations 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.
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.
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In connection with the AEA with HG Energy (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) that occurred during the year ended December 31, 2018, CNX determined that the carrying value of the other intangible asset - customer relationship exceeded its fair value, and an impairment of $19 million was included in Impairment of Other Intangible Assets in the Consolidated Statement of Income. No such transactions occurred in the 2019 period.
Exploration and Production Related Other Costs

| For the Years Ended December 31,
(in millions) | 2019 |  | 2018 |  | Variance |  | Percent Change
Lease Expiration Costs | $ | 31 |  |  | $ | 5 |  |  | $ | 26 |  |  | 520.0 | %
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 | $ | 44 |  |  | $ | 12 |  |  | $ | 32 |  |  | 266.7 | %

•Lease 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.
SG&A
SG&A costs include costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees 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) | 2019 |  | 2018 |  | Variance |  | Percent Change
Long-Term Equity-Based Compensation (Non-Cash) | $ | 38 |  |  | $ | 21 |  |  | $ | 17 |  |  | 81.0 | %
Salaries, Wages and Employee Benefits | 40 |  |  | 40 |  |  | — |  |  | — | %
Short-Term Incentive Compensation | 21 |  |  | 24 |  |  | (3) |  |  | (12.5) | %
Other | 45 |  |  | 50 |  |  | (5) |  |  | (10.0) | %
Total SG&A | $ | 144 |  |  | $ | 135 |  |  | $ | 9 |  |  | 6.7 | %

•Long-term equity-based compensation 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 change 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.
•Short-term incentive compensation decreased $3 million due to a reduction in the number of employees and lower projected payouts in the 2019 period.
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Other Operating Expense

| For the Years Ended December 31,
(in millions) | 2019 |  | 2018 |  | Variance |  | Percent Change
Unutilized Firm Transportation and Processing Fees | $ | 55 |  |  | $ | 42 |  |  | $ | 13 |  |  | 31.0 | %
Idle Equipment and Service Charges | 12 |  |  | 5 |  |  | 7 |  |  | 140.0 | %
Insurance Expense | 4 |  |  | 3 |  |  | 1 |  |  | 33.3 | %
Severance Expense | 1 |  |  | 1 |  |  | — |  |  | — | %
Litigation Expense | — |  |  | 4 |  |  | (4) |  |  | (100.0) | %
Water Expense | — |  |  | 6 |  |  | (6) |  |  | (100.0) | %
Other | 8 |  |  | 11 |  |  | (3) |  |  | (27.3) | %
Total Other Operating Expense | $ | 80 |  |  | $ | 72 |  |  | $ | 8 |  |  | 11.1 | %

•Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The 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 increase 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 Income in Total Other Operating Income above.
•Idle Equipment and Service Charges primarily relate to the temporary idling of some of the Company's natural gas drilling rigs as well as related equipment and other services that may be needed in the natural gas drilling and completions process. The increase of $7 million in the period-to-period comparison was primarily the result CNX terminating one of its drilling rig contracts early, as well as additional idle service expense related to the Shaw 1G Utica Shale well that occurred in the first quarter of 2019.
•Water Expense decreased $6 million due to the associated costs related to the sales of freshwater to third-parties for hydraulic fracturing during 2018 in Total Other Operating Income above. There were nominal sales during 2019.
Other Expense (Income)

| For the Years Ended December 31,
(in millions) | 2019 |  | 2018 |  | Variance |  | Percent Change
Other Income |  |  |  |  |  |  |
Royalty Income | $ | 4 |  |  | $ | 15 |  |  | $ | (11) |  |  | (73.3) | %
Right of Way Sales | 9 |  |  | 14 |  |  | (5) |  |  | (35.7) | %
Interest Income | 2 |  |  | — |  |  | 2 |  |  | 100.0 | %
Other | 4 |  |  | 8 |  |  | (4) |  |  | (50.0) | %
Total Other Income | $ | 19 |  |  | $ | 37 |  |  | $ | (18) |  |  | (48.6) | %
Other Expense |  |  |  |  |  |  |
Bank Fees | $ | 11 |  |  | $ | 11 |  |  | $ | — |  |  | — | %
Professional Services | 4 |  |  | 7 |  |  | (3) |  |  | (42.9) | %
Other Land Rental Expense | 4 |  |  | 4 |  |  | — |  |  | — | %
Other Corporate Expense | 3 |  |  | — |  |  | 3 |  |  | 100.0 | %
Total Other Expense | $ | 22 |  |  | $ | 22 |  |  | $ | — |  |  | — | %
Total Other Expense (Income) | $ | 3 |  |  | $ | (15) |  |  | $ | 18 |  |  | 120.0 | %

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Gain on Asset Sales and Abandonments, net
A gain on asset sales of $36 million related to non-core assets was recognized in the year ended December 31, 2019 compared to a gain of $157 million in the year ended December 31, 2018, primarily due to the $131 million gain that was recognized 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 in the 2018 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.
Gain on Previously Held Equity Interest
CNX recognized a gain on previously held equity interest of $624 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.
Loss on Debt Extinguishment
A loss on debt extinguishment of $8 million was recognized in the year ended December 31, 2019 compared to a loss on debt extinguishment of $54 million in the year ended December 31, 2018. During the year ended December 31, 2019, CNX purchased $400 million of its 5.875% senior notes due in April 2022 at an average price equal to 101.5% of the principal amount. During the 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% 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 | %

•The $5 million increase 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 million purchase of the outstanding 5.875% senior notes due in April 2022 during the year ended December 31, 2018. Additionally, the Company purchased $400 million of its outstanding 5.875% senior notes due in April 2022 during the year ended December 31, 2019. 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) | 2019 |  | 2018 |  | Variance |  | Percent Change
Total Company Earnings Before Income Tax | $ | 60 |  |  | $ | 1,099 |  |  | $ | (1,039) |  |  | (94.5) | %
Income Tax Expense | $ | 28 |  |  | $ | 216 |  |  | $ | (188) |  |  | (87.0) | %
Effective Income Tax Rate | 46.5 | % |  | 19.6 | % |  | 26.9 | % |  |

The effective income tax rate was 46.5% for the year ended December 31, 2019, compared to 19.6% for the year ended December 31, 2018. The effective rate for the year ended December 31, 2019 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”)
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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.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at the date of the financial statements. See Note 1-Significant Accounting Policies 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 used in the preparation of the Consolidated Financial Statements.
Asset Retirement Obligations
Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate 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 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.
The Company believes that the accounting estimates related to asset retirement obligations are “critical accounting estimates” because the Company must assess the expected amount and timing of asset retirement obligations. In addition, 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 in the Company’s assumptions.
Income Taxes
Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of 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 December 31, 2020, CNX had deferred tax liabilities in excess of deferred tax assets of approximately $343 million. At December 31, 2020, CNX had a valuation allowance of $123 million on deferred tax assets.
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.
The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise
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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.
Natural Gas, NGL, Condensate and Oil Reserve ("Natural Gas Reserve") Values
Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and natural gas which, by analysis of geoscience 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.
There are numerous uncertainties inherent in estimating quantities and values 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 based on engineering, economic and geological data assembled and analyzed by our staff. Our natural gas reserves are reviewed by independent experts each year. Some of the factors and assumptions which impact economically recoverable reserve estimates include:
•geological conditions;
•historical production from the area compared with production from other producing areas;
•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 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 respect 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 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, an impairment of $62 million was included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. This impairment was related to our Southwest Pennsylvania (SWPA) coalbed methane (CBM) asset group. For the year ended December 31, 2019, an impairment of $327 million was 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. See Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
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There were no other impairments related to proved properties in the years ended December 31, 2020, 2019 or 2018.
CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. 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. 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.
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 closed on January 3, 2018, CNX recorded $796 million of goodwill. See Note 4 - Acquisitions and Dispositions for more information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Goodwill is not amortized, but rather it is evaluated 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. We may assess goodwill for impairment by first performing a qualitative assessment, which considers specific factors, based on the weight of evidence, and the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. 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, we perform a quantitative impairment test. From time to time, we may also bypass the qualitative assessment and proceed directly to the quantitative impairment test. Under the quantitative goodwill impairment test, the fair value of a reporting unit is compared to its carrying amount. If the quantitative goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded, which is the difference between carrying value of the reporting unit and its fair value, with the impairment loss not to exceed the amount of goodwill recorded. The estimation of fair value of a reporting unit is determined using the income approach and/or the market approach as described below.
The income approach is a quantitative evaluation to determine the fair value of the reporting unit. Under the income approach we determine the fair value based on estimated future cash flows discounted by an estimated weighted-average cost of capital plus a forecast risk, which reflects the overall level of inherent risk of the reporting unit and the rate of return a market participant would expect to earn. The inputs used for the income approach were significant unobservable inputs, or Level 3 inputs, as described in the accounting fair value hierarchy. CNX determined the fair value based on estimated future cash flows and earnings before deducting net interest expense (interest expense less interest income) and income taxes (EBITDA - a non-GAAP financial measure) and also included estimates for capital expenditures, discounted to present value using a risk-adjusted rate, which management feels reflects the overall level of inherent risk of the reporting unit. Cash flow projections were derived from board approved budgeted amounts, a seven-year operating forecast and an estimate of future cash flows. Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur.
The market approach measures the fair value of a reporting unit through the analysis of recent transactions and/or financial multiples of comparable businesses. Consideration is given to the financial conditions and operating performance of the reporting unit being valued relative to those publicly-traded companies operating in the same or similar lines of business.
The determination of the fair value requires us to make significant estimates and assumptions. These estimates and assumptions primarily include but are not limited to: the selection of appropriate peer group companies; control premiums appropriate for acquisitions in the industries in which we compete; discount rates; terminal growth rates; and forecasts of revenue, operating income, depreciation and amortization and capital expenditures. The estimates of future cash flows and
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EBITDA are subjective in nature and are subject to impacts from business risks as described in Part I. Item 1A. "Risk Factors" of this Form 10-K. 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. Although we believe our estimates of fair value are reasonable, actual financial results could differ from those estimates due to the inherent uncertainty involved in making such estimates. Changes in assumptions concerning future financial results or other underlying assumptions could have a significant impact on either the fair value of the reporting unit, the amount of any goodwill impairment charge, or both.
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. 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 more information. There were no other impairments related to goodwill in the years ended December 31, 2020, 2019 or 2018. Any additional adverse changes in the future could reduce the underlying cash flows used to estimate fair values and could result in a decline in fair value that could trigger future impairment charges.
The Company believes that the accounting estimates related to goodwill 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. 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 as well as other assumptions such as movement in the Company's stock price, weighted-average cost of capital, terminal growth rates, 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 and industry multiples. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about goodwill impairment 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 Definite-lived Intangible Assets
Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed for impairment when indicators of impairment are present. Impairment tests require that the Company first compare future undiscounted cash flows to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the asset to its estimated fair value is required.
In May 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were acquired in connection with the Midstream acquisition exceeded their fair value in conjunction with the AEA with HG Energy (See Note 4 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). As a result, CNX recognized an impairment on this intangible asset of $19 million, which is included in Impairment of Other Intangible Assets in the Consolidated Statements of Income for the year ended December 31, 2018. There were no other impairments related to definite-lived intangible assets in the years ended December 31, 2020, 2019 or 2018.
The Company believes that the accounting estimates related to the impairment of definite-lived intangible 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. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about the impairment of definite-lived intangible 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.
Business Combinations
Accounting for the acquisition of a business requires the identifiable assets and liabilities acquired to be recorded at fair value. The most significant assumptions in a business combination include those used to estimate the fair value of the oil and natural gas properties acquired. The fair value of proved natural gas properties is determined using a risk-adjusted after-tax
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discounted cash flow analysis based upon significant assumptions including commodity prices; projections of estimated quantities of reserves; projections of future rates of production; timing and amount of future development and operating costs; projected reserve recovery factors; and a weighted average cost of capital.
The Company utilizes the guideline transaction method to estimate the fair value of unproved properties acquired in a business combination which requires the Company to use judgment in considering the value per undeveloped acre in recent comparable transactions to estimate the value of unproved properties.
The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach, which incorporates assumptions about the replacement costs for similar assets, the relative age of assets and any potential economic or functional obsolescence.
The fair values of the intangible assets are estimated using the multi-period excess earnings model which estimates revenues and cash flows derived from the intangible asset and then deducts portions of the cash flow that can be attributed to supporting assets otherwise recognized. The Company’s intangible assets are comprised of customer relationships.
The Company believes that the accounting estimates related to business combinations are “critical accounting estimates” because the Company must, in determining the fair value of assets acquired, make assumptions about future commodity prices; projections of estimated quantities of reserves; projections of future rates of production; projections regarding the timing and amount of future development and operating costs; and projections of reserve recovery factors, per acre values of undeveloped property, replacement cost of and future cash flows from midstream assets, cash flow from customer relationships and non-compete agreements and the pre and post modification value of stock based awards. Different assumptions may result in materially different values for these assets which would impact the Company’s financial position and future results of operations.
Convertible Senior Notes
CNX accounted for its Convertible Senior Notes due May 2026 as separate liability and equity components. The carrying amount of the liability component of the instrument was computed by estimating the fair value of a similar liability without the conversion option. The amount of the equity component was then calculated by deducting the fair value of the liability component from the principal amount of the instrument. The difference between the principal amount and the liability component represents a debt discount that is amortized to interest expense over the respective term of the Convertible Notes using the effective interest rate method. The equity component is not remeasured as long as it continues to meet the conditions for equity classification. Additionally, a detailed analysis of the terms of the convertible senior notes transactions was required to determine existence of any derivatives that may require separate mark-to-market accounting under applicable accounting guidance.
The Company believes that the accounting estimates related to the Convertible Notes are “critical accounting estimates” because of the judgment required when determining the balance sheet classification of the elements of the Convertible Notes as well as the existence of any derivatives that may require separate presentation under the applicable accounting guidance. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and the resulting balance sheet classification.
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Liquidity and Capital Resources
CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations 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 next 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 or due to the uncertainty created by the COVID-19 pandemic, 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, 2020, CNX was in compliance with all of its debt covenants. After considering the potential effect of a significant decline in commodity prices as well as the uncertainty created by the COVID-19 pandemic on its operations, CNX currently expects to remain in compliance with its debt covenants.
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 asset of $118 million at December 31, 2020 and a net asset of $406 million at December 31, 2019. The Company has not experienced any issues of non-performance by derivative counterparties.
CNX frequently evaluates potential acquisitions. CNX has funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity financing, will be available to CNX on terms which CNX finds acceptable, or at all.
Cash Flows (in millions)

| For the Years Ended December 31,
| 2020 |  | 2019 |  | Change
Cash Provided by Operating Activities | $ | 795 |  |  | $ | 981 |  |  | $ | (186) |
Cash Used in Investing Activities | $ | (439) |  |  | $ | (1,147) |  |  | $ | 708 |
Cash (Used in) Provided by Financing Activities | $ | (351) |  |  | $ | 166 |  |  | $ | (517) |

Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:
•Net income decreased $461 million in the period-to-period comparison.
•Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $473 million impairment of goodwill, a $266 million decrease in impairment of exploration and production properties, a $119 million decrease in impairment of unproved properties and expirations, a $595 million net change in commodity derivative instruments, an $18 million increase in the gain on debt extinguishment, a $24 million decrease in stock based compensation, $197 million change in deferred income taxes, and 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 $705 million in the period-to-period comparison primarily due to decreased expenditures in the Shale segment resulting from decreased drilling and completions activity. Gathering capital expenditures decreased due primarily to the substantial build out that was completed during 2019.
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•Proceeds from asset sales increased $3 million mainly due to increased surface sales and oil and natural gas assignment sales in the year ended December 31, 2020.
Cash (used in) provided by financing activities changed in the period-to-period comparison primarily due to the following items:
•In the year ended December 31, 2020, CNX paid $882 million to purchase $894 million of Senior Notes due in 2022 at 98.6% of the principal amount. In the year ended December 31, 2019, CNX paid $406 million to purchase $400 million of the Senior Notes due in 2022 at 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.
•In the year ended December 31, 2020, there were $21 million of net payments on the CNXM Credit Facility compared to $228 million of net proceeds in the year ended December 31, 2019.
•In the year ended December 31, 2020, there were $500 million of net payments on the CNX Credit Facility compared to $49 million of net proceeds in the year ended December 31, 2019.
•In the year ended December 31, 2020, CNX received proceeds of $500 million from the issuance of Senior Notes due in 2029.
•In the year ended December 31, 2020, CNX received proceeds of $207 million from the issuance of Senior Notes due in 2027 at 103.5% of the principal amount. The new Senior Notes due in 2027 were offered as additional notes under an indenture pursuant to the $500 million Senior Notes due in 2027 that were issued in the year ended December 31, 2019. 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, 2020, there were $159 million of net proceeds from the Cardinal States Facility and CSG Holdings 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.
•In the year ended December 31, 2020, CNX received proceeds of $335 million from the issuance of the Convertible Notes. 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, 2020, CNX paid $36 million for capped call transactions related to the issuance of the Convertible Notes. 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, 2020, there were $42 million in distributions to CNXM noncontrolling interest holders compared to distributions of $64 million in the year ended December 31, 2019.
•In the years ended December 31, 2020 and 2019, CNX repurchased $37 million and $117 million, respectively, of its common stock on the open market.
•Debt issuance and financing fees increased $15 million primarily due to the fees associated with the borrowings on the Cardinal States Facility and CSG Holdings Facility and the issuance of the Convertible Notes.
The following is a summary of the Company's significant contractual obligations at December 31, 2020 (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 | $ | 806 |  |  | $ | 970 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,776 |
Gas Firm Transportation and Processing | 252,886 |  |  | 430,312 |  |  | 390,693 |  |  | 985,201 |  |  | 2,059,092 |
Long-Term Debt | 22,574 |  |  | 48,181 |  |  | 497,423 |  |  | 1,882,675 |  |  | 2,450,853 |
Interest on Long-Term Debt | 122,251 |  |  | 262,415 |  |  | 240,083 |  |  | 202,118 |  |  | 826,867 |
Finance Lease Obligations | 6,876 |  |  | 837 |  |  | 182 |  |  | 38 |  |  | 7,933 |
Interest on Finance Lease Obligations | 262 |  |  | 52 |  |  | 11 |  |  | 1 |  |  | 326 |
Operating Lease Obligations | 52,575 |  |  | 23,301 |  |  | 7,434 |  |  | 22,500 |  |  | 105,810 |
Interest on Operating Lease Obligations | 3,615 |  |  | 3,744 |  |  | 2,823 |  |  | 3,496 |  |  | 13,678 |
Long-Term Liabilities—Employee Related (a) | 1,992 |  |  | 4,169 |  |  | 4,436 |  |  | 35,129 |  |  | 45,726 |
Other Long-Term Liabilities (b) | 201,684 |  |  | 10,000 |  |  | 10,000 |  |  | 64,713 |  |  | 286,397 |
Total Contractual Obligations (c) | $ | 665,521 |  |  | $ | 783,981 |  |  | $ | 1,153,085 |  |  | $ | 3,195,871 |  |  | $ | 5,798,458 |

_________________________
(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.
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(c)The table above does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
Debt
At December 31, 2020, CNX had total long-term debt of $2,451 million, including the current portion of long-term debt of $23 million and 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 $7 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) or CSG Holdings III LLC.
•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) or CSG Holdings III LLC.
•An aggregate principal amount of $400 million of 6.50% Senior Notes due March 2026 issued by CNXM, less $4 million of unamortized bond discount. Interest on the notes is payable March 15 and September 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% Senior Notes due May 2026, unless earlier redeemed, repurchased, or converted, less $108 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) or CSG Holdings III LLC.
•An aggregate principal amount of $291 million in outstanding borrowings under the CNXM Credit Facility. CNX is not a guarantor of CNXM's Credit Facility.
•An aggregate principal amount of $161 million in outstanding borrowings under the CNX Credit Facility. CNXM (or its subsidiaries or general partner) is not a guarantor of CNX's Credit Facility.
•An aggregate principal amount of $115 million in outstanding borrowings under the Cardinal States Facility, less $1 million of unamortized discount. Interest and a portion of the obligation are paid quarterly.
•An aggregate principal amount of $45 million in outstanding borrowings under the CSG Holdings Facility, less a nominal unamortized discount. Interest and a portion of the obligation are paid quarterly.
Total Equity and Dividends
CNX had total equity of $4,422 million at December 31, 2020 compared to $4,962 million at December 31, 2019. 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.
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 suspended its quarterly dividend in March 2016 to further reflect the Company's increased emphasis on growth at that time. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX, and such other factors as the Board of Directors deems relevant. CNX's Credit Facility limits its ability to pay dividends in excess of an annual rate of $0.10 per share when the Company's net leverage ratio exceeds 3.00 to 1.00 and is subject to availability under the Credit Facility of at least 15% of the aggregate commitments. The net leverage ratio was 2.45 to 1.00 at December 31, 2020. The Credit Facility does not permit dividend payments in the event of default. The indentures to the 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 under the year ended December 31, 2020.
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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, 2020. 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.
Recent Accounting Pronouncements
In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This ASU simplifies an entity's accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, simplifies the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification, requires entities to use the if-converted method for all convertible instruments in the diluted EPS calculation and include the effect of potential share settlement (if the effect is more dilutive) for instruments that may be settled in cash or shares, except for certain liability-classified share-based payment awards, requires new disclosures about events that occur during the reporting period and cause conversion contingencies to be met and about the fair value of an entity's convertible debt at the instrument level, among other things. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years, and can be adopted through either a modified retrospective method of transition or a fully retrospective method of transition. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. The Company is still evaluating the effect of adopting this guidance.
In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (Topic 848). This ASU provides optional expedient and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. In response to the concerns about structural risks of interbank offered rates (IBORs) and, particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR), regulators in several jurisdictions around the world have undertaken reference rate reform initiatives to identify alternative reference rates that are more observable or transaction based and less susceptible to manipulation. The ASU provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates that are expected to be discontinued. In January 2021, the FASB issued ASU 2021-01, which clarifies that certain provisions in Topic 848, if elected by an entity, apply to derivative instruments that use an interest rate for margining, discounting, or contract price alignment that is modified as a result of reference rate reform. The amendments in these ASUs are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is still evaluating the effect of adopting this guidance.
In March 2020, the FASB issued ASU 2020-03 - Codification Improvements to Financial Instruments. This ASU improves and clarifies various financial instruments topics, including the CECL standard (see Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K for more information). The ASU includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments in this ASU have different effective dates. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In addition to the risks inherent in operations, CNX is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CNX's exposure to the risks of changing commodity prices, interest rates and foreign exchange rates.
CNX is exposed to market price risk in the normal course of selling natural gas and liquids. CNX uses fixed-price contracts, options and derivative commodity instruments (over-the-counter swaps) to minimize exposure to market price volatility in the sale of natural gas. Under our risk management policy, it is not our intent to engage in derivative activities for speculative purposes. Typically, CNX “sells” swaps under which it receives a fixed price from counterparties and pays a floating market price. During the second quarter of 2020, CNX purchased, rather than sold, financial swaps for the period May through November of 2020 under which CNX will pay a fixed price to and receive a floating price from its hedge counterparties.
CNX has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. The Company's market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.
CNX believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates our exposure to material risks. The use of derivative instruments without other risk assessment procedures could materially affect the Company's results of operations depending on market prices; however, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity due to our risk assessment procedures and internal controls.
For a summary of accounting policies related to derivative instruments, see Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
At December 31, 2020 and 2019, our open derivative instruments were in a net asset position with a fair value of $118 million and $406 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at December 31, 2020 and 2019. A hypothetical 10 percent increase in future natural gas prices would have decreased the fair value by $362 million and $383 million at December 31, 2020 and 2019, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the fair value by $366 million and $402 million at December 31, 2020 and 2019, respectively.
CNX's interest expense is sensitive to changes in the general level of interest rates in the United States. The Company uses derivative instruments to manage risk related to interest rates. These instruments change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. At December 31, 2020 and 2019, CNX had $1,980 million and $1,797 million, respectively, aggregate principal amount of debt outstanding under fixed-rate instruments, including unamortized debt issuance costs of $27 million and $9 million, respectively. At December 31, 2020 and 2019, CNX had $452 million and $973 million, respectively, of debt outstanding under variable-rate instruments. CNX’s primary exposure to market risk for changes in interest rates relates to our Credit Facility, under which there were $161 million of borrowings at December 31, 2020 and $661 million at December 31, 2019, and CNXM's revolving credit facility, under which there were $291 million of borrowings at December 31, 2020 and $312 million at December 31, 2019. A hypothetical 100 basis-point increase in the average rate for CNX's variable-rate instruments would decrease pre-tax future earnings as of December 31, 2020 and 2019 by $5 million and $10 million, respectively, on an annualized basis.
All of CNX's transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks.
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Natural Gas Hedging Volumes
As of January 7, 2021, the Company's hedged volumes for the periods indicated are as follows:

| For the Three Months Ended |  |
| March 31, |  | June 30, |  | September 30, |  | December 31, |  | Total Year
2021 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 126.3 |  |  | 112.1 |  |  | 115.2 |  |  | 119.2 |  |  | 472.1*
Weighted Average Hedge Price per Mcf | $ | 2.57 |  |  | $ | 2.45 |  |  | $ | 2.45 |  |  | $ | 2.52 |  |  | $ | 2.50 |
2022 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 101.4 |  |  | 96.9 |  |  | 97.9 |  |  | 95.1 |  |  | 391.3
Weighted Average Hedge Price per Mcf | $ | 2.41 |  |  | $ | 2.32 |  |  | $ | 2.32 |  |  | $ | 2.30 |  |  | $ | 2.34 |
2023 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 70.2 |  |  | 71.0 |  |  | 71.8 |  |  | 71.8 |  |  | 284.8 |
Weighted Average Hedge Price per Mcf | $ | 2.24 |  |  | $ | 2.21 |  |  | $ | 2.21 |  |  | $ | 2.23 |  |  | $ | 2.22 |
2024 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 67.6 |  |  | 64.7 |  |  | 65.4 |  |  | 65.4 |  |  | 263.1 |
Weighted Average Hedge Price per Mcf | $ | 2.32 |  |  | $ | 2.27 |  |  | $ | 2.27 |  |  | $ | 2.27 |  |  | $ | 2.28 |
2025 Fixed Price Volumes |  |  |  |  |  |  |  |  |
Hedged Bcf | 25.4 |  |  | 25.7 |  |  | 26.0 |  |  | 25.9 |  |  | 103.0 |
Weighted Average Hedge Price per Mcf | $ | 2.10 |  |  | $ | 2.10 |  |  | $ | 2.10 |  |  | $ | 2.10 |  |  | $ | 2.10 |

*Quarterly volumes do not add to annual volumes inasmuch as a discrete condition in individual quarters, where basis hedge volumes exceed NYMEX hedge volumes, does not exist for the year taken as a whole.
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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

|  | Page
Report of Independent Registered Public Accounting Firm | 79
Consolidated Statements of Income for the Years Ended December 31, 2020, 2019 and 2018 | 82
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018 | 83
Consolidated Balance Sheets at December 31, 2020 and 2019 | 84
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2020, 2019 and 2018 | 86
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, 2018 | 87
Notes to the Audited Consolidated Financial Statements | 88

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Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of CNX Resources Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CNX Resources Corporation and Subsidiaries (the Company) as of December 31, 2020 and 2019, and the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15 (a) (2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 9, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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| Issuance of Convertible Senior Notes
Description of the Matter | As described in Note 12 to the consolidated financial statements, in April 2020, the Company issued $345.0 million of aggregate principal of 2.25% convertible senior notes due May 2026 in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. Additionally, the Company entered into separate capped call transactions to reduce potential dilution to the Company’s common stock upon any conversion of the Convertible Notes. These transactions are collectively referred to as the Convertible Notes Transactions. To account for the Convertible Notes, the Company was required to separate the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of a similar debt instrument that does not have an associated conversion feature. The carrying amount of the equity component was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. The equity component was recorded in capital in excess of par value in the consolidated statement of stockholders’ equity and is not remeasured as long as it continues to meet the conditions for equity classification.
| Auditing the Company’s accounting for the Convertible Notes Transactions was complex due to the judgment that was required in determining the balance sheet classification of the elements of the Convertible Notes. Additionally, a detailed analysis of the terms of the Convertible Notes Transactions was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Convertible Notes Transactions. For example, we tested the Company's controls over the initial recognition and measurement of the Convertible Notes Transactions, including the recording of the associated liability and equity components. We also tested the evaluation of the Notes and the identification and evaluation of specific features and the related accounting.
| To test the initial accounting for the Convertible Notes Transactions, our audit procedures included, among others, inspection of the agreements underlying the Convertible Notes Transactions and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the convertible notes, including conclusions reached with respect to identification and bifurcation of embedded features.
| Valuation of Goodwill
Description of the Matter | At December 31, 2020, the Company’s goodwill was $323.3 million and all goodwill was attributed to the Midstream reporting unit in the Shale segment. As discussed in Note 9 to the consolidated financial statements, goodwill is tested for impairment at least annually, 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.
| Auditing management’s annual and interim quantitative goodwill impairment tests was complex and highly judgmental due to the significant estimation required to determine the fair value of the Midstream reporting unit. In particular, the fair value estimates were sensitive to significant assumptions, including changes in estimated future revenues, which are affected by expectations about future market, industry and economic conditions.
How We Addressed the Matter in Our Audit | We tested controls that address the risks of material misstatement related to the Company’s goodwill impairment review process, including controls over management’s review of the significant assumptions described above.

80

| To test the estimated fair value of the Company’s midstream reporting unit, we performed audit procedures that included, among others, assessing methodologies and testing the significant assumptions discussed above and the underlying data used by the Company in its analysis. We compared the significant assumptions used by management to current industry and economic trends and evaluated whether changes in those trends would affect the significant assumptions. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting unit that would result from changes in the assumptions.
| Depreciation, Depletion & Amortization
Description of the Matter | As described in Note 1, under the successful efforts method of accounting, depreciation, depletion, and amortization (DD&A) related to proved gas properties is recorded using the units-of-production method. For the year ended December 31, 2020, the Company recorded DD&A expense related to proved gas properties of $400.8 million. Proved developed reserves, as estimated by petroleum engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by petroleum engineers, are used to calculate depletion on property acquisitions. Proved oil and natural gas reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Significant judgment is required by the Company’s internal engineering staff in evaluating geological and engineering data when estimating proved oil and natural gas reserves. Estimating reserves also requires the selection of inputs, including price and operating, and development cost assumptions as well as tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and natural gas reserves, management used independent petroleum engineers to audit the estimates prepared by the Company’s internal engineering staff as of December 31, 2020.
| Auditing the Company’s DD&A calculation was especially complex because of the use of the work of the internal engineering staff and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the independent petroleum engineers in estimating proved oil and natural gas reserves.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the independent petroleum engineers for use in estimating the proved oil and natural gas reserves.
| Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the individual primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent petroleum engineers used to audit the estimates. In addition, in assessing whether we can use the work of the independent petroleum engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the independent petroleum engineers in estimating proved oil and natural gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved oil and natural gas reserves amounts used to the Company’s reserve report.

/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Pittsburgh, Pennsylvania
February 9, 2021
81

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data) | For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Revenue and Other Operating Income: |  |  |  |  |
Natural Gas, NGLs and Oil Revenue | $ | 896,745 |  |  | $ | 1,364,325 |  |  | $ | 1,577,937 |
Gain (Loss) on Commodity Derivative Instruments | 172,982 |  |  | 376,105 |  |  | (30,212) |
Purchased Gas Revenue | 105,792 |  |  | 94,027 |  |  | 65,986 |
Other Revenue and Operating Income | 82,459 |  |  | 87,992 |  |  | 116,723 |
Total Revenue and Other Operating Income | 1,257,978 |  |  | 1,922,449 |  |  | 1,730,434 |
Costs and Expenses: |  |  |  |  |
Operating Expense |  |  |  |  |
Lease Operating Expense | 40,407 |  |  | 65,443 |  |  | 95,139 |
Transportation, Gathering and Compression | 285,683 |  |  | 330,539 |  |  | 302,933 |
Production, Ad Valorem and Other Fees | 24,196 |  |  | 27,461 |  |  | 32,750 |
Depreciation, Depletion and Amortization | 501,821 |  |  | 508,463 |  |  | 493,423 |
Exploration and Production Related Other Costs | 14,994 |  |  | 44,380 |  |  | 12,033 |
Purchased Gas Costs | 100,902 |  |  | 90,553 |  |  | 64,817 |
Impairment of Exploration and Production Properties | 61,849 |  |  | 327,400 |  |  | — |
Impairment of Goodwill | 473,045 |  |  | — |  |  | — |
Impairment of Unproved Properties and Expirations | — |  |  | 119,429 |  |  | — |
Impairment of Other Intangible Assets | — |  |  | — |  |  | 18,650 |
Selling, General and Administrative Costs | 109,375 |  |  | 143,550 |  |  | 134,806 |
Other Operating Expense | 85,472 |  |  | 79,255 |  |  | 72,412 |
Total Operating Expense | 1,697,744 |  |  | 1,736,473 |  |  | 1,226,963 |
Other Expense (Income) |  |  |  |  |
Other Expense (Income) | 23,584 |  |  | 2,862 |  |  | (14,571) |
Gain on Asset Sales and Abandonments, net | (21,224) |  |  | (35,563) |  |  | (157,015) |
Gain on Previously Held Equity Interest | — |  |  | — |  |  | (623,663) |
(Gain) Loss on Debt Extinguishment | (10,101) |  |  | 7,614 |  |  | 54,118 |
Interest Expense | 170,806 |  |  | 151,379 |  |  | 145,934 |
Total Other Expense (Income) | 163,065 |  |  | 126,292 |  |  | (595,197) |
Total Costs and Expenses | 1,860,809 |  |  | 1,862,765 |  |  | 631,766 |
(Loss) Earnings Before Income Tax | (602,831) |  |  | 59,684 |  |  | 1,098,668 |
Income Tax (Benefit) Expense | (174,087) |  |  | 27,736 |  |  | 215,557 |
Net (Loss) Income | (428,744) |  |  | 31,948 |  |  | 883,111 |
Less: Net Income Attributable to Noncontrolling Interests | 55,031 |  |  | 112,678 |  |  | 86,578 |
Net (Loss) Income Attributable to CNX Resources Shareholders | $ | (483,775) |  |  | $ | (80,730) |  |  | $ | 796,533 |
(Loss) Earnings Per Share |  |  |  |  |
Basic | $ | (2.43) |  |  | $ | (0.42) |  |  | $ | 3.75 |
Diluted | $ | (2.43) |  |  | $ | (0.42) |  |  | $ | 3.71 |
Dividends Declared Per Share | $ | — |  |  | $ | — |  |  | $ | — |

The accompanying notes are an integral part of these financial statements.
82

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Net (Loss) Income | $ | (428,744) |  |  | $ | 31,948 |  |  | $ | 883,111 |
Other Comprehensive (Loss) Income: |  |  |  |  |
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $914, $1,664, $(792)) | (2,579) |  |  | (4,701) |  |  | 1,672 |
Comprehensive (Loss) Income | (431,323) |  |  | 27,247 |  |  | 884,783 |
Less: Comprehensive Income Attributable to Noncontrolling Interests | 55,031 |  |  | 112,678 |  |  | 86,578 |
Comprehensive (Loss) Income Attributable to CNX Resources Shareholders | $ | (486,354) |  |  | $ | (85,431) |  |  | $ | 798,205 |

The accompanying notes are an integral part of these financial statements.
83

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

| December 31, 2020 |  | December 31, 2019
ASSETS |  |  |
Current Assets: |  |  |
Cash and Cash Equivalents | $ | 15,617 |  |  | $ | 16,283 |
Restricted Cash | 735 |  |  | — |
Accounts and Notes Receivable: |  |  |
Trade (Note 17) | 145,929 |  |  | 133,480 |
Other Receivables | 4,238 |  |  | 13,679 |
Supplies Inventories | 9,657 |  |  | 6,984 |
Recoverable Income Taxes (Note 6) | 88 |  |  | 62,425 |
Derivative Instruments (Note 19) | 84,657 |  |  | 247,794 |
Prepaid Expenses | 12,411 |  |  | 17,456 |
Total Current Assets | 273,332 |  |  | 498,101 |
Property, Plant and Equipment (Note 8): |  |  |
Property, Plant and Equipment | 10,963,996 |  |  | 10,572,006 |
Less—Accumulated Depreciation, Depletion and Amortization | 3,938,451 |  |  | 3,435,431 |
Total Property, Plant and Equipment—Net | 7,025,545 |  |  | 7,136,575 |
Other Assets: |  |  |
Operating Lease Right-of-Use Assets (Note 13) | 108,683 |  |  | 187,097 |
Investment in Affiliates | 16,022 |  |  | 16,710 |
Derivative Instruments (Note 19) | 188,237 |  |  | 314,096 |
Goodwill (Note 9) | 323,314 |  |  | 796,359 |
Other Intangible Assets (Note 9) | 90,095 |  |  | 96,647 |
Restricted Cash | 5,247 |  |  | — |
Other | 11,289 |  |  | 15,221 |
Total Other Assets | 742,887 |  |  | 1,426,130 |
TOTAL ASSETS | $ | 8,041,764 |  |  | $ | 9,060,806 |

The accompanying notes are an integral part of these financial statements.
84

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share data)

| December 31, 2020 |  | December 31, 2019
LIABILITIES AND EQUITY |  |  |
Current Liabilities: |  |  |
Accounts Payable | $ | 118,185 |  |  | $ | 202,553 |
Derivative Instruments (Note 19) | 42,329 |  |  | 41,466 |
Current Portion of Finance Lease Obligations (Note 13) | 6,876 |  |  | 7,164 |
Current Portion of Long-Term Debt (Note 12) | 22,574 |  |  | — |
Current Portion of Operating Lease Obligations (Note 13) | 52,575 |  |  | 61,670 |
Other Accrued Liabilities (Note 11) | 198,773 |  |  | 216,086 |
Total Current Liabilities | 441,312 |  |  | 528,939 |
Non-Current Liabilities: |  |  |
Long-Term Debt (Note 12) | 2,401,427 |  |  | 2,754,443 |
Finance Lease Obligations (Note 13) | 1,057 |  |  | 7,706 |
Operating Lease Obligations (Note 13) | 53,235 |  |  | 110,466 |
Derivative Instruments (Note 19) | 127,290 |  |  | 115,862 |
Deferred Income Taxes (Note 6) | 466,253 |  |  | 476,108 |
Asset Retirement Obligations (Note 7) | 84,712 |  |  | 63,377 |
Other | 44,041 |  |  | 41,596 |
Total Non-Current Liabilities | 3,178,015 |  |  | 3,569,558 |
TOTAL LIABILITIES | 3,619,327 |  |  | 4,098,497 |
Stockholders’ Equity: |  |  |
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 220,440,993 Issued and Outstanding at December 31, 2020; 186,642,962 Issued and Outstanding at December 31, 2019 | 2,208 |  |  | 1,870 |
Capital in Excess of Par Value | 2,959,357 |  |  | 2,199,605 |
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding | — |  |  | — |
Retained Earnings | 1,476,056 |  |  | 1,971,676 |
Accumulated Other Comprehensive Loss | (15,184) |  |  | (12,605) |
Total CNX Resources Stockholders’ Equity | 4,422,437 |  |  | 4,160,546 |
Noncontrolling Interest | — |  |  | 801,763 |
TOTAL STOCKHOLDERS' EQUITY | 4,422,437 |  |  | 4,962,309 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 8,041,764 |  |  | $ | 9,060,806 |

The accompanying notes are an integral part of these financial statements.
85

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Dollars in thousands)

| Common Stock |  | Capital in Excess of Par Value |  | Retained Earnings (Deficit) |  | Accumulated Other Comprehensive Income (Loss) |  | Total CNX Resources Stockholders’ Equity |  | Non- Controlling Interest |  | Total Equity
December 31, 2017 | $ | 2,241 |  |  | $ | 2,450,323 |  |  | $ | 1,455,811 |  |  | $ | (8,476) |  |  | $ | 3,899,899 |  |  | $ | — |  |  | $ | 3,899,899 |
Net Income | — |  |  | — |  |  | 796,533 |  |  | — |  |  | 796,533 |  |  | 86,578 |  |  | 883,111 |
Issuance of Common Stock | 8 |  |  | 1,705 |  |  | — |  |  | — |  |  | 1,713 |  |  | — |  |  | 1,713 |
Purchase and Retirement of Common Stock | (259) |  |  | (206,895) |  |  | (176,598) |  |  | — |  |  | (383,752) |  |  | — |  |  | (383,752) |
Shares Withheld for Taxes | — |  |  | — |  |  | (5,037) |  |  | — |  |  | (5,037) |  |  | (348) |  |  | (5,385) |
Amortization of Stock-Based Compensation Awards | — |  |  | 18,930 |  |  | — |  |  | — |  |  | 18,930 |  |  | 2,411 |  |  | 21,341 |
Other Comprehensive Income | — |  |  | — |  |  | — |  |  | 1,672 |  |  | 1,672 |  |  | — |  |  | 1,672 |
ASU 2018-02 Reclassification | — |  |  | — |  |  | 1,100 |  |  | (1,100) |  |  | — |  |  | — |  |  | — |
Distributions to CNXM Noncontrolling Interest Holders | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (55,433) |  |  | (55,433) |
Acquisition of CNX Gathering, LLC | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 718,577 |  |  | 718,577 |
December 31, 2018 | $ | 1,990 |  |  | $ | 2,264,063 |  |  | $ | 2,071,809 |  |  | $ | (7,904) |  |  | $ | 4,329,958 |  |  | $ | 751,785 |  |  | $ | 5,081,743 |
December 31, 2018 | $ | 1,990 |  |  | $ | 2,264,063 |  |  | $ | 2,071,809 |  |  | $ | (7,904) |  |  | $ | 4,329,958 |  |  | $ | 751,785 |  |  | $ | 5,081,743 |
Net (Loss) Income | — |  |  | — |  |  | (80,730) |  |  | — |  |  | (80,730) |  |  | 112,678 |  |  | 31,948 |
Issuance of Common Stock | 9 |  |  | 556 |  |  | — |  |  | — |  |  | 565 |  |  | — |  |  | 565 |
Purchase and Retirement of Common Stock | (129) |  |  | (101,559) |  |  | (13,789) |  |  | — |  |  | (115,477) |  |  | — |  |  | (115,477) |
Shares Withheld for Taxes | — |  |  | — |  |  | (5,614) |  |  | — |  |  | (5,614) |  |  | (696) |  |  | (6,310) |
Amortization of Stock-Based Compensation Awards | — |  |  | 36,545 |  |  | — |  |  | — |  |  | 36,545 |  |  | 1,880 |  |  | 38,425 |
Other Comprehensive Loss | — |  |  | — |  |  | — |  |  | (4,701) |  |  | (4,701) |  |  | — |  |  | (4,701) |
Distributions to CNXM Noncontrolling Interest Holders | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (63,884) |  |  | (63,884) |
December 31, 2019 | $ | 1,870 |  |  | $ | 2,199,605 |  |  | $ | 1,971,676 |  |  | $ | (12,605) |  |  | $ | 4,160,546 |  |  | $ | 801,763 |  |  | $ | 4,962,309 |
December 31, 2019 | $ | 1,870 |  |  | $ | 2,199,605 |  |  | $ | 1,971,676 |  |  | $ | (12,605) |  |  | $ | 4,160,546 |  |  | $ | 801,763 |  |  | $ | 4,962,309 |
Net (Loss) Income | — |  |  | — |  |  | (483,775) |  |  | — |  |  | (483,775) |  |  | 55,031 |  |  | (428,744) |
Issuance of Common Stock | 8 |  |  | 2,049 |  |  | — |  |  | — |  |  | 2,057 |  |  | — |  |  | 2,057 |
Purchase and Retirement of Common Stock | (41) |  |  | (33,067) |  |  | (10,139) |  |  | — |  |  | (43,247) |  |  | — |  |  | (43,247) |
Shares Withheld for Taxes | — |  |  | — |  |  | (1,706) |  |  | — |  |  | (1,706) |  |  | (309) |  |  | (2,015) |
Amortization of Stock-Based Compensation Awards | — |  |  | 12,897 |  |  | — |  |  | — |  |  | 12,897 |  |  | 1,485 |  |  | 14,382 |
Equity Component of Convertible Senior Notes, net of Issuance Costs | — |  |  | 78,317 |  |  | — |  |  | — |  |  | 78,317 |  |  | — |  |  | 78,317 |
Purchase of Capped Call | — |  |  | (26,351) |  |  | — |  |  | — |  |  | (26,351) |  |  | — |  |  | (26,351) |
Other Comprehensive Loss | — |  |  | — |  |  | — |  |  | (2,579) |  |  | (2,579) |  |  | — |  |  | (2,579) |
Distributions to CNXM Noncontrolling Interest Holders | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (41,987) |  |  | (41,987) |
CNXM Merger | 371 |  |  | 725,907 |  |  | — |  |  | — |  |  | 726,278 |  |  | (815,983) |  |  | (89,705) |
December 31, 2020 | $ | 2,208 |  |  | $ | 2,959,357 |  |  | $ | 1,476,056 |  |  | $ | (15,184) |  |  | $ | 4,422,437 |  |  | $ | — |  |  | $ | 4,422,437 |

The accompanying notes are an integral part of these financial statements.
86

CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands) | For the Years Ended December 31,
Cash Flows from Operating Activities: | 2020 |  | 2019 |  | 2018
Net (Loss) Income | $ | (428,744) |  |  | $ | 31,948 |  |  | $ | 883,111 |
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Continuing Operating Activities: |  |  |  |  |
Depreciation, Depletion and Amortization | 501,821 |  |  | 508,463 |  |  | 493,423 |
Amortization of Deferred Financing Costs | 21,202 |  |  | 7,747 |  |  | 8,361 |
Impairment of Exploration and Production Properties | 61,849 |  |  | 327,400 |  |  | — |
Impairment of Unproved Properties and Expirations | — |  |  | 119,429 |  |  | — |
Impairment of Goodwill | 473,045 |  |  | — |  |  | — |
Impairment of Other Intangible Assets | — |  |  | — |  |  | 18,650 |
Stock-Based Compensation | 14,382 |  |  | 38,425 |  |  | 21,341 |
Gain on Asset Sales and Abandonments, net | (21,224) |  |  | (35,563) |  |  | (157,015) |
Gain on Previously Held Equity Interest | — |  |  | — |  |  | (623,663) |
(Gain) Loss on Debt Extinguishment | (10,101) |  |  | 7,614 |  |  | 54,118 |
(Gain) Loss on Commodity Derivative Instruments | (172,982) |  |  | (376,105) |  |  | 30,212 |
Loss on Other Derivative Instruments | 13,051 |  |  | — |  |  | — |
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments | 461,217 |  |  | 69,780 |  |  | (69,720) |
Deferred Income Taxes | (118,300) |  |  | 79,092 |  |  | 345,560 |
Equity in Loss (Earnings) of Affiliates | 688 |  |  | (2,103) |  |  | (5,363) |
Return on Equity Investment | — |  |  | 4,056 |  |  | — |
Changes in Operating Assets: |  |  |  |  |
Accounts and Notes Receivable | (4,895) |  |  | 118,622 |  |  | (57,734) |
Supplies Inventories | (2,673) |  |  | 2,731 |  |  | 1,027 |
Recoverable Income Taxes | 62,336 |  |  | 87,050 |  |  | (118,498) |
Prepaid Expenses | 4,923 |  |  | 3,115 |  |  | (1,391) |
Changes in Other Assets | (39) |  |  | 1,000 |  |  | 4,904 |
Changes in Operating Liabilities: |  |  |  |  |
Accounts Payable | (48,485) |  |  | (6,405) |  |  | 12,760 |
Accrued Interest | (4,314) |  |  | 4,529 |  |  | (5,839) |
Other Operating Liabilities | (6,453) |  |  | 13,242 |  |  | 53,135 |
Changes in Other Liabilities | (1,233) |  |  | (23,507) |  |  | (1,556) |
Net Cash Provided by Operating Activities | 795,071 |  |  | 980,560 |  |  | 885,823 |
Cash Flows from Investing Activities: |  |  |  |  |
Capital Expenditures | (487,291) |  |  | (1,192,599) |  |  | (1,116,397) |
CNX Gathering LLC Acquisition, Net of Cash Acquired | — |  |  | — |  |  | (299,272) |
Proceeds from Asset Sales | 48,322 |  |  | 45,160 |  |  | 511,767 |
Net Distributions from Equity Affiliates | — |  |  | — |  |  | 9,250 |
Net Cash Used in Investing Activities | (438,969) |  |  | (1,147,439) |  |  | (894,652) |
Cash Flows from Financing Activities: |  |  |  |  |
Net (Payments on) Proceeds from CNX Revolving Credit Facility | (500,200) |  |  | 49,000 |  |  | 612,000 |
Payments on Miscellaneous Borrowings | (7,155) |  |  | (7,149) |  |  | (7,165) |
Payments on Long-Term Notes | (882,213) |  |  | (405,876) |  |  | (955,019) |
Proceeds from Issuance of CNX Senior Notes | 707,000 |  |  | 500,000 |  |  | — |
Proceeds from Issuance of CNXM Senior Notes | — |  |  | — |  |  | 394,000 |
Net Proceeds from CSG Non-Revolving Credit Facilities | 158,794 |  |  | — |  |  | — |
Proceeds from Issuance of Convertible Senior Notes | 334,650 |  |  | — |  |  | — |
Purchase of Capped Call Related to Convertible Senior Notes | (35,673) |  |  | — |  |  | — |
Net (Payments on) Proceeds from CNXM Revolving Credit Facility | (20,750) |  |  | 227,750 |  |  | (65,500) |
Distributions to CNXM Noncontrolling Interest Holders | (41,987) |  |  | (63,884) |  |  | (55,433) |
Proceeds from Issuance of Common Stock | 2,057 |  |  | 565 |  |  | 1,713 |
Shares Withheld for Taxes | (2,015) |  |  | (6,310) |  |  | (5,385) |
Purchases of Common Stock | (37,247) |  |  | (117,477) |  |  | (381,752) |
Debt Issuance and Financing Fees | (26,047) |  |  | (10,655) |  |  | (20,599) |
Net Cash (Used in) Provided by Financing Activities | (350,786) |  |  | 165,964 |  |  | (483,140) |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 5,316 |  |  | (915) |  |  | (491,969) |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 16,283 |  |  | 17,198 |  |  | 509,167 |
Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 21,599 |  |  | $ | 16,283 |  |  | $ | 17,198 |

The accompanying notes are an integral part of these financial statements.
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CNX RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:
A summary of the significant accounting policies of CNX Resources Corporation and subsidiaries ("CNX" or "the Company") is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.
Basis of Consolidation:
The Consolidated Financial Statements include the accounts of CNX Resources Corporation, its wholly-owned subsidiaries, and its majority-owned and/or controlled subsidiaries. Investments in business entities in which CNX does not have control but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate consolidation method.
Prior to the Merger on September 28, 2020, see Note 4 - Acquisitions and Dispositions, certain variable interest entities were required to be consolidated pursuant to the Consolidation topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. The portion of these entities that was not owned by the Company was presented as non-controlling interest.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates included in, but not limited to, the preparation of the consolidated financial statements are related to long-lived assets (including intangible assets and goodwill), accounts receivable credit losses, the values of natural gas, NGLs, condensate and oil (collectively "natural gas") reserves, asset retirement obligations, deferred income tax assets and liabilities, contingencies, fair value of derivative instruments, the fair value of the liability and equity components of the convertible senior notes, stock-based compensation and salary retirement benefits.
Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Restricted cash consists of cash that the Company is contractually obligated to maintain in accordance with the terms of the Cardinal States Gathering LLC and CSG Holdings II LLC Credit Agreements, each dated March 13, 2020 (See Note 12 - Long-Term Debt for more information).
The following table provides a reconciliation of cash, cash equivalents, and restricted cash to amounts shown in the statement of cash flows:

| December 31,
| 2020 |  | 2019 |  | 2018
Cash and Cash Equivalents | $ | 15,617 |  |  | $ | 16,283 |  |  | $ | 17,198 |
Restricted Cash, Current Portion | 735 |  |  | — |  |  | — |
Restricted Cash, Less Current Portion | 5,247 |  |  | — |  |  | — |
Total Cash, Cash Equivalents and Restricted Cash | $ | 21,599 |  |  | $ | 16,283 |  |  | $ | 17,198 |

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Trade Accounts Receivable and Allowance for Credit Losses:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest.
On January 1, 2020, CNX adopted Accounting Standards Update (ASU) 2016-13 Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. CNX adopted Topic 326 using the prospective transition method.
Prior to adopting Topic 326, CNX reserved for specific accounts receivable when it was probable that all or a part of an outstanding balance would not be collected, such as customer bankruptcies. Collectability was determined based on terms of sale, credit status of customers and various other circumstances. CNX regularly reviewed collectability and established or adjusted the allowance as necessary using the specific identification method. Account balances were charged off against the allowance after all means of collection had been exhausted and the potential for recovery was considered remote. Reserves for uncollectible amounts were not material in the periods presented.
Under Topic 326, management records an allowance for credit losses related to the collectability of third-party customers' receivables using the historical aging of the customer receivable balance. The collectability is determined based on past events, including historical experience, customer credit rating, as well as current market conditions. CNX monitors customer ratings and collectability on an on-going basis. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.
There were no material financing receivables with a contractual maturity greater than one year at December 31, 2020 or 2019.
As of December 31, 2020 and 2019, Accounts Receivable - Trade were $145,929 and $133,480, respectively, and Other Receivables were $4,238 and $13,679, respectively.
The following represents the roll forward of the allowance for credit losses for the years ended:

| December 31,
| 2020 |  | 2019
Allowance for Credit Losses - Trade, Beginning of Year | $ | — |  |  | $ | — |
Provision for Expected Credit Losses | 84 |  |  | — |
Allowance for Credit Losses - Trade, End of Period | $ | 84 |  |  | $ | — |
Allowance for Credit Losses - Other Receivables, Beginning of Year | $ | 2,463 |  |  | $ | 2,038 |
Provision for Expected Credit Losses | 2,760 |  |  | 595 |
Write-off of Uncollectible Accounts | (1,975) |  |  | (170) |
Allowance for Credit Losses - Other Receivables, End of Period | $ | 3,248 |  |  | $ | 2,463 |

Inventories:
Inventories are stated at the lower of cost or net realizable value. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's operations.
Property, Plant and Equipment:
CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral
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interests are amortized using the units-of-production method. Depreciation, depletion and amortization expense is calculated based on the actual produced sales volumes multiplied by the applicable rate per unit, which is derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Proved developed reserves, as estimated by petroleum engineers, are used to calculate amortization of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by petroleum engineers, are used to calculate depletion on property acquisitions. Proved oil and natural gas reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates. The Company recorded depreciation, depletion and amortization expense related to proved gas properties using the units-of-production method of $400,758, $423,488, and $412,588 for the years ended December 31, 2020, 2019, and 2018, respectively.
Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.
Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows:

|  | Years
Buildings and Improvements |  | 10 to 45
Machinery and Equipment |  | 3 to 25
Gathering and Transmission |  | 30 to 40
Leasehold Improvements |  | Life of Lease

Costs for purchased software are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed seven years.
Impairment of Long-Lived Assets:
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present, and the estimated fair value of the investment is less than the assets' carrying value.
Impairment of Proved Properties:
CNX performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, tests require that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. 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 significant assumptions including projected revenues, future commodity prices and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions.
During the year ended December 31, 2020, CNX recognized certain indicators of impairments specific to our Southwest Pennsylvania Coalbed Methane 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 using level 3 inputs which consisted of 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 $61,849 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 wells and the related processing facility during the first quarter.
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During the fourth quarter of 2019, CNX identified certain indicators of impairment specific to our Central Pennsylvania Marcellus 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 using level 3 inputs which consisted of 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 $327,400 was 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 Central Pennsylvania 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:
Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. 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 expense 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 impairment related to unproved properties of $119,429 that was included in Impairment of Unproved Properties and Expirations in the Consolidated Statements of Income. These unproved properties are within CNX's Central Pennsylvania operating region and east of the acreage associated with the proved property impairment described above.
Exploration expense, which is associated primarily with lease expirations, was $14,994, $44,380 and $12,033 for the years ended December 31, 2020, 2019 and 2018, respectively, and is included in Exploration and Production Related Other Costs in the Consolidated Statements of Income.
Impairment of Goodwill:
In connection with the Midstream Acquisition (See Note 4 - Acquisitions and Dispositions for more information), CNX recorded $796,359 of goodwill through the application of purchase accounting. The goodwill recorded was allocated in its entirety to the Midstream reporting unit within the Shale segment.
Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is not amortized, but rather it is evaluated 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. These indicators include, but are not limited to, overall financial performance, industry and market considerations, anticipated future cash flows and discount rates, changes in the stock price with regards to CNX, regulatory and legal developments, and other relevant factors.
In connection with the annual evaluation of goodwill for impairment or earlier if an impairment indicator is identified, CNX may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. If after assessing such factors or circumstances, CNX determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. If CNX chooses to bypass the qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then CNX will perform a quantitative assessment. In the case of a quantitative assessment, CNX estimates the fair value of the reporting unit with which the goodwill is associated using level 3 inputs and compares it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. The Company uses a combination of the income approach (generally a discounted cash flow method) and market approach (which may include the guideline public company method and/or the guideline transaction method) to estimate the fair value of a reporting unit.
The income approach is used to estimate value based on the present value of future economic benefits that are expected to be produced by an asset or business entity. This approach generally involves two general steps:
(i) The first step involves establishing a forecast of the estimated future net cash flows expected to accrue directly or indirectly to the owner of the asset over its remaining useful life or to the owner of the business entity (including a
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reporting unit).
(ii) The second step involves discounting these estimated future net cash flows to their present value using a market rate of return.
CNX determined the fair value based on estimated future revenues and earnings before deducting net interest expense (interest expense less interest income) and income taxes (EBITDA - a non-GAAP financial measure), and also included estimates for capital expenditures, discounted to present value using an industry rate adjusted for company-specific risk, which management feels reflects the overall level of inherent risk of the reporting unit. These assumptions are affected by expectations about future market, industry and economic conditions. Cash flow projections were derived from board approved budgeted amounts, a seven-year operating forecast and an estimate of future cash flows. Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur.
The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from business risks as described in Item 1A. Risk Factors of this Form 10-K. 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. Although CNX believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the estimated fair value. Future results could differ from our current estimates and assumptions.
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 master limited partnership (MLP) market space, an impairment indicator was identified. 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 $473,045 was included in Impairment of Goodwill in the Consolidated Statements of Income.
In connection with our annual assessment of goodwill in the fourth quarter of 2020, we 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, we concluded that the estimated fair value exceeded carrying value, and accordingly no adjustment to goodwill was necessary. However, the margin by which the fair value of the Midstream reporting unit exceeded its carrying value was less than 10%. As a result, this reporting unit is susceptible to impairment risk from further adverse macroeconomic conditions or other adverse factors such as future gathering volumes being less than those currently estimated. Any such adverse changes in the future could reduce the underlying cash flows used to estimate fair values and could result in a decline in fair value that could trigger future impairment charges relating to the Midstream reporting unit.
Impairment of Definite-Lived Intangible Assets:
Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed for impairment when indicators of impairment are present.
In connection with the Midstream Acquisition (See Note 4 - Acquisitions and Dispositions for more information), CNX recorded $128,781 of other intangible assets, which are comprised of customer relationships, through the application of purchase accounting.
In May 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were acquired in connection with the Midstream acquisition exceeded their fair value in conjunction with the Asset Exchange Agreement with HG Energy II Appalachia, LLC (See Note 4 - Acquisitions and Dispositions for more information). CNX recognized an impairment on this intangible asset of $18,650, which is included in Impairment of Other Intangible Assets in the Consolidated Statements of Income.
The customer relationships intangible asset is amortized on a straight-line basis over approximately 17 years.
Income Taxes:
Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or
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payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of the Company's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.
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 do not meet the more likely than not to be sustained criteria, the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate settlement. 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 the Company believes 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 position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.
Asset Retirement Obligations:
CNX accrues for dismantling and removing costs of gas-related facilities and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income.
Investment Plan:
CNX has an investment plan that is available to most employees. Throughout the years ended December 31, 2020, 2019 and 2018, the Company's matching contribution was 6% of eligible compensation contributed by eligible employees. The Company may also make discretionary contributions to the Plan ranging from 1% to 6% of eligible compensation for eligible employees (as defined by the Plan). There were no such discretionary contributions made by CNX for the years ended December 31, 2020, 2019 and 2018. Total matching contribution payments and costs were $2,976, $3,460 and $3,205 for the years ended December 31, 2020, 2019 and 2018, respectively.
Revenue Recognition:
Revenues are recognized when the recognition criteria of ASC 606 are met, which generally occurs at the point in which title passes to the customers. For natural gas, NGL and oil revenue, this occurs at the contractual point of delivery. For revenues generated from natural gas gathering services provided to third-parties, this occurs when obligations under the terms of the contract with the shipper are satisfied.
CNX sells natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within the Consolidated Statements of Income in the Purchased Gas Revenue line.
CNX purchases natural gas produced by third-parties at market prices less a fee. The gas purchased from third-parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Revenue and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX from the third-party.
Contingencies:
From time to time, CNX, or its subsidiaries, are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes and other claims and actions, arising out of the normal course of
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business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
Stock-Based Compensation:
Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CNX recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 15 - Stock-Based Compensation for more information.
Derivative Instruments:
CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The change in fair value of the interest rate swap agreements are accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings.
CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. Natural gas commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings.
None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if CNX's obligations with any of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would be required to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with the counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis, generally measured based upon Level 2 inputs, which is further described in Note 18 - Fair Value of Financial Instruments.
Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions.
CNX is exposed to credit risk in the event of non-performance by counterparties, whose creditworthiness is subject to continuing review. Historically, CNX has not experienced any issues of non-performance by derivative counterparties.
Recent Accounting Pronouncements:
In August 2020, the FASB issued Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This ASU simplifies an entity's accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, simplifies the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification, requires entities to use the if-converted method for all convertible instruments in the diluted EPS calculation and include the effect of potential share settlement (if the effect is more dilutive) for instruments that may be settled in cash or shares, except for certain liability-classified share-based payment awards, requires new disclosures about events that occur during the reporting period and cause conversion contingencies to be met and about the fair value of an entity's convertible debt at the instrument level, among other things. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years, and can be adopted through either a modified retrospective method of transition or a fully retrospective method of transition. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. The Company is still evaluating the effect of adopting this guidance.
In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (Topic 848). This ASU provides optional expedient and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. In response to the concerns about structural risks of interbank offered rates (IBORs) and, particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR), regulators in several jurisdictions around the world have undertaken reference rate reform initiatives to identify alternative reference rates that are more observable or transaction based
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and less susceptible to manipulation. The ASU provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates that are expected to be discontinued. In January 2021, the FASB issued ASU 2021-01, which clarifies that certain provisions in Topic 848, if elected by an entity, apply to derivative instruments that use an interest rate for margining, discounting, or contract price alignment that is modified as a result of reference rate reform. The amendments in these ASUs are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is still evaluating the effect of adopting this guidance.
In March 2020, the FASB issued ASU 2020-03 - Codification Improvements to Financial Instruments. This ASU improves and clarifies various financial instruments topics, including the CECL standard. The ASU includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments in this ASU have different effective dates. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.
Reclassifications:
Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2020, with no effect on previously reported net income, stockholders' equity, or statement of cash flows.
Subsequent Events:
The Company has evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.
NOTE 2—EARNINGS PER SHARE:
Basic earnings per share is computed by dividing net income attributable to CNX shareholders by the weighted average shares outstanding during the reporting period. Diluted earnings per share is computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include, if dilutive, additional shares from stock options, performance stock options, restricted stock units, performance share units and shares issuable upon conversion of CNX's outstanding Convertible Notes (See Note 12 - Long-Term Debt). The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted stock units and performance share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period.
Pursuant to the Merger (See Note 4 - Acquisitions and Dispositions for more information), all outstanding phantom units previously granted under the CNXM long-term incentive plan were converted into the right to receive 0.88 shares of common stock of CNX. As such, all outstanding phantom units were converted, effective as of the closing of the Merger, into CNX restricted stock units. Each CNX restricted stock unit will be subject to the same vesting, forfeiture and other terms and conditions applicable to the converted CNXM phantom units. Under Accounting Standards Codification Topic 718, Compensation - Stock Compensation, it was determined that there was no additional compensation cost to record as the conversion of awards did not result in incremental fair value. CNXM's dilutive units did not have a material impact on the Company's earnings per share calculations for the period from January 1, 2020 through September 30, 2020, the year ended December 31, 2019, or the period from January 3, 2018 through December 31, 2018.
The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per share because their effect would be antidilutive:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Anti-Dilutive Options | 4,200,509 |  |  | 4,696,264 |  |  | 2,285,775 |
Anti-Dilutive Restricted Stock Units | 2,160,727 |  |  | 1,282,582 |  |  | — |
Anti-Dilutive Performance Share Units | 721,244 |  |  | 752,899 |  |  | 145,217 |
Anti-Dilutive Performance Share Options | — |  |  | 927,268 |  |  | 927,268 |
| 7,082,480 |  |  | 7,659,013 |  |  | 3,358,260 |

The Company expects to settle the principal amount of the Convertible Notes in cash. As a result, only the amount by which the conversion value exceeds the aggregated principal amount of the Convertible Notes is included in the diluted
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earnings per share computation under the treasury stock method. The conversion spread has a dilutive impact on diluted earnings per share when the average market price of the Company’s common stock for a given period exceeds the initial conversion price of $12.84 per share for the Convertible Notes. As of December 31, 2020, the if-converted value of the Convertible Notes did not exceed the outstanding principal amount. In connection with the Convertible Notes’ issuance, the Company entered into privately negotiated capped call transactions with certain counterparties, (the “Capped Calls” and “Capped Call Transactions”), which were not included in calculating the number of diluted shares outstanding, as their effect would have been anti-dilutive.
The computations for basic and diluted (loss) earnings per share are as follows:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Net (Loss) Income | $ | (428,744) |  |  | $ | 31,948 |  |  | $ | 883,111 |
Less: Net Income Attributable to Non-Controlling Interest | 55,031 |  |  | 112,678 |  |  | 86,578 |
Net (Loss) Income Attributable to CNX Resources Shareholders | $ | (483,775) |  |  | $ | (80,730) |  |  | $ | 796,533 |
Weighted-Average Shares of Common Stock Outstanding | 199,225,441 |  |  | 190,727,122 |  |  | 212,348,581 |
Effect of Diluted Shares* | — |  |  | — |  |  | 2,280,384 |
Weighted-Average Diluted Shares of Common Stock Outstanding | 199,225,441 |  |  | 190,727,122 |  |  | 214,628,965 |
(Loss) Earnings Per Share: |  |  |  |  |
Basic | $ | (2.43) |  |  | $ | (0.42) |  |  | $ | 3.75 |
Diluted | $ | (2.43) |  |  | $ | (0.42) |  |  | $ | 3.71 |

*During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive.
Shares of common stock outstanding were as follows:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Balance, Beginning of Year | 186,642,962 |  |  | 198,663,342 |  |  | 223,743,322 |
Issuance Related to Stock-Based Compensation (1) | 882,335 |  |  | 909,107 |  |  | 814,344 |
Retirement of Common Stock (2) | (4,138,527) |  |  | (12,929,487) |  |  | (25,894,324) |
Issuance Related to CNXM Merger | 37,054,223 |  |  | — |  |  | — |
Balance, End of Year | 220,440,993 |  |  | 186,642,962 |  |  | 198,663,342 |

(1) See Note 15 - Stock-Based Compensation for additional information.
(2) See Note 5 - Stock Repurchase for additional information.
NOTE 3—REVENUE FROM CONTRACTS WITH CUSTOMERS:
Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to exclude all taxes from the measurement of transaction price.
For natural gas, NGL and oil, and purchased gas revenue, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company’s efforts to satisfy the performance obligations. A portion of the contracts contain fixed consideration (i.e. fixed price contracts or contracts with a fixed differential to NYMEX or index prices). The fixed consideration is allocated to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price. Revenue associated with natural gas, NGL and oil as presented on the accompanying Consolidated Statements of Income represent the Company’s share of revenues net of royalties and
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excluding revenue interests owned by others. When selling natural gas, NGL and oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.
Included in Other Revenue and Operating Income in the Consolidated Statements of Income and in the below table are revenues generated from natural gas gathering services provided to third-parties. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric based fees are based on actual volumes gathered. The Company generally considers the interruptible gathering of each unit (MMBtu) of natural gas as a separate performance obligation. Payment terms for these contracts typically require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered.
Disaggregation of Revenue
The following table is a disaggregation of revenue by major source:

| For the Years Ended December 31,
2020 |  | 2019 |  | 2018
Revenue from Contracts with Customers: |  |  |  |  |
Natural Gas Revenue | $ | 823,132 |  |  | $ | 1,251,013 |  |  | $ | 1,391,459 |
NGL Revenue | 64,138 |  |  | 104,139 |  |  | 165,883 |
Oil/Condensate Revenue | 9,475 |  |  | 9,173 |  |  | 20,595 |
Total Natural Gas, NGL and Oil Revenue | 896,745 |  |  | 1,364,325 |  |  | 1,577,937 |
Purchased Gas Revenue | 105,792 |  |  | 94,027 |  |  | 65,986 |
Other Sources of Revenue and Other Operating Income: |  |  |  |  |
Gain (Loss) on Commodity Derivative Instruments | 172,982 |  |  | 376,105 |  |  | (30,212) |
Other Revenue and Operating Income | 82,459 |  |  | 87,992 |  |  | 116,723 |
Total Revenue and Other Operating Income | $ | 1,257,978 |  |  | $ | 1,922,449 |  |  | $ | 1,730,434 |

The disaggregated revenue information corresponds with the Company’s segment reporting found in Note 21 - Segment Information.
Contract Balances
CNX invoices its customers once a performance obligation has been satisfied, at which point payment is unconditional. Accordingly, CNX's contracts with customers do not give rise to contract assets or liabilities under ASC 606. The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer. The opening and closing balances of the Company’s receivables related to contracts with customers were $133,480 and $145,929, respectively, as of December 31, 2020.
Transaction Price Allocated to Remaining Performance Obligations
ASC 606 requires that the Company disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement, including when variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a series.
A significant portion of CNX's natural gas, NGL and oil and purchased gas revenue is short-term in nature with a contract term of one year or less. For those contracts, CNX has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For revenue associated with contract terms greater than one year, a significant portion of the consideration in those contracts is variable in nature and the Company allocates the variable consideration in its contract entirely to each specific performance obligation to which it relates. Therefore, any remaining variable consideration in the transaction price is allocated
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entirely to wholly unsatisfied performance obligations. As such, the Company has not disclosed the value of unsatisfied performance obligations pursuant to the practical expedient.
For revenue associated with contract terms greater than one year with a fixed price component, the aggregate amount of the transaction price allocated to remaining performance obligations was $120,275 as of December 31, 2020. The Company expects to recognize net revenue of $55,500 in the next 12 months and $37,151 over the following 12 months, with the remainder recognized thereafter.
For revenue associated with CNX's midstream contracts, which also have terms greater than one year, the interruptible gathering of each unit of natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior-Period Performance Obligations
CNX records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas, NGL and oil revenue may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. CNX records the differences between the estimate and the actual amounts received in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and the related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For each of the years ended December 31, 2020, 2019, and 2018, revenue recognized in the current reporting period related to performance obligations satisfied in prior a reporting period was not material.
NOTE 4—ACQUISITIONS AND DISPOSITIONS:
On July 26, 2020, CNX entered into an Agreement and Plan of Merger (the “Merger Agreement”) with CNXM, CNX Midstream GP LLC (the “General Partner”) and CNX Resources Holding LLC., a wholly owned subsidiary of CNX (“Merger Sub”), pursuant to which Merger Sub merged with and into CNXM with CNXM surviving as an indirect wholly owned subsidiary of CNX (the “Merger”). On September 28, 2020, the Merger was completed and CNX issued 37,054,223 shares of common stock to acquire the 42,107,071 common units of CNXM not owned by CNX prior to the Merger at a fixed exchange ratio of 0.88 shares of CNX common stock for each CNXM common unit, for total implied consideration of $384,623. As a result of the Merger, CNXM’s common units are no longer publicly traded.
Except for the Class B units of CNXM, which were automatically canceled immediately prior to the effective time of the Merger for no consideration in accordance with CNXM’s partnership agreement, the interests in CNXM owned by CNX and its subsidiaries remain outstanding as limited partner interests in the surviving entity. The General Partner will continue to own the non-economic general partner interest in the surviving entity.
Because CNX controlled CNXM prior to the Merger and continues to control CNXM after the Merger, CNX accounted for the change in its 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. No gain or loss was recognized in its condensed consolidated statements of operations as a result of the Merger.
The tax effects of the Merger were reported as adjustments to deferred income taxes and capital in excess of par value.
Prior to the effective time of the Merger on September 28, 2020, public unitholders held a 46.9% equity interest in CNXM and CNX owned the remaining 53.1% equity interest. 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 CNX's ownership interest in CNXM during the year ended December 31, 2019. See discussion of Midstream Acquisition below for change in ownership interest during the year ended December 31, 2018.
CNXM’s revolving credit facility (See Note 10 - Revolving Credit Facilities) and the CNXM Senior Notes (See Note 12 - Long-Term Debt) were not impacted by the Merger.
The Company incurred $11,271 of transaction costs directly attributable to the Merger during the year ended December 31, 2020, including financial advisory, legal service and other professional fees, which were recorded to Other Expense (Income) in the Consolidated Statements of Income.
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On August 31, 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties, which included approximately 26,000 net undeveloped acres. The net cash proceeds of $381,124 are included in Proceeds from Asset Sales in the Consolidated Statements of Cash Flows and the net gain on the transaction of $130,710 is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
On May 2, 2018, CNX closed on an Asset Exchange Agreement (the “AEA”) with HG Energy II Appalachia, LLC (“HG Energy”), pursuant to which, among other things, HG Energy (i) paid to CNX approximately $7,000 and (ii) assigned to CNX certain undeveloped Marcellus and Utica acreage in Southwest Pennsylvania, in exchange for CNX (x) assigning its interest in certain non-core midstream assets and surface acreage to HG Energy and (y) releasing certain HG Energy oil and gas acreage from dedication under a gathering agreement that is partially held, indirectly, by CNX. In connection with the transaction, CNX also agreed to certain transactions with CNXM, including the amendment of the existing gas gathering agreement between CNX and CNXM to increase the existing well commitment by an additional forty wells. The net gain on the sale was $286 and is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
As a result of the AEA, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were acquired in connection with the Midstream Acquisition discussed below (see also Note 9 - Goodwill and Other Intangible Assets) exceeded their fair value, and recognized an impairment of approximately $18,650, which is included in Impairment of Other Intangible Assets in the Consolidated Statements of Income.
On March 30, 2018, CNX Gas completed the sale of substantially all of its shallow oil and gas assets and certain Coalbed Methane (CBM) assets in Pennsylvania and West Virginia for $89,921 in cash consideration. In connection with the sale, the buyer assumed approximately $196,514 of asset retirement obligations. The net gain on the sale was $4,227 and is included in Gain on Asset Sales and Abandonments, net in the Consolidated Statements of Income.
On December 14, 2017, CNX Gas entered into a purchase agreement with Noble, pursuant to which CNX Gas acquired Noble’s 50% membership interest in CNX Gathering for a cash purchase price of $305,000 (the "Midstream Acquisition"). Prior to the Midstream Acquisition, the Company accounted for its 50% interest in CNX Gathering as an equity method investment as the Company had the ability to exercise significant influence, but not control, over the operating and financial policies of the midstream operations. In conjunction with the Midstream Acquisition, the Company obtained a controlling interest in CNX Gathering and, through CNX Gathering's ownership of the general partner, control over the Partnership. Accordingly, the Midstream Acquisition has been accounted for as a business combination using the acquisition method of accounting pursuant to ASC Topic 805, Business Combinations, or ASC 805. ASC 805 requires that, in circumstances where a business combination is achieved in stages (or step acquisition), previously held equity interests are remeasured at fair value and any difference between the fair value and the carrying value of the equity interest held be recognized as a gain or loss on the statement of income.
The fair value assigned to the previously held equity interest in CNX Gathering and CNXM for purposes of calculating the gain or loss was $799,033 and was determined using the income approach, based on a discounted cash flow methodology. The resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $623,663 is included in Gain on Previously Held Equity Interest in the Consolidated Statements of Income.
The fair value of the previously held equity interests was based on inputs that are not observable in the market and therefore represent Level 3 inputs (See Note 18 - Fair Value of Financial Instruments). The fair value was measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation included estimates of: (i) gathering volumes; (ii) future operating costs; and (iii) a market-based weighted average cost of capital. These inputs required significant judgments and estimates by management.
The fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, were estimated using the cost approach. Significant unobservable inputs in the valuation include management's assumptions about the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence associated with the acquired assets. As a result, the fair value estimates of the midstream facilities and equipment represents a Level 3 fair value measurement.
As part of the purchase price allocation, the Company identified intangible assets for customer relationships with third-party customers. The fair value of the identified intangible assets was determined using the income approach, which requires a forecast of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant unobservable inputs in the valuation include future revenue estimates, future cost assumptions, and estimated
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customer retention rates. As a result, the fair value estimate of the identified intangible assets represents a Level 3 fair value measurement.
The noncontrolling interest in the acquired business is comprised of the limited partner units in CNXM, which were not acquired by the Company. At the time of the Midstream Acquisition, the CNXM limited partner units were actively traded on the New York Stock Exchange and were valued based on observable market prices as of the transaction date and therefore represent a Level 1 fair value measurement.
Allocation of Purchase Price (Midstream Acquisition)
The following table summarizes the purchase price and the amounts of identified assets acquired and liabilities assumed based on the fair value as of January 3, 2018, with any excess of the purchase price over the fair value of the identified net assets acquired recorded as goodwill. The purchase price allocation was finalized as of December 31, 2018.
Fair Value of Consideration Transferred:

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

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

| Amount
Fair Value of Assets Acquired: |
Cash and Cash Equivalents | $ | 8,348 |
Accounts and Notes Receivable | 21,199 |
Prepaid Expense | 2,006 |
Other Current Assets | 163 |
Property, Plant and Equipment, net | 1,043,340 |
Intangible Assets | 128,781 |
Other | 593 |
Total Assets Acquired | 1,204,430 |
Fair Value of Liabilities Assumed: |
Accounts Payable | 26,059 |
CNXM Revolving Credit Facility | 149,500 |
Total Liabilities Assumed | 175,559 |
Total Identifiable Net Assets | 1,028,871 |
Fair Value of Noncontrolling Interest in CNXM | (718,577) |
Goodwill | 796,359 |
Net Assets Acquired | $ | 1,106,653 |

Post-Acquisition Operating Results (Midstream Acquisition)
The Midstream Acquisition contributed the following to the Midstream reporting unit within the Shale segment:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Other Revenue and Operating Income | $ | 64,710 |  |  | $ | 74,314 |  |  | $ | 89,781 |
Earnings Before Income Tax | $ | 156,818 |  |  | $ | 166,654 |  |  | $ | 133,811 |

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NOTE 5— STOCK REPURCHASE:
As of December 31, 2020, CNX's Board of Directors had approved $750,000 in stock repurchases since the October 30, 2017 inception of the current stock repurchase program. On January 26, 2021, the Company’s Board of Directors approved an increase in the aggregate amount of the current stock repurchase program plan, to $900,000. This increases the amount available under the current stock repurchase program to $245,000, not subject to an expiration date. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans.
During the year ended December 31, 2020, 4,138,527 shares were repurchased and retired at an average price of $10.43 per share for a total cost of $43,247. During the year ended December 31, 2019, 12,929,487 shares were repurchased and retired at an average price of $8.91 per share for a total cost of $115,477. During the year ended December 31, 2018, 25,894,324 shares were repurchased and retired at an average price of $14.80 per share for a total cost of $383,752.
NOTE 6—INCOME TAXES:
Income tax (benefit) expense provided on earnings consisted of:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Current: |  |  |  |  |
U.S. Federal | $ | (55,799) |  |  | $ | (51,243) |  |  | $ | (130,003) |
U.S. State | 12 |  |  | (113) |  |  | — |
| (55,787) |  |  | (51,356) |  |  | (130,003) |
Deferred: |  |  |  |  |
U.S. Federal | (83,080) |  |  | 47,717 |  |  | 319,813 |
U.S. State | (35,220) |  |  | 31,375 |  |  | 25,747 |
| (118,300) |  |  | 79,092 |  |  | 345,560 |
Total Income Tax (Benefit) Expense | $ | (174,087) |  |  | $ | 27,736 |  |  | $ | 215,557 |

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The components of the net deferred taxes are as follows:

| December 31,
| 2020 |  | 2019
Deferred Tax Assets: |  |  |
Net Operating Loss- Federal | $ | 215,936 |  |  | $ | 202,913 |
Net Operating Loss - State | 129,641 |  |  | 130,430 |
Foreign Tax Credit | 43,194 |  |  | 43,194 |
Operating Lease Right-of-Use Assets | 28,085 |  |  | 47,849 |
Gas Well Closing | 24,251 |  |  | 17,888 |
Salary Retirement | 11,478 |  |  | 9,236 |
Equity Compensation | 6,639 |  |  | 9,308 |
Alternative Minimum Tax | — |  |  | 51,241 |
Interest Limitation | — |  |  | 25,734 |
Other | 9,416 |  |  | 10,030 |
Total Deferred Tax Assets | 468,640 |  |  | 547,823 |
Valuation Allowance | (123,098) |  |  | (125,054) |
Net Deferred Tax Assets | 345,542 |  |  | 422,769 |
Deferred Tax Liabilities: |  |  |
Property, Plant and Equipment | (649,917) |  |  | (593,401) |
Investment in Partnership | (85,882) |  |  | (145,424) |
Gas Derivatives | (26,882) |  |  | (105,721) |
Operating Lease Liabilities | (28,287) |  |  | (46,640) |
Discount on Convertible Notes | (18,097) |  |  | — |
Advance Gas Royalties | (2,519) |  |  | (3,337) |
Other | (211) |  |  | (4,354) |
Total Deferred Tax Liabilities | (811,795) |  |  | (898,877) |
Net Deferred Tax Liability | $ | (466,253) |  |  | $ | (476,108) |

Deferred taxes are recorded for certain tax benefits, including net operating losses and tax credit carry-forwards, if management assesses the utilization of those assets to be more likely than not. A valuation allowance is required when it is not more likely than not that all or a portion of a deferred tax asset will be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. Positive evidence considered included financial earnings generated over the past three years for certain subsidiaries, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence includes financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods.
As of December 31, 2020, the Company has a deferred tax asset related to federal net operating losses of $215,936, which expire at various times between 2034 and 2039. However, because of the Tax Cuts and Jobs Act (the "TCJA Act") enacted on December 22, 2017 and the Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") enacted on March 27, 2020, the anticipated federal net operating losses generated in 2018 - 2020 do not expire but may only offset 80% of taxable income in any tax years beginning after 2020.
The CARES Act, which, among other things; increased the adjusted taxable income limitation for the disallowance of interest expense from 30% to 50% and provided for refunds of any remaining alternative minimum tax (AMT) credits in 2020. The impact of other tax implications of the Act on the financial statements and related disclosures are immaterial.
The TCJA Act repealed the corporate AMT for tax years beginning January 1, 2018 and provides that AMT credits can be utilized to offset current federal taxes owed in tax years 2018 through 2020. In addition, 50% of any unused AMT credits are refundable during these years with any remaining AMT credit carryforward being fully refunded in 2021, which was revised under the CARES Act to 2020. The Company has no deferred tax asset relating to federal AMT credits as of December 31,
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2020 compared to $51,241 as of December 31, 2019, a decrease of $51,241 from the prior year that resulted from the refunds received of all remaining outstanding AMT credits.
A valuation allowance on foreign tax credits of $43,194 has also been recorded at December 31, 2020 and 2019. The foreign tax credits expire at various times between 2021 and 2023.
CNX has, on an after federal tax basis, a deferred tax asset related to state operating losses of $129,641 with a related valuation allowance of $79,197 at December 31, 2020. The deferred tax asset related to state operating losses, on an after-tax adjusted basis, was $130,430 with a related valuation allowance of $81,202 at December 31, 2019. A review of positive and negative evidence regarding these state tax benefits concluded that the valuation allowances for various CNX subsidiaries was warranted. These net operating losses (NOLs) expire at various times between 2021 and 2040.
Management will continue to assess the potential for realized deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that could materially impact net income.
The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to CNX's effective tax rate:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
| Amount |  | Percent |  | Amount |  | Percent |  | Amount |  | Percent
Statutory U.S. Federal Income Tax Rate | $ | (126,595) |  |  | 21.0 | % |  | $ | 12,534 |  |  | 21.0 | % |  | $ | 230,721 |  |  | 21.0 | %
Net Effect of State Income Taxes | (32,336) |  |  | 5.5 |  |  | 1,333 |  |  | 2.2 |  |  | 60,814 |  |  | 5.6 |
Non-Controlling Interest | (11,556) |  |  | 1.9 |  |  | (23,662) |  |  | (39.6) |  |  | (18,181) |  |  | (1.7) |
Uncertain Tax Positions | 375 |  |  | (0.1) |  |  | — |  |  | — |  |  | (4,265) |  |  | (0.4) |
Accrual to Tax Return Reconciliation | 13 |  |  | — |  |  | 603 |  |  | 1.0 |  |  | 3,028 |  |  | 0.3 |
Effect of Equity Compensation | 4,311 |  |  | (0.7) |  |  | 8,771 |  |  | 14.7 |  |  | — |  |  | — |
Effect of Change in State Valuation Allowance | (2,004) |  |  | 0.3 |  |  | 33,238 |  |  | 55.6 |  |  | (22,684) |  |  | (2.1) |
Effect of Change in Federal Valuation Allowance | 48 |  |  | — |  |  | (2,640) |  |  | (4.4) |  |  | (18,110) |  |  | (1.7) |
Other Deferred Adjustments | 1,166 |  |  | (0.2) |  |  | (1,691) |  |  | (2.8) |  |  | 5,957 |  |  | 0.6 |
Effect of Federal and State Rate Reductions | (1,450) |  |  | 0.2 |  |  | (3,842) |  |  | (6.4) |  |  | (27,429) |  |  | (2.5) |
Effect of Federal Tax Credits | (6,284) |  |  | 1.0 |  |  | 2,881 |  |  | 4.8 |  |  | 1,208 |  |  | 0.1 |
Other | 225 |  |  | — |  |  | 211 |  |  | 0.4 |  |  | 4,498 |  |  | 0.4 |
Income Tax (Benefit) Expense / Effective Rate | $ | (174,087) |  |  | 28.9 | % |  | $ | 27,736 |  |  | 46.5 | % |  | $ | 215,557 |  |  | 19.6 | %

The effective tax rate for the year ended December 31, 2020 was higher than the U.S. federal statutory rate primarily due to state taxes, equity compensation, and the decrease in certain state valuation allowances as a result of the Merger transaction with CNXM partially offset by the benefit from non-controlling interest.
The effective tax rate for the year ended December 31, 2019 was higher than the U.S. federal statutory rate primarily due to state taxes, equity compensation, and the increase in certain state valuation allowances as a result of the higher than projected net operating loss generated in 2018 partially offset by the benefit from non-controlling interest.
As a result of the Midstream Acquisition on January 3, 2018 as discussed in Note 4 - Acquisitions and Dispositions, the Company obtained a controlling interest in CNX Gathering LLC and, through CNX Gathering's ownership of the general partner, control over CNXM. The financial results for 2018 through 2020 reflect full consolidation of CNXM’s assets and liabilities. The effective tax rates for the years ended December 31, 2019 and 2018 reflect a $23,662 and $18,181 reduction in income tax expense, respectively, due to the non-controlling interest in CNXM’s earnings.
The effective tax rate for the year ended December 31, 2018 was lower than the U.S. federal statutory rate primarily due to the effect of the filing of a Federal NOL carryback for 2017 and 2016 resulting in a financial statement benefit of $23,483 through the realization of the Federal NOLs at a 35% tax rate as a carryback versus the current 21% tax rate as a carryforward, the reversal of the AMT credit sequestration valuation allowance, and the release of certain state valuation allowances as a result of a corporate reorganization during the year. The federal NOL carryback claims for 2016 and 2017 were subject to a review by the IRS and the Joint Committee on Taxation which has since been completed.
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The TCJA Act, which, among other things, lowered the U.S. Federal corporate income tax rate from 35% to 21%, repealed the corporate AMT for tax years beginning January 1, 2018, and provided for a refund of previously accrued AMT credits. The Company's effective tax rate for 2018 reflects the release of previously recorded valuation allowances against AMT credit carry-forwards of $12,413, as those credits were able to be monetized under the TCJA Act.
In December 2019, the FASB issued ASU 2019-12 - Income Taxes - Simplifying the Accounting for Income Taxes (Topic 740), which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. This ASU removes the following exceptions: (1) exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items; (2) exception to the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment; (3) exception to the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary; and (4) exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. The amendments in this ASU also improve consistency and simplify other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this ASU were applied using different approaches depending on what the specific amendment relates to and, for public entities, are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The Company early adopted ASU 2019-12 as of January 1, 2020.
A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:

| For the Years Ended
| December 31,
| 2020 |  | 2019
Balance at Beginning of Period | $ | 31,516 |  |  | $ | 31,516 |
Increase in Unrecognized Tax Benefits Resulting from Tax Positions Taken During Prior Periods | 1,726 |  |  | — |
Reduction in Unrecognized Tax Benefits Because of the Lapse of the Applicable Statute of Limitations | (1,351) |  |  | — |
Balance at End of Period | $ | 31,891 |  |  | $ | 31,516 |

If these unrecognized tax benefits were recognized, $31,891 and $31,516 would affect CNX's effective income tax rate for 2020 and 2019, respectively.
In 2020, CNX recognized an increase in unrecognized tax benefits of $1,726 for tax benefits resulting from a tax position taken on our 2019 federal tax return for additional tax credits. CNX recognized a reduction to unrecognized tax benefits of $1,351 due to the expiration of the statute of limitations from a position taken on a previously filed federal income tax return.
CNX recognizes accrued interest related to unrecognized tax benefits in its interest expense. As of December 31, 2020 and 2019, the Company reported no accrued liability relating to uncertain tax positions in Other Liabilities in the Consolidated Balance Sheets. During the years ended December 31, 2020 and 2019, CNX paid no interest related to income tax deficiencies.
CNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. CNX had no accrued liabilities for tax penalties as of December 31, 2020 and 2019.
CNX and its subsidiaries file federal income tax returns with the United States and income tax returns within various states. With few exceptions, the Company is no longer subject to United States federal, state, local or non-U.S. income tax examinations by tax authorities for the years before 2018.
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NOTE 7—ASSET RETIREMENT OBLIGATIONS:
The reconciliation of changes in asset retirement obligations is as follows:

|  | December 31,
|  | 2020 |  | 2019
Balance, Beginning of Year |  | $ | 68,454 |  |  | $ | 38,554 |
Obligations Divested |  | (703) |  |  | — |
Accretion Expense |  | 11,067 |  |  | 9,458 |
Obligations Incurred |  | 2,806 |  |  | 2,933 |
Obligations Settled |  | (7,905) |  |  | (4,231) |
Revisions in Estimated Cash Flows |  | 19,449 |  |  | 21,740 |
Balance, End of Year |  | $ | 93,168 |  |  | $ | 68,454 |

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:

| December 31,
Property, Plant and Equipment | 2020 |  | 2019
Intangible Drilling Cost | $ | 4,965,252 |  |  | $ | 4,688,497 |
Gas Gathering Equipment | 2,510,917 |  |  | 2,463,866 |
Proved Gas Properties | 1,253,094 |  |  | 1,208,046 |
Gas Wells and Related Equipment | 1,120,061 |  |  | 1,042,000 |
Unproved Gas Properties | 725,705 |  |  | 755,590 |
Surface Land and Other Equipment | 199,322 |  |  | 226,285 |
Other | 189,645 |  |  | 187,722 |
Total Property, Plant and Equipment | 10,963,996 |  |  | 10,572,006 |
Less: Accumulated Depreciation, Depletion and Amortization | 3,938,451 |  |  | 3,435,431 |
Total Property, Plant and Equipment - Net | $ | 7,025,545 |  |  | $ | 7,136,575 |

During the years ended December 31, 2020 and 2019, the Company capitalized $1,328 and $5,482, respectively, of interest on Gas Gathering Equipment under construction.
Amounts below reflect properties where drilling operations have not yet commenced and therefore, were not being amortized for the years ended December 31, 2020 and 2019, respectively. These assets will be amortized using the units-of-production method and reclassified to proved gas properties when placed in service.

| December 31,
| 2020 |  | 2019
Unproved Gas Properties | $ | 725,705 |  |  | $ | 755,590 |
Advance Royalties | 9,676 |  |  | 12,770 |
Total | $ | 735,381 |  |  | $ | 768,360 |

NOTE 9—GOODWILL AND OTHER INTANGIBLE ASSETS:
In connection with the Midstream Acquisition that closed on January 3, 2018 (see Note 4 - Acquisitions and Dispositions for more information), CNX recorded $796,359 of goodwill and $128,781 of other intangible assets which are comprised of customer relationships.
Impairment of Goodwill
All goodwill is attributed to the Midstream reporting unit within the Shale segment. Goodwill is evaluated for impairment at least annually and whenever events or changes in circumstance indicate that the fair value of a reporting unit is less than its carrying amount. In connection with the evaluation of goodwill for impairment, CNX may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its
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carrying amount. If after assessing such factors or circumstances, CNX determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. If CNX chooses to bypass the qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then CNX will perform a quantitative assessment. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. The Company uses a combination of the income approach (generally a discounted cash flow method) and market approach (which may include the guideline public company method and/or the guideline transaction method) to estimate the fair value of a reporting unit.
In estimating the fair value of the Midstream reporting unit, the Company used the income approach’s discounted cash flow method, which applies significant inputs not observable in the public market (Level 3), including estimates and assumptions related to the use of an appropriate discount rate, future throughput volumes, operating costs and capital spending, discounted to present value using an industry rate adjusted for company-specific risk, which management feels reflects the overall level of inherent risk of the reporting unit. These assumptions are affected by expectations about future market, industry and economic conditions. Cash flow projections were derived from board approved budgeted amounts, a seven-year operating forecast and an estimate of future cash flows. Subsequent cash flows were developed using growth or contraction rates that management believes are reasonably likely to occur. The Company used the market approach’s comparable company method. The comparable company method evaluates the value of a company using metrics of other businesses of similar size and industry.
During the first quarter of 2020, the Company identified indicators of impairment in the form of 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. Management concluded that these factors presented indications that the fair value of the Midstream reporting unit was more likely than not below the reporting unit’s carrying value. CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches as described above to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceeded its estimated fair value, and a corresponding impairment of $473,045 was recorded, which was included in Impairment of Goodwill in the accompanying Consolidated Statements of Income.
In connection with our annual assessment of goodwill in the fourth quarter of 2020, we 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, we concluded that the estimated fair value exceeded carrying value, and accordingly no adjustment to goodwill was necessary. However, the margin by which the fair value of the Midstream reporting unit exceeded its carrying value was less than 10%. As a result, this reporting unit is susceptible to impairment risk from further adverse macroeconomic conditions or other adverse factors such as future gathering volumes being less than those currently estimated. Any additional adverse changes in the future could reduce the underlying cash flows used to estimate fair values and could result in a decline in fair value that could trigger future impairment charges.
The estimates of future cash flows are subjective in nature and are subject to impacts from business risks as described in “Item 1A. Risk Factors”. 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. Although CNX believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the estimated fair value. Future results could differ from our current estimates and assumptions.
Changes in the carrying amount of goodwill consist of the following activity:

| Amount
December 31, 2019 | $ | 796,359 |
Impairment | 473,045 |
December 31, 2020 | $ | 323,314 |

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

| December 31,
| 2020 |  | 2019
Other Intangible Assets: |  |  |
Gross Amortizable Asset - Customer Relationships | $ | 109,752 |  |  | $ | 109,752 |
Less: Accumulated Amortization - Customer Relationships | 19,657 |  |  | 13,105 |
Total Other Intangible Assets, net | $ | 90,095 |  |  | $ | 96,647 |

During the year ended December 31, 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets exceeded their fair value as a result of the AEA with HG Energy. Accordingly, CNX recognized an impairment on this intangible asset of $18,650. There were no such impairments during the years ended December 31, 2020 and 2019.
The customer relationship intangible asset is being amortized on a straight-line basis over approximately 17 years. Amortization expense related to other intangible assets was $6,552 for each of the years ended December 31, 2020 and 2019, and $6,931 for the year ended December 31, 2018. The estimated annual amortization expense is expected to approximate $6,552 per year for each of the next five years.
NOTE 10—REVOLVING CREDIT FACILITIES:
CNX
In April 2019, CNX amended its senior revolving credit facility ("Credit Facility") and extended its maturity to April 2024. The lenders' commitments remained unchanged at $2,100,000, with an accordion feature that allows the Company to increase commitments to $3,000,000. In addition, the cumulative credit basket for dividends and distributions was replaced with a basket for dividends and distributions subject to a pro forma net leverage ratio of at least 3.00 to 1.00 and availability under the Credit Facility of at least 15% of the aggregate commitments. In April 2020, as part of the semi-annual borrowing base redetermination, both the lenders' commitments and borrowing base decreased to $1,900,000, and the $650,000 letters of credit aggregate sub-limit remained unchanged. The amount of cash on hand that CNX may have is also limited to $150,000 when loans under the credit agreement are outstanding, subject to certain exceptions. In October 2020, as part of the semi-annual borrowing base redetermination, the lenders reaffirmed CNX's $1,900,000 borrowing base. In November 2020, as part of the issuance of the $500,000 of 6.00% Senior Notes due January 2029 (See Note 12 - Long-Term Debt), both the lenders' commitments and borrowing base decreased to $1,775,000.
The CNX Credit Facility is secured by substantially all of the assets of CNX and certain of its subsidiaries (excluding the certain excluded subsidiaries, which includes Cardinal States Gathering LLC, CNX Midstream GP LLC and CNXM, and their respective subsidiaries).
Under the terms of the agreement, borrowings under the revolving credit facility will bear interest at CNX's option at either:
•the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, or (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or
•the LIBOR rate, which is the LIBOR rate plus a margin ranging from 1.75% to 2.75%.
The CNX Credit Facility contains a number of affirmative and negative covenants including those that, except in certain circumstances, limit the Company and the subsidiary guarantors' ability to create, incur, assume or suffer to exist indebtedness, create or permit to exist liens on properties, dispose of assets, make investments, purchase or redeem CNX common stock, pay dividends, merge with another corporation and amend the senior unsecured notes. The Company must also mortgage 85% of the value of its proved reserves and 85% of the value of its proved developed producing reserves, in each case, which are included in the borrowing base, maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof, and enter into control agreements with respect to such applicable accounts.
The CNX Credit Facility contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants.
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The CNX Credit Facility also requires that CNX maintain a maximum net leverage ratio of no greater than 4.00 to 1.00, which is calculated as the ratio of debt less cash on hand to consolidated EBITDA, measured quarterly. CNX must also maintain a minimum current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current liabilities, excluding borrowings under the revolver, measured quarterly. The calculation of all of the ratios exclude CNXM. CNX was in compliance with all financial covenants as of December 31, 2020.
At December 31, 2020, the CNX Credit Facility had $160,800 of borrowings outstanding and $185,272 of letters of credit outstanding, leaving $1,428,928 of unused capacity. At December 31, 2019, the CNX Credit Facility had $661,000 of borrowings outstanding and $204,726 of letters of credit outstanding, leaving $1,234,274 of unused capacity.
CNX Midstream Partners LP (CNXM)
CNXM's revolving credit facility was not impacted by the Merger (See Note 4 - Acquisitions and Dispositions).
In April 2019, CNXM amended its senior secured revolving credit facility (the “CNXM Credit Facility”) and extended its maturity to April 2024. The lenders' commitments remained unchanged at $600,000, with an accordion feature that allows CNXM to increase the available borrowings by up to an additional $250,000 under certain terms and conditions. The CNXM Credit Facility includes the ability to issue letters of credit up to $100,000 in the aggregate.
Under the terms of the amended agreement, borrowings under the CNXM Credit Facility will bear interest at CNXM's option at either:
•the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, or (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.50% to 1.50%; or
•the LIBOR rate, plus a margin ranging from 1.50% to 2.50%.
Fees and interest rate spreads under the CNXM Credit Facility are based on the total leverage ratio, measured quarterly.
The CNXM Credit Facility requires CNXM to comply with a number of affirmative and negative covenants. In addition, CNXM is obligated to maintain at the end of each fiscal quarter (w) for so long as at least $150,000 of the CNXM 6.50% Senior Notes due March 2026 (CNXM Senior Notes) are outstanding, a maximum total leverage ratio of no greater than 5.25 to 1.00 (which increases to no greater than 5.50 to 1.00 during qualifying acquisition periods); (x) if less than $150,000 of the CNXM Senior Notes are outstanding, a maximum total leverage ratio of no greater than 4.75 to 1.00 (which increases to no greater than 5.25 to 1.00 during qualifying acquisition periods); (y) a maximum secured leverage ratio of no greater than 3.50 to 1.00 and (z) a minimum interest coverage ratio of no less than 2.50 to1.00. CNXM was in compliance with all financial covenants as of December 31, 2020.
The CNXM Credit Facility also contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under the revolving credit facility are secured by substantially all of the assets of CNXM and its wholly-owned subsidiaries. CNX is not a guarantor under the CNXM Credit Facility.
At December 31, 2020, the CNXM Credit Facility had $291,000 of borrowings outstanding and $30 of letters of credit outstanding, leaving $308,970 of unused capacity. At December 31, 2019, the CNXM Credit Facility had $311,750 of borrowings outstanding, leaving $288,250 of unused capacity.
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NOTE 11—OTHER ACCRUED LIABILITIES:

| December 31,
| 2020 |  | 2019
Royalties | $ | 72,401 |  |  | $ | 74,061 |
Accrued Interest | 26,549 |  |  | 30,862 |
Short-Term Incentive Compensation | 20,340 |  |  | 21,030 |
Transportation Charges | 15,969 |  |  | 16,533 |
Deferred Revenue | 10,986 |  |  | 13,964 |
Accrued Other Taxes | 10,580 |  |  | 9,115 |
Accrued Payroll & Benefits | 5,009 |  |  | 6,248 |
Other | 26,697 |  |  | 37,610 |
Current Portion of Long-Term Liabilities: |  |  |
Asset Retirement Obligations | 8,455 |  |  | 5,076 |
Salary Retirement | 1,787 |  |  | 1,587 |
Total Other Accrued Liabilities | $ | 198,773 |  |  | $ | 216,086 |

NOTE 12—LONG-TERM DEBT:

| December 31,
| 2020 |  | 2019
Senior Notes due March 2027 at 7.25% (Principal of $700,000 and $500,000, respectively, plus Unamortized Premium of $6,686 at December 31, 2020) | $ | 706,686 |  |  | $ | 500,000 |
Senior Notes due January 2029 at 6.00%, Issued at Par Value | 500,000 |  |  | — |
CNX Midstream Partners LP Senior Notes due March 2026 at 6.50% (Principal of $400,000 less Unamortized Discount of $3,875 and $4,625, respectively)* | 396,125 |  |  | 395,375 |
CNX Midstream Partners LP Revolving Credit Facility* | 291,000 |  |  | 311,750 |
Convertible Senior Notes due May 2026 at 2.25% (Principal of $345,000 less Unamortized Discount and Issuance Costs of $107,735) | 237,265 |  |  | — |
CNX Revolving Credit Facility | 160,800 |  |  | 661,000 |
Cardinal States Gathering Company Credit Facility maturing in March 2028 (Principal of $114,985 less Unamortized Discount of $1,126) | 113,859 |  |  | — |
CSG Holdings II LLC Credit Facility maturing in March 2027 (Principal of $45,559 less Unamortized Discount of $441) | 45,118 |  |  | — |
Senior Notes due April 2022 at 5.875% (Principal of $894,307 plus Unamortized Premium of $1,001 at December 31, 2019) | — |  |  | 895,308 |
Less: Unamortized Debt Issuance Costs | 26,852 |  |  | 8,990 |
| 2,424,001 |  |  | 2,754,443 |
Less: Amounts Due in One Year | 22,574 |  |  | — |
Long-Term Debt | $ | 2,401,427 |  |  | $ | 2,754,443 |

*CNX is not a guarantor of CNXM's 6.50% Senior Notes due March 2026 or CNXM's Credit Facility.
CNXM's Credit Facility and the CNXM Senior Notes were not impacted by the Merger (See Note 4 - Acquisitions and Dispositions).
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At December 31, 2020, annual undiscounted maturities of CNX and CNXM long-term debt during the next five years and thereafter are as follows:

Year ended December 31, | Amount
2021 | $ | 22,574 |
2022 | 23,712 |
2023 | 24,469 |
2024 | 474,366 |
2025 | 23,057 |
Thereafter | 1,989,166 |
Total Long-Term Debt Maturities | $ | 2,557,344 |

During the year ended December 31, 2020, CNX purchased and retired the remaining $894,307 of its outstanding 5.875% Senior Notes due April 2022. As part of this transaction, a gain of $10,101 was included in (Gain) Loss on Debt Extinguishment in the Consolidated Statements of Income.
In November 2020, CNX completed a private offering of $500,000 aggregate principal amount of 6.00% Senior Notes due January 2029 (the “Senior Notes due January 2029”). The notes, along with the related guarantees, were issued pursuant to an indenture, dated November 30, 2020, among the Company, the subsidiary guarantors party thereto and UMB Bank, N.A., as trustee. The notes accrue interest from November 30, 2020 at a rate of 6.00% per year. Interest is payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2021. The Senior Notes due January 2029 mature on January 15, 2029, subject to adjustment upon the occurrence of specified events. The notes rank equally in right of payment with all of the Company’s existing and future senior indebtedness and senior to any subordinated indebtedness that the Company may incur. The notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner) or CSG Holdings III LLC.
In September 2020, CNX completed a private offering of $200,000 aggregate principal amount of 7.25% Senior Notes due March 2027 (the “Senior Notes due March 2027s”) plus $7,000 of unamortized bond premium at a price of 103.5% of par with an effective yield of 6.34%. The notes, along with the related guarantees, were issued pursuant to an indenture, dated March 14, 2019. The notes accrue interest from September 14, 2020 at a rate of 7.25% per year. Interest is payable semi-annually in arrears on March 14 and September 14 of each year, beginning March 14, 2021. The notes mature on March 14, 2027. The Senior Notes due March 2027 rank equally in right of payment with all of the Company’s existing and future senior indebtedness and senior to any subordinated indebtedness that the Company may incur. The notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner) or CSG Holdings III LLC.
In April 2020, CNX issued $345,000 in aggregate principal amount of 2.25% convertible senior notes due May 2026 (the "Convertible Notes") in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, including $45,000 aggregate principal amount of Convertible Notes issued pursuant to the exercise in full of the initial purchasers’ option to purchase additional Convertible Notes. The Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of the Company. The Convertible Notes bear interest at a fixed rate of 2.25% per annum, payable semi-annually in arrears on May 1 and November 1 of each year, commencing on November 1, 2020. Proceeds from the issuance of the Convertible Notes totaled $334,650, net of initial purchaser discounts and issuance costs. The notes are guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner) or CSG Holdings III LLC.
The initial conversion rate is 77.8816 shares of CNX's common stock per $1,000 principal amount of Convertible Notes, which represents an initial conversion price of approximately $12.84 per share, subject to adjustment upon the occurrence of specified events. The Convertible Notes will mature on May 1, 2026, unless earlier repurchased, redeemed or converted. Before February 1, 2026, note holders will have the right to convert their Convertible Notes only upon the occurrence of the following events:
•during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on June 30, 2020, if the Last Reported Sale Price per share of Common Stock exceeds one hundred and thirty percent (130%) of the Conversion Price for each of at least twenty (20) Trading Days (whether or not consecutive) during the thirty (30) consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter.
•during the five (5) consecutive Business Days immediately after any ten (10) consecutive trading day period (such ten (10) consecutive Trading Day period, the “Measurement Period”) if the trading Price per $1,000 principal amount of
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Notes, as determined following a request by a Holder in accordance with the procedures set forth below, for each trading day of the Measurement Period was less than ninety eight percent (98%) of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day.
•if we call any or all of the Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or
•upon the occurrence of certain specified corporate events as set forth in the indenture governing the Convertible Notes.
From and after February 1, 2026, note holders may convert their Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date.
Upon conversion, the Company may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture governing the Convertible Notes. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the Convertible Notes, that occur prior to the maturity date, the Company will increase the conversion rate, in certain circumstances, for a holder who elects to convert its Convertible Notes in connection with such a corporate event.
The Company will settle conversions by paying or delivering, as applicable, cash, shares of its common stock or a combination of cash and shares of its common stock, at the Company’s election. The Company’s current intent is to settle the principal amount of the Convertible Notes in cash upon conversion.
If certain corporate events that constitute a “Fundamental Change” (as defined in the indenture governing the Convertible Notes) occur, then noteholders may require the Company to repurchase their Notes at a cash repurchase price equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock. During the year ended December 31, 2020, the conditions allowing holders of the Convertible Notes to exercise their conversion right were not met and as of December 31, 2020, the notes were not convertible. The Convertible Notes are therefore classified as long-term debt at December 31, 2020.
In accounting for the transaction, the Convertible Notes were separated into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of a similar debt instrument that does not have an associated conversion feature. The fair value was based on market data available for publicly traded, senior, unsecured corporate bonds with similar maturity, which represent Level 2 observable inputs. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes and was recorded in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity and is not remeasured as long as it continues to meet the conditions for equity classification. The excess of the principal amount of the Convertible Notes over the liability component and the debt issuance costs are amortized to interest expense over the contractual term of the Convertible Notes using the effective interest method.
In accounting for the debt issuance costs of $10,350 related to the Convertible Notes, the Company allocated the total amount incurred to the liability and equity components using the same proportions as the proceeds of the Convertible Notes. Issuance costs attributable to the liability component were $7,024 and will be amortized to interest expense using the effective interest method over the contractual term of the Convertible Notes. Issuance costs attributable to the equity component were $3,326 and were netted with the equity component in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity and are not subject to amortization.
The net carrying amount of the liability and equity components of the Convertible Notes was as follows:

| December 31, 2020
Liability Component: |
Principal | $ | 345,000 |
Unamortized Discount | (101,367) |
Unamortized Issuance Costs | (6,368) |
Net Carrying Amount | $ | 237,265 |
Equity Component, net of Purchase Discounts and Issuance Costs | 78,317 |

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Interest expense related to the Convertible Notes is as follows:

| For the Year Ended
| December 31, 2020
Contractual Interest Expense | $ | 5,175 |
Amortization of Debt Discount | 9,516 |
Amortization of Issuance Costs | 655 |
Total Interest Expense | $ | 15,346 |

In connection with the offering of the Convertible Notes, the Company entered into privately negotiated capped call transactions with certain counterparties, (the “Capped Calls”). The Capped Calls each have an initial strike price of $12.84 per share, subject to certain adjustments, which correspond to the initial conversion price of the Convertible Notes. The Capped Calls have an initial cap price of $18.19 per share, subject to certain adjustments. The Capped Calls cover, subject to anti-dilution adjustments, the aggregate number of shares of the Company’s common stock that initially underlie the Convertible Notes, and are expected generally to reduce potential dilution to the Company’s common stock upon any conversion of Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of converted Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap, based on the cap price of the Capped Call Transactions. The conditions that cause adjustments to the initial strike price of the Capped Calls mirror the conditions that result in corresponding adjustments for the Convertible Notes. For accounting purposes, the Capped Calls are separate transactions, and not part of the terms of the Convertible Notes. As these transactions meet certain accounting criteria, the Capped Calls are recorded in stockholders’ equity and are not accounted for as derivatives. The cost of $35,673 incurred in connection with the Capped Calls was recorded as a reduction to Capital in Excess of Par Value. The impact of the Capped Calls related to stockholders’ equity has been included in Capital in Excess of Par Value in the Consolidated Statement of Stockholders Equity and includes taxes in the amount of $9,322, for a net impact of $26,351.
During the year ended December 31, 2020, CNX's wholly-owned subsidiary Cardinal States Gathering Company LLC (Cardinal States) entered into a $125,000 non-revolving credit facility agreement (the "Cardinal States Facility"). The Cardinal States Facility matures in 2028, has an interest rate of 3-month LIBOR + 450 basis points and includes an excess cash flow sweep in an amount required to achieve a quarterly targeted debt balance. The facility is secured by substantially all of the Cardinal States assets, requires a minimum level of hedging of the variable interest rate exposure and is non-recourse to CNX.
Additionally, during the year ended December 31, 2020, CNX's wholly-owned subsidiary CSG Holdings II LLC (CSG Holdings) entered into a $50,000 non-revolving credit facility agreement (the "CSG Holdings Facility"). The CSG Holdings Facility matures in 2027, has interest rate of 3-month LIBOR + 675 basis points and includes a full excess cash sweep. The facility is secured by substantially all of the CSG Holding assets, requires a minimum level of hedging of the variable interest rate exposure and is non-recourse to CNX.
During the year ended December 31, 2019, CNX completed a private offering of $500,000 of 7.25% Senior Notes due March 2027. The notes are guaranteed by most of CNX's subsidiaries but do not include CNXM (or its subsidiaries or general partner).
During the year ended December 31, 2019, CNX purchased and retired $400,000 of its outstanding 5.875% Senior Notes due April 2022. As part of this transaction, a loss of $7,614 was included in (Gain) Loss on Debt Extinguishment in the Consolidated Statements of Income.
During the year ended December 31, 2018, CNX purchased and retired $411,375 of its outstanding 5.875% Senior Notes due April 2022. As part of this transaction, a loss of $15,320 was included in (Gain) Loss on Debt Extinguishment in the Consolidated Statements of Income.
During the year ended December 31, 2018, CNX called the $500,000 balance on its 8.00% Senior Notes due April 2023. As part of this transaction, a loss of $38,798 was included in (Gain) Loss on Debt Extinguishment in the Consolidated Statements of Income.
NOTE 13—LEASES:
On January 1, 2019, the Company adopted ASU 2016-02, and all related amendments, using the transition method, which allows for a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. CNX elected the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all leases that existed prior to the transition date. As a result, CNX did not reassess 1) whether existing or expired contracts contain
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leases, 2) lease classification for any existing or expired leases or 3) whether lease origination costs qualified as initial direct costs. Additionally, the Company elected the short-term practical expedient for all asset classes by establishing an accounting policy to exclude leases with a term of 12 months or less. CNX will not separate lease components from non-lease components for any asset class. Lastly, CNX adopted the easement practical expedient, which allows the Company to apply ASC 842 prospectively to land easements after the adoption date. Easements that existed or expired prior to the adoption date that were not previously assessed under ASC 840 will not be reassessed.
CNX's leasing activities primarily consist of operating and finance leases for electric fracturing equipment, natural gas drilling rigs, CNX's corporate headquarters as well as field offices, a natural gas gathering pipeline and commercial vehicles. Some leases include options to renew ranging from a period of 1 to 10 years, which are not recognized as part of the lease right-of-use (ROU) assets or liabilities as they are not reasonably certain to be exercised.
Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of the lease payments over the lease term. As most of CNX's leases do not provide an implicit rate, an incremental borrowing rate is used to determine the present value of lease payments.
The components of lease cost were as follows:

| For the Years Ended December 31,
| 2020 |  | 2019
Operating Lease Cost | $ | 74,703 |  |  | $ | 73,809 |
Finance Lease Cost: |  |  |
Amortization of Right-of-Use Assets | 4,959 |  |  | 5,242 |
Interest on Lease Liabilities | 739 |  |  | 1,241 |
Short-term Lease Cost | 3,252 |  |  | 5,547 |
Variable Lease Cost* | 9,634 |  |  | 17,337 |
Total Lease Cost | $ | 93,287 |  |  | $ | 103,176 |

*Amounts recognized in the Consolidated Balance Sheets for natural gas drilling rigs are measured using the rates that would be paid if the rigs were idle, as this represents the minimum payment that could be made under the contract. Variable lease cost represents amounts paid for natural gas drilling rigs above this minimum when the rigs are in use. Amounts recognized in the Consolidated Balance Sheets for electric fracturing equipment are measured using minimum pumping hours under the contract; however, pumping hours may exceed the minimum and vary period to period. Any such amounts paid related to pumping hours in excess of the minimum represent variable lease cost.
Rental expense under operating leases prior to the adoption of ASC 842 was $21,441 for the year ended December 31, 2018.
Amounts recognized in the Consolidated Balance Sheets are as follows:

| December 31,
| 2020 |  | 2019
Operating Leases: |  |  |
Operating Lease Right-of-Use Asset | $ | 108,683 |  |  | $ | 187,097 |
Current Portion of Operating Lease Obligations | $ | 52,575 |  |  | $ | 61,670 |
Operating Lease Obligations | 53,235 |  |  | 110,466 |
Total Operating Lease Liabilities | $ | 105,810 |  |  | $ | 172,136 |
Finance Leases: |  |  |
Property, Plant and Equipment | $ | 72,653 |  |  | $ | 72,916 |
Less—Accumulated Depreciation, Depletion and Amortization | 67,508 |  |  | 63,008 |
Property, Plant and Equipment—Net | $ | 5,145 |  |  | $ | 9,908 |
Current Portion of Finance Lease Obligations | $ | 6,876 |  |  | $ | 7,164 |
Finance Lease Obligations | 1,057 |  |  | 7,706 |
Total Finance Lease Liabilities | $ | 7,933 |  |  | $ | 14,870 |

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Supplemental cash flow information related to leases was as follows:

| For the Years Ended December 31,
| 2020 |  | 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities: |  |  |
Operating Cash Flows from Operating Leases | $ | 62,610 |  |  | $ | 66,827 |
Operating Cash Flows from Finance Leases | $ | 739 |  |  | $ | 1,241 |
Financing Cash Flows from Finance Leases | $ | 7,155 |  |  | $ | 7,149 |
Right-of-Use Assets Obtained in Exchange for Lease Obligations: |  |  |
Operating Leases | $ | 4,027 |  |  | $ | 15,347 |
Finance Leases | $ | 257 |  |  | $ | 1,846 |

Maturities of lease liabilities are as follows:

| Operating |  | Finance
| Leases |  | Leases
Year Ended December 31, |  |  |
2021 | $ | 56,190 |  |  | $ | 7,138 |
2022 | 21,592 |  |  | 446 |
2023 | 5,453 |  |  | 442 |
2024 | 5,433 |  |  | 155 |
2025 | 4,824 |  |  | 38 |
Thereafter | 25,996 |  |  | 40 |
Total Lease Payments | 119,488 |  |  | 8,259 |
Less: Interest | 13,678 |  |  | 326 |
Present Value of Lease Liabilities | $ | 105,810 |  |  | $ | 7,933 |

Lease terms and discount rates are as follows:

| December 31,
| 2020 |  | 2019
Weighted Average Remaining Lease Term (years): |  |  |
Operating Leases | 4.68 |  | 4.39
Finance Leases | 1.37 |  | 2.16
Weighted Average Discount Rate: |  |  |
Operating Leases | 4.40 | % |  | 4.96 | %
Finance Leases | 6.33 | % |  | 6.92 | %

NOTE 14—PENSION:
The benefits for the Defined Contribution Restoration Plan were frozen effective July 1, 2018. Employees hired after this date are not eligible for this benefit plan. In addition, current participants receive no further compensation credits after that date, with the last award being 2017. Annual interest credits will continue to be made in accordance with the terms of the plan. The freezing of the plan triggered a curtailment gain of $416 during the year ended December 31, 2018.
The current portion of the pension obligation is included in Other Accrued Liabilities and the noncurrent portion is included in Other Liabilities in the Consolidated Balance Sheets.
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The reconciliation of changes in the benefit obligation, plan assets and funded status of the pension benefits is as follows:

| December 31,
| 2020 |  | 2019
Change in Benefit Obligation: |  |  |
Benefit Obligation at Beginning of Period | $ | 40,196 |  |  | $ | 33,569 |
Service Cost | 247 |  |  | 209 |
Interest Cost | 1,179 |  |  | 1,338 |
Actuarial Loss | 4,098 |  |  | 4,865 |
Plan Amendments | — |  |  | 1,728 |
Benefits and Other Payments | (1,644) |  |  | (1,513) |
Benefit Obligation at End of Period | $ | 44,076 |  |  | $ | 40,196 |
Change in Plan Assets: |  |  |
Fair Value of Plan Assets at Beginning of Period | $ | — |  |  | $ | — |
Company Contributions | 1,644 |  |  | 1,513 |
Benefits and Other Payments | (1,644) |  |  | (1,513) |
Fair Value of Plan Assets at End of Period | $ | — |  |  | $ | — |
Funded Status: |  |  |
Current Liabilities | $ | (1,787) |  |  | $ | (1,587) |
Noncurrent Liabilities | (42,289) |  |  | (38,609) |
Net Obligation Recognized | $ | (44,076) |  |  | $ | (40,196) |
Amounts Recognized in Accumulated Other Comprehensive Loss Consist of: |  |  |
Net Actuarial Loss | $ | 19,075 |  |  | $ | 15,361 |
Prior Service Cost | 1,506 |  |  | 1,727 |
Total | 20,581 |  |  | 17,088 |
Less: Tax Benefit | 5,397 |  |  | 4,483 |
Net Amount Recognized | $ | 15,184 |  |  | $ | 12,605 |

The components of the net periodic benefit cost are as follows:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Components of Net Periodic Benefit Cost: |  |  |  |  |
Service Cost | $ | 247 |  |  | $ | 209 |  |  | $ | 302 |
Interest Cost | 1,179 |  |  | 1,338 |  |  | 1,265 |
Amortization of Prior Service Cost (Credit) | 221 |  |  | (17) |  |  | (193) |
Recognized Net Actuarial Loss | 383 |  |  | 242 |  |  | 865 |
Curtailment Gain | — |  |  | — |  |  | (416) |
Net Periodic Benefit Cost | $ | 2,030 |  |  | $ | 1,772 |  |  | $ | 1,823 |

CNX utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the pension plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO) or the market-related value of plan assets are amortized over the expected remaining future lifetime of all plan participants for the pension plan.
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The following table provides information related to the pension plan with an accumulated benefit obligation in excess of plan assets:

| As of December 31,
| 2020 |  | 2019
Projected Benefit Obligation | $ | 44,076 |  |  | $ | 40,196 |
Accumulated Benefit Obligation | $ | 43,886 |  |  | $ | 40,196 |
Fair Value of Plan Assets | $ | — |  |  | $ | — |

Assumptions:
The weighted-average assumptions used to determine benefit obligations are as follows:

| As of December 31,
| 2020 |  | 2019
Discount Rate | 2.47 | % |  | 3.36 | %
Rate of Compensation Increase | — | % |  | — | %
Interest Credited Rate | 2.26 | % |  | 3.01 | %

The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans.
The weighted-average assumptions used to determine net periodic benefit cost are as follows:

| For the Years ended December 31,
| 2020 |  | 2019 |  | 2018
Discount Rate | 3.36 | % |  | 4.37 | % |  | 4.28 | %
Rate of Compensation Increase | — | % |  | 3.63 | % |  | 4.05 | %
Interest Credited Rate | 2.47 | % |  | 3.39 | % |  | 3.94 | %

Cash Flows:
The following benefit payments, which reflect expected future service, are expected to be paid:

|  | Pension
Year ended December 31, |  | Benefits
2021 |  | $ | 1,787 |
2022 |  | $ | 1,846 |
2023 |  | $ | 1,913 |
2024 |  | $ | 1,977 |
2025 |  | $ | 2,049 |
Year 2026-2030 |  | $ | 11,172 |

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NOTE 15—STOCK-BASED COMPENSATION:
CNX's Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the Equity Incentive Plan have been adopted and approved by the Board of Directors and the Company's shareholders since the commencement of the Equity Incentive Plan. Most recently, in May 2020 the Company's Shareholders adopted and approved a 10,775,000 increase to the total number of shares available for issuance. At December 31, 2020, 14,081,055 shares of common stock remained available for grant under the plan. The Equity Incentive Plan provides that the aggregate number of shares available for issuance will be reduced by one share for each share relating to stock options and by 1.62 for each share relating to Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the Equity Incentive Plan after the tenth anniversary of the grant date of the award.
For those shares expected to vest, CNX recognizes stock-based compensation costs on a straight-line basis over the requisite service period of the award, which is generally the vesting term. Options and RSUs vest over a three-year term. PSUs granted in 2016-2019 vest over a five-year term at 20% per year and PSUs granted in 2020 vest over a three-year term at 33.3% per year subject to performance conditions. If an employee leaves the Company, all unvested shares are forfeited. CNX recognizes forfeitures as they occur. The vesting of all awards will accelerate in the event of death and disability and may accelerate upon a change in control of CNX.
Pursuant to the terms of the change in control severance agreements of certain employees and CNX officers, outstanding equity awards held by such employees vest upon a stockholder (or stockholder group) becoming the beneficial owner of more than 25% of the Company's outstanding common stock. During the year ended December 31, 2019, Southeastern Asset Management, Inc. and its affiliates ("SEAM") acquired shares of CNX's common stock in the open market which resulted in SEAM's aggregate share ownership exceeding more than 25% of CNX's common stock outstanding. This transaction, as such, constituted a change in control event under the severance agreements, resulting in the accelerated vesting of 473,126 restricted stock units and 903,100 performance share units held by the aforementioned employees that were issued prior to 2019. Those affected employees and officers each consented to waive the change in control vesting provision included in the change in control severance agreements with respect to their restricted stock unit and performance share unit awards that were issued during 2019. The accelerated vesting resulted in $19,654 of additional long-term equity-based compensation expense for the year ended December 31, 2019, and is included in Selling, General and Administrative Costs in the Consolidated Statements of Income. The performance share unit awards that vested continue to be subject to the attainment of performance goals as determined by the Compensation Committee of CNX's Board of Directors after the end of the applicable performance period.
The total stock-based compensation expense recognized relating to CNX shares during the years ended December 31, 2020, 2019 and 2018 was $12,897, $36,545 and $18,930, respectively. The related deferred tax benefit totaled $2,134, $3,955, $4,169, respectively.
As of December 31, 2020, CNX has $10,830 of unrecognized compensation cost related to all non-vested stock-based compensation awards, which is expected to be recognized over a weighted-average period of 1.82 years. When stock options are exercised, and restricted and performance stock unit awards become vested, the issuances are made from CNX's common stock shares.
Pursuant to the Merger (See Note 4 - Acquisitions and Dispositions for more information), all outstanding phantom units previously granted under the CNXM long-term incentive plan were converted into the right to receive 0.88 shares of common stock of CNX. As such, all outstanding phantom units were converted, effective as of the closing of the Merger, into CNX restricted stock units. Each CNX restricted stock unit will be subject to the same vesting, forfeiture and other terms and conditions applicable to the converted CNXM phantom units. Under Accounting Standards Codification Topic 718, Compensation - Stock Compensation, it was determined that there was no additional compensation cost to record as the conversion of awards did not result in incremental fair value.
Stock Options:
CNX examined its historical pattern of option exercises in an effort to determine if there were any discernible activity patterns based on certain employee populations. From this analysis, CNX identified two distinct employee populations and used the Black-Scholes option pricing model to value the options for each of the employee populations. The expected term computation presented in the table below is based upon a weighted average of the historical exercise patterns and post-vesting termination behavior of the two populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends.
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The total fair value of options granted during the years ended December 31, 2020, 2019 and 2018 was $1,066, $50, and $143 respectively, based on the following assumptions and weighted average fair values:

|  | December 31,
|  | 2020 |  | 2019 |  | 2018
Weighted Average Fair Value of Grants |  | $ | 3.56 |  |  | $ | 3.48 |  |  | $ | 6.50 |
Risk-free Interest Rate |  | 1.61 | % |  | 2.13 | % |  | 2.66 | %
Expected Dividend Yield |  | — | % |  | — | % |  | — | %
Expected Forfeiture Rate |  | — | % |  | — | % |  | — | %
Expected Volatility |  | 55.33 | % |  | 43.60 | % |  | 52.68 | %
Expected Term in Years |  | 5.11 |  | 6.50 |  | 3.71

A summary of the status of stock options granted is presented below:

|  |  |  |  |  | Weighted |  |
|  |  |  |  |  | Average |  |
|  |  |  | Weighted |  | Remaining |  | Aggregate
|  |  |  | Average |  | Contractual |  | Intrinsic
|  |  |  | Exercise |  | Term (in |  | Value (in
|  | Shares |  | Price |  | years) |  | thousands)
Outstanding at December 31, 2019 |  | 4,696,264 |  |  | $ | 18.05 |  |  |  |  |
Granted |  | 299,541 |  |  | $ | 10.46 |  |  |  |  |
Exercised |  | (298,513) |  |  | $ | 6.87 |  |  |  |  |
Forfeited |  | (3,561) |  |  | $ | 10.53 |  |  |  |  |
Expired |  | (493,222) |  |  | $ | 43.53 |  |  |  |  |
Outstanding at December 31, 2020 |  | 4,200,509 |  |  | $ | 15.32 |  |  | 4.18 |  | $ | 9,430 |
Exercisable at December 31, 2020 |  | 3,908,444 |  |  | $ | 15.68 |  |  | 3.81 |  | $ | 9,330 |

At December 31, 2020, there were 3,710,157 employee stock options outstanding under the Equity Incentive Plan. Non-employee director stock options vest one year after the grant date. There are 490,352 stock options outstanding under these grants.
The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CNX's closing stock price on the last trading day of the year ended December 31, 2020 and the option's exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2020. This amount varies based on the fair market value of CNX's stock. The total intrinsic value of options exercised for the years ended December 31, 2020, 2019 and 2018 was $1,263, $175, and $2,077, respectively.
Cash received from option exercises for the years ended December 31, 2020, 2019 and 2018 was $2,052, $546 and $1,714, respectively. The tax impact from option exercises totaled $328, $46 and $569 for the years ended December 31, 2020, 2019 and 2018, respectively.
Restricted Stock Units:
Under the Equity Incentive Plan, CNX grants certain employees and non-employee directors RSU awards, which entitle the holder to receive shares of common stock as the award vests. Non-employee director RSUs vest at the end of one year. Compensation expense is recognized over the vesting period of the units, described above. The total fair value of RSUs granted during the years ended December 31, 2020, 2019 and 2018 was $10,619, $10,844 and $13,768, respectively. The total fair value of restricted stock units vested during the years ended December 31, 2020, 2019 and 2018 was $4,798, $10,391 and $6,437, respectively.
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The following table represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant:

|  | Number of |  | Weighted Average
|  | Shares |  | Grant Date Fair Value
Nonvested at December 31, 2019 |  | 1,033,200 |  |  | $11.71
Granted |  | 1,251,065 |  |  | $8.49
RSUs granted in conversion, as a result of the CNXM Merger |  | 204,619 |  |  | $18.01
Vested |  | (577,834) |  |  | $10.95
Forfeited |  | (39,923) |  |  | $9.65
Nonvested at December 31, 2020 |  | 1,871,127 |  |  | $10.10

Performance Share Units:
Under the Equity Incentive Plan, CNX grants certain employees performance share unit awards, which entitle the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. The total fair value of performance share units granted during the years ended December 31, 2020, 2019 and 2018 was $3,826, $6,741 and $8,570, respectively. The total fair value of performance share units vested during the years ended December 31, 2020, 2019 and 2018 was $1,926, $4,668 and $7,547, respectively.
The following table represents the nonvested performance share units and their corresponding fair value (based upon the Monte Carlo Methodology) on the date of grant:

|  | Number of |  | Weighted Average
|  | Shares |  | Grant Date Fair Value
Nonvested at December 31, 2019 |  | 1,400,836 |  |  | $18.91
Granted |  | 660,634 |  |  | $5.79
PSUs Issued |  | 112,158 |  |  | $20.39
Vested |  | (274,716) |  |  | $20.82
Forfeited |  | (131,474) |  |  | $18.37
Nonvested at December 31, 2020 |  | 1,767,438 |  |  | $13.85

Performance Options:
Under the Equity Incentive Plan, CNX granted certain employees performance options in 2010, which entitled the holder to shares of common stock subject to the achievement of certain performance goals. Compensation expense was recognized over the vesting period of the options. The Black-Scholes option valuation model was used to value each tranche separately. There have been no performance options granted since 2010. The 927,268 performance options that were outstanding and exercisable at a weighted average exercise price of $39.00 at December 31, 2019 expired as of December 31, 2020.
NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CNX. For non-cash transactions that relate to the separation, as well as acquisitions and dispositions, see Note 4 - Acquisitions and Dispositions.
As of December 31, 2020, 2019 and 2018, CNX purchased goods and services related to capital projects in the amount of $30,982, $43,982 and $58,246, respectively, which are included in accounts payable.
The following table shows cash paid (received):

|  | For the Years Ended December 31,
|  | 2020 |  | 2019 |  | 2018
Interest (Net of Amounts Capitalized) |  | $ | 141,992 |  |  | $ | 143,111 |  |  | $ | 144,756 |
Income Taxes |  | $ | (118,125) |  |  | $ | (138,409) |  |  | $ | (11,505) |

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NOTE 17—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:
CNX markets natural gas primarily to gas wholesalers in the United States. Concentration of credit risk is summarized below:

| December 31,
| 2020 |  | 2019
Gas Wholesalers | $ | 133,253 |  |  | $ | 115,641 |
NGL, Condensate & Processing Facilities | 7,008 |  |  | 10,140 |
Other | 5,752 |  |  | 7,699 |
Allowance for Credit Losses | (84) |  |  | — |
Total Accounts Receivable Trade | $ | 145,929 |  |  | $ | 133,480 |

As of December 31, 2020, a receivable of $19,995 due from Direct Energy Business Marketing LLC was included in the Gas Wholesalers balance above. As of December 31, 2019, receivables of $23,859 and $15,401 due from Direct Energy Business Marketing LLC and NJR Energy Services Company, respectively, were included. No other customers made up more than 10% of the total balances.
During the year ended December 31, 2020, sales to Direct Energy Business Marketing LLC were $167,390, which comprised over 10% of the Company's revenue from contracts with external customers for the period.
During the year ended December 31, 2019, sales to Direct Energy Business Marketing LLC were $214,980 and sales to NJR Energy Services Company were $147,540, each of which comprised over 10% of the Company's revenue from contracts with external customers for the period.
During the year ended December 31, 2018, sales to NJR Energy Services Company were $219,472 and sales to Direct Energy Business Marketing LLC were $184,668, each of which comprised over 10% of the Company's revenue from contracts with external customers for the period.
NOTE 18—FAIR VALUE OF FINANCIAL INSTRUMENTS:
CNX determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:
Level 1 - Quoted prices for identical instruments in active markets.
Level 2 - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward curves.
Level 3 - Unobservable inputs significant to the fair value measurement supported by little or no market activity.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.
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The financial instrument measured at fair value on a recurring basis is summarized below:

| Fair Value Measurements at December 31, 2020 |  | Fair Value Measurements at December 31, 2019
Description | Level 1 |  | Level 2 |  | Level 3 |  | Level 1 |  | Level 2 |  | Level 3
Gas Derivatives | $ | — |  |  | $ | 117,545 |  |  | $ | — |  |  | $ | — |  |  | $ | 405,781 |  |  | $ | — |
Interest Rate Swaps | $ | — |  |  | $ | (14,270) |  |  | $ | — |  |  | $ | — |  |  | $ | (1,219) |  |  | $ | — |

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

| December 31, 2020 |  | December 31, 2019
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Cash and Cash Equivalents | $ | 15,617 |  |  | $ | 15,617 |  |  | $ | 16,283 |  |  | $ | 16,283 |
Long-Term Debt (Excluding Debt Issuance Costs) | $ | 2,450,853 |  |  | $ | 2,638,251 |  |  | $ | 2,763,433 |  |  | $ | 2,619,676 |

Cash and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that is not actively traded is valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.
NOTE 19—DERIVATIVE INSTRUMENTS:
CNX enters into interest rate swap agreements to manage its exposure to interest rate volatility. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. The change in fair value of the interest rate swap agreements are accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings.
In March 2020, CNX entered into interest rate swaps related to $175,000 of borrowings under the Cardinal States Facility and CSG Holdings Facility (See Note 12 - Long-Term Debt). In order to manage exposure to interest rate volatility, each respective entity entered into an interest rate swap for the full outstanding principal amounts inclusive of a put option at 25 basis points. The underlying notional for each swap and put option reduces over time based upon an expected amortization profile for each respective credit facility. In addition, CSG Holdings entered into a call option commencing March 31, 2023.
In June 2019, CNX entered into an interest rate swap agreement related to $160,000 of borrowings under CNX’s Credit Facility (See Note 10 - Revolving Credit Facilities) which has the economic effect of modifying the variable-interest obligation into a fixed-interest obligation over a three-year period. In March 2020, this swap was terminated and replaced via a new interest rate swap, effective April 3, 2020, into a new four-year interest rate swap inclusive of a put option at zero basis points. Also executed in March 2020 was a new four-year $250,000 interest rate swap inclusive of a put option at zero basis points, effective April 3, 2020. Consistent with the previous interest rate swap agreement, the $250,000 interest rate swap was entered into to manage CNX's exposure to interest rate volatility.
CNX enters into financial derivative instruments (over-the-counter swaps) to manage its exposure to commodity price volatility. Typically, CNX “sells” swaps under which it receives a fixed price from counterparties and pays a floating market price. During the second quarter of 2020, CNX purchased, rather than sold, financial swaps for the period May through November of 2020 under which CNX will pay a fixed price to and receive a floating price from its hedge counterparties. Swaps purchased have the effect of reducing total hedged volumes for the period of the swap. Natural gas commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings.
CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.
None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if CNX's obligations with any of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with our counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value in the Consolidated Balance Sheets on a gross basis.
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Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions.
The total notional amounts of production of CNX's derivative instruments were as follows:

| December 31, |  | Forecasted to
| 2020 |  | 2019 |  | Settle Through
Natural Gas Commodity Swaps (Bcf) | 1,256.9 |  |  | 1,460.6 |  |  | 2025
Natural Gas Basis Swaps (Bcf) | 1,294.1 |  |  | 1,290.4 |  |  | 2026
Interest Rate Swaps | $ | 569,972 |  |  | $ | 160,000 |  |  | 2028

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

| December 31,
| 2020 |  | 2019
Current Assets: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 53,668 |  |  | $ | 234,238 |
Basis Only Swaps | 30,848 |  |  | 13,556 |
Interest Rate Swaps | 141 |  |  | — |
Total Current Assets | $ | 84,657 |  |  | $ | 247,794 |
Other Non-Current Assets: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 134,661 |  |  | $ | 288,543 |
Basis Only Swaps | 52,903 |  |  | 25,553 |
Interest Rate Swaps | 673 |  |  | — |
Total Other Non-Current Assets | $ | 188,237 |  |  | $ | 314,096 |
Current Liabilities: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 23,506 |  |  | $ | 345 |
Basis Only Swaps | 14,491 |  |  | 40,626 |
Interest Rate Swaps | 4,332 |  |  | 495 |
Total Current Liabilities | $ | 42,329 |  |  | $ | 41,466 |
Non-Current Liabilities: |  |  |
Commodity Derivative Instruments: |  |  |
Commodity Swaps | $ | 59,388 |  |  | $ | 9,693 |
Basis Only Swaps | 57,150 |  |  | 105,445 |
Interest Rate Swaps | 10,752 |  |  | 724 |
Total Non-Current Liabilities | $ | 127,290 |  |  | $ | 115,862 |

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

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Cash Received (Paid) in Settlement of Commodity Derivative Instruments: |  |  |  |  |
Natural Gas: |  |  |  |  |
Commodity Swaps | $ | 390,547 |  |  | $ | 82,899 |  |  | $ | (41,098) |
Basis Swaps | 70,670 |  |  | (13,119) |  |  | (28,622) |
Total Cash Received (Paid) in Settlement of Commodity Derivative Instruments | 461,217 |  |  | 69,780 |  |  | (69,720) |
Unrealized (Loss) Gain on Commodity Derivative Instruments: |  |  |  |  |
Natural Gas: |  |  |  |  |
Commodity Swaps | (407,308) |  |  | 406,472 |  |  | 33,026 |
Basis Swaps | 119,073 |  |  | (100,147) |  |  | 6,482 |
Total Unrealized (Loss) Gain on Commodity Derivative Instruments | (288,235) |  |  | 306,325 |  |  | 39,508 |
Gain (Loss) on Commodity Derivative Instruments: |  |  |  |  |
Natural Gas: |  |  |  |  |
Commodity Swaps | (16,761) |  |  | 489,371 |  |  | (8,072) |
Basis Swaps | 189,743 |  |  | (113,266) |  |  | (22,140) |
Total Gain (Loss) on Commodity Derivative Instruments | $ | 172,982 |  |  | $ | 376,105 |  |  | $ | (30,212) |

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

| For the Years Ended December 31,
| 2020 |  | 2019 |  |
Cash (Paid) Received in Settlement of Interest Rate Swaps | $ | (3,141) |  |  | $ | 223 |  |  |
Unrealized Loss on Interest Rate Swaps | (13,051) |  |  | (1,219) |  |  |
Loss on Interest Rate Swaps | $ | (16,192) |  |  | $ | (996) |  |  |

Cash Received (Paid) in Settlement of Commodity Derivative Instruments for the year ended December 31, 2020 includes $54,982 related to the monetization of certain NYMEX commodity swaps. The monetization resulted from reducing the contract swap prices of certain 2022, 2023 and 2024 NYMEX natural gas swap contracts. The notional quantities of the contracts were not changed by this monetization. Net proceeds received from the monetization are classified as operating cash flows in the Consolidated Statements of Cash Flows.
The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and normal sales exception and are not subject to derivative instrument accounting.
NOTE 20—COMMITMENTS AND CONTINGENT LIABILITIES:
CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, royalty accounting, damage to property, climate change, governmental regulations including environmental violations and remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CNX; however, such amounts cannot be reasonably estimated.
The 1992 Coal Industry Retiree Health Benefit Act (“Coal Act”), in Section 9711, requires coal companies that were providing health benefits to United Mine Workers of America (“UMWA”) retirees as of February 1993 to continue providing health benefits to such individuals, in substantially the same coverages, for as long as the last signatory operator remains in
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business. Section 9711 also requires any “related person” to be joint and severally liable for the provision of these health benefits. On May 1, 2020, the court in the Murray Energy Corporation (“Murray”) bankruptcy proceedings approved a settlement agreement between Murray and the UMWA that transferred to the UMWA 1992 Benefit Plan the Coal Act liabilities for retirees in Murray’s Section 9711 plan. The retirees transferred by Murray to the 1992 Benefit Plan include approximately 2,159 retirees allegedly traced to the December 2013 sale by CONSOL Energy Inc. to Murray Energy of the following possible last signatory operators: Consolidation Coal Company, McElroy Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Keystone Coal Mining Corp., and Eight-Four Coal Mining Company (the “Sold Subsidiaries”). On May 2, 2020, the Trustees of the UMWA 1992 Benefit Plan sued CNX and CONSOL Energy Inc. (“CONSOL”) in federal court contending that the Sold Subsidiaries were last signatory operators and that CNX and CONSOL are related persons to the Sold Subsidiaries and, as such, CNX and CONSOL are jointly and severally liable for the Coal Act health benefits allegedly owed to the eligible retirees traced to the Sold Subsidiaries. The 1992 Plan seeks, among other relief, a declaration that CNX and CONSOL are obligated to enroll the eligible retirees attributed to the Sold Subsidiaries in a Section 9711 Plan; that CNX and CONSOL are liable to post the security required by Section 9712; and, that CNX and CONSOL are liable to pay per beneficiary premiums until the eligible retirees are enrolled in a Section 9711 plan, and other fees, costs and disbursements under the Coal Act. We disagree with the suit filed by the UMWA 1992 Plan, have filed a Motion to Dismiss and intend to defend this action. Further, under the Separation and Distribution Agreement that was entered into at the time we spun-out our coal business in 2017, CONSOL agreed to indemnify CNX for all coal-related liabilities, including this lawsuit. With respect to this matter although a loss is possible, it is not probable, and accordingly no accrual has been recognized.
At December 31, 2020, CNX has provided the following financial guarantees, unconditional purchase obligations, and letters of credit to certain third-parties as described by major category in the following tables. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management believes that the commitments in the following table will expire without being funded, and therefore will not have a material adverse effect on financial condition.

| Amount of Commitment Expiration Per Period
| Total Amounts Committed |  | Less Than 1 Year |  | 1-3 Years |  | 3-5 Years |  | Beyond 5 Years
Letters of Credit: |  |  |  |  |  |  |  |  |
Firm Transportation | $ | 178,352 |  |  | $ | 178,352 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other | 6,950 |  |  | 6,950 |  |  | — |  |  | — |  |  | — |
Total Letters of Credit | 185,302 |  |  | 185,302 |  |  | — |  |  | — |  |  | — |
Surety Bonds: |  |  |  |  |  |  |  |  |
Employee-Related | 2,600 |  |  | 2,600 |  |  | — |  |  | — |  |  | — |
Environmental | 12,447 |  |  | 12,187 |  |  | 260 |  |  | — |  |  | — |
Financial Guarantees | 81,670 |  |  | 81,670 |  |  | — |  |  | — |  |  | — |
Other | 9,183 |  |  | 7,899 |  |  | 1,284 |  |  | — |  |  | — |
Total Surety Bonds | 105,900 |  |  | 104,356 |  |  | 1,544 |  |  | — |  |  | — |
Total Commitments | $ | 291,202 |  |  | $ | 289,658 |  |  | $ | 1,544 |  |  | $ | — |  |  | $ | — |

Excluded from the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business in November 2017. Although CONSOL Energy has agreed to indemnify CNX to the extent that CNX would be called upon to pay any of these liabilities, there is no assurance that CONSOL Energy will satisfy its obligations to indemnify CNX in the event that CNX is so called upon (See “Item 1A. Risk Factors” in this Form 10-K).
CNX enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded in the Consolidated Balance Sheets.
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As of December 31, 2020, the purchase obligations for each of the next five years and beyond were as follows:

Obligations Due | Amount
Less than 1 year | $ | 253,692 |
1 - 3 years | 431,282 |
3 - 5 years | 390,693 |
More than 5 years | 985,201 |
Total Purchase Obligations | $ | 2,060,868 |

NOTE 21—SEGMENT INFORMATION:
The Company reports segment information based on the “management” approach. The management approach designates the internal reporting used by management for making decisions and assessing performance as the source of the Company’s reportable segments.
The Company evaluates the performance of its reportable segments based on total revenue and other operating income, and operating expenses directly attributable to that segment. Certain expenses are managed outside the reportable segments and therefore are not allocated. These expenses include, but are not limited to, interest expense, impairment of exploration and production properties, impairment of goodwill and other corporate expenses such as selling, general and administrative costs.
CNX's principal activity is to produce pipeline quality natural gas for sale primarily to gas wholesalers and the Company has two reportable segments that conducts those operations: Shale and Coalbed Methane. The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, realized gain on commodity derivative instruments that were monetized prior to their settlement dates, exploration and production related other costs, impairments of exploration and production properties, as well as various other expenses that are managed outside the reportable segments as discussed above. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses.
Prior to the Merger of CNXM that occurred in September 2020 (See Note 4 - Acquisitions and Dispositions), CNX consisted of two principal business divisions: Exploration and Production (E&P) and Midstream. The E&P Division included four reportable segments, Marcellus Shale, Utica Shale, Coalbed Methane and Other Gas. Certain reclassifications of 2019 and 2018 segment information have been made to conform to the 2020 presentation.
Industry segment results for the year ended December 31, 2020 are:

|  | Shale |  | Coalbed Methane |  | Other |  |  |  |  |  |  |  |  |  | Consolidated |
Natural Gas, NGLs and Oil Revenue |  | $ | 781,038 |  |  | $ | 114,366 |  |  | $ | 1,341 |  |  |  |  |  |  |  |  |  |  | $ | 896,745 |  | (A)
Purchased Gas Revenue |  | — |  |  | — |  |  | 105,792 |  |  |  |  |  |  |  |  |  |  | 105,792 |  |
Gain (Loss) on Commodity Derivative Instruments |  | 337,269 |  |  | 39,884 |  |  | (204,171) |  |  |  |  |  |  |  |  |  |  | 172,982 |  | (B)
Other Operating Income |  | 64,710 |  |  | — |  |  | 17,749 |  |  |  |  |  |  |  |  |  |  | 82,459 |  | (C)
Total Revenue and Other Operating Income |  | $ | 1,183,017 |  |  | $ | 154,250 |  |  | $ | (79,289) |  |  |  |  |  |  |  |  |  |  | $ | 1,257,978 |  |
Total Operating Expense |  | $ | 709,036 |  |  | $ | 127,845 |  |  | $ | 860,863 |  |  |  |  |  |  |  |  |  |  | $ | 1,697,744 |  |
Earnings (Loss) Before Income Tax |  | $ | 473,981 |  |  | $ | 26,405 |  |  | $ | (1,103,217) |  |  |  |  |  |  |  |  |  |  | $ | (602,831) |  |
Segment Assets |  | $ | 6,068,933 |  |  | $ | 1,095,816 |  |  | $ | 877,015 |  |  |  |  |  |  |  |  |  |  | $ | 8,041,764 |  | (D)
Depreciation, Depletion and Amortization |  | $ | 416,441 |  |  | $ | 69,745 |  |  | $ | 15,635 |  |  |  |  |  |  |  |  |  |  | $ | 501,821 |  |
Capital Expenditures |  | $ | 474,545 |  |  | $ | 9,789 |  |  | $ | 2,957 |  |  |  |  |  |  |  |  |  |  | $ | 487,291 |  |

(A) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $167,390 to Direct Energy Business Marketing LLC, which comprises over 10% of revenue from contracts with external customers for the period.
(B) Included in Other is a realized gain on commodity derivative instruments of $83,997 related to the monetization of hedges (see Note 19 - Derivative Instruments for more information).
(C) Includes midstream revenue of $64,710 and equity in loss of unconsolidated affiliates of $688 for Shale and Other, respectively.
(D) Includes investments in unconsolidated equity affiliates of $16,022 .
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Industry segment results for the year ended December 31, 2019 are:

|  |  | Shale |  | Coalbed Methane |  | Other |  |  |  |  |  |  |  |  |  | Consolidated |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 1,199,276 |  |  | $ | 163,893 |  |  | $ | 1,156 |  |  |  |  |  |  |  |  |  |  | $ | 1,364,325 |  | (E)
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 94,027 |  |  |  |  |  |  |  |  |  |  | 94,027 |  |
Gain on Commodity Derivative Instruments |  |  | 62,418 |  |  | 7,335 |  |  | 306,352 |  |  |  |  |  |  |  |  |  |  | 376,105 |  |
Other Revenue and Operating Income |  |  | 74,314 |  |  | — |  |  | 13,678 |  |  |  |  |  |  |  |  |  |  | 87,992 |  | (F)
Total Revenue and Other Operating Income |  |  | $ | 1,336,008 |  |  | $ | 171,228 |  |  | $ | 415,213 |  |  |  |  |  |  |  |  |  |  | $ | 1,922,449 |  |
Total Operating Expense |  |  | $ | 787,488 |  |  | $ | 135,778 |  |  | $ | 813,207 |  |  |  |  |  |  |  |  |  |  | $ | 1,736,473 |  |
Earnings (Loss) Before Income Tax |  |  | $ | 548,520 |  |  | $ | 35,450 |  |  | $ | (524,286) |  |  |  |  |  |  |  |  |  |  | $ | 59,684 |  |
Segment Assets |  |  | $ | 6,527,245 |  |  | $ | 1,222,005 |  |  | $ | 1,311,556 |  |  |  |  |  |  |  |  |  |  | $ | 9,060,806 |  | (G)
Depreciation, Depletion and Amortization |  |  | $ | 427,219 |  |  | $ | 73,189 |  |  | $ | 8,055 |  |  |  |  |  |  |  |  |  |  | $ | 508,463 |  |
Capital Expenditures |  |  | $ | 1,175,091 |  |  | $ | 11,333 |  |  | $ | 6,175 |  |  |  |  |  |  |  |  |  |  | $ | 1,192,599 |  |

(E) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $214,980 to Direct Energy Business Marketing LLC and $147,540 to NJR Energy Services Company, each of which comprises over 10% of revenue from contracts with external customers for the period.
(F) Includes midstream revenue of $74,314 and equity in earnings of unconsolidated affiliates of $2,103 for Shale and Other, respectively.
(G) Includes investments in unconsolidated equity affiliates of $16,710.
Industry segment results for the year ended December 31, 2018 are:

|  |  | Shale |  | Coalbed Methane |  | Other |  |  |  |  |  | Consolidated |
Natural Gas, NGLs and Oil Revenue |  |  | $ | 1,349,196 |  |  | $ | 212,884 |  |  | $ | 15,857 |  |  |  |  |  |  | $ | 1,577,937 |  | (H)
Purchased Gas Revenue |  |  | — |  |  | — |  |  | 65,986 |  |  |  |  |  |  | 65,986 |  |
(Loss) Gain on Commodity Derivative Instruments |  |  | (60,326) |  |  | (8,768) |  |  | 38,882 |  |  |  |  |  |  | (30,212) |  |
Other Revenue and Operating Income |  |  | 89,781 |  |  | — |  |  | 26,942 |  |  |  |  |  |  | 116,723 |  | (I)
Total Revenue and Other Operating Income |  |  | $ | 1,378,651 |  |  | $ | 204,116 |  |  | $ | 147,667 |  |  |  |  |  |  | $ | 1,730,434 |  |
Total Operating Expense |  |  | $ | 751,673 |  |  | $ | 154,121 |  |  | $ | 321,169 |  |  |  |  |  |  | $ | 1,226,963 |  |
Earnings Before Income Tax |  |  | $ | 626,978 |  |  | $ | 49,995 |  |  | $ | 421,695 |  |  |  |  |  |  | $ | 1,098,668 |  |
Segment Assets |  |  | $ | 6,268,113 |  |  | $ | 1,272,457 |  |  | $ | 1,051,600 |  |  |  |  |  |  | $ | 8,592,170 |  | (J)
Depreciation, Depletion and Amortization |  |  | $ | 404,503 |  |  | $ | 77,004 |  |  | $ | 11,916 |  |  |  |  |  |  | $ | 493,423 |  |
Capital Expenditures |  |  | $ | 1,094,471 |  |  | $ | 17,083 |  |  | $ | 4,843 |  |  |  |  |  |  | $ | 1,116,397 |  |

(H) Included in Total Natural Gas, NGLs and Oil Revenue are sales of $219,472 to NJR Energy Services Company and $184,668 to Direct Energy Business Marketing LLC, each of which comprises over 10% of revenue from contracts with external customers for the period.
(I) Includes midstream revenue of $89,781 and equity in earnings of unconsolidated affiliates of $5,363 for Shale and Other, respectively.
(J) Includes investments in unconsolidated equity affiliates of $18,663.
Reconciliation of Segment Information to Consolidated Amounts:
Revenue and Other Operating Income:

|  | For the Years Ended December 31,
|  | 2020 |  | 2019 |  | 2018
Total Segment Revenue from Contracts with External Customers |  | $ | 1,067,247 |  |  | $ | 1,532,666 |  |  | $ | 1,733,704 |
Gain (Loss) on Commodity Derivative Instruments |  | 172,982 |  |  | 376,105 |  |  | (30,212) |
Other Operating Income |  | 17,749 |  |  | 13,678 |  |  | 26,942 |
Total Consolidated Revenue and Other Operating Income |  | $ | 1,257,978 |  |  | $ | 1,922,449 |  |  | $ | 1,730,434 |

NOTE 22—SUPPLEMENTAL GAS DATA (unaudited):
The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” The supplementary information summarized below presents the results of natural gas and oil activities for the E&P segment in accordance with the successful efforts method of accounting for production activities.
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Capitalized Costs:

| As of December 31,
| 2020 |  | 2019
Intangible Drilling Costs | $ | 4,965,252 |  |  | $ | 4,688,497 |
Gas Gathering Assets | 2,510,916 |  |  | 2,463,866 |
Proved Gas Properties | 1,253,094 |  |  | 1,208,046 |
Gas Wells and Related Equipment | 1,120,061 |  |  | 1,042,000 |
Unproved Gas Properties | 725,705 |  |  | 755,590 |
Other Gas Assets | 95,734 |  |  | 73,479 |
Total Property, Plant and Equipment | 10,670,762 |  |  | 10,231,478 |
Accumulated Depreciation, Depletion and Amortization | (3,852,593) |  |  | (3,317,442) |
Net Capitalized Costs | $ | 6,818,169 |  |  | $ | 6,914,036 |

Costs incurred for property acquisition, exploration and development (*):

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Property Acquisitions: |  |  |  |  |
Proved Properties | $ | 16,622 |  |  | $ | 36,710 |  |  | $ | 38,621 |
Unproved Properties | 8,060 |  |  | 24,760 |  |  | 36,248 |
Development** | 432,438 |  |  | 1,063,945 |  |  | 986,419 |
Exploration | 33,644 |  |  | 79,855 |  |  | 61,604 |
Total | $ | 490,764 |  |  | $ | 1,205,270 |  |  | $ | 1,122,892 |

__________
(*) Includes costs incurred whether capitalized or expensed.
(**) Includes development costs for midstream of $67 million, $325 million and $142 million for 2020, 2019 and 2018, respectively.
Results of Operations for Producing Activities:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Natural Gas, NGLs and Oil Revenue | $ | 896,745 |  |  | $ | 1,364,325 |  |  | $ | 1,577,937 |
Realized Gain (Loss) on Commodity Derivative Instruments | 461,217 |  |  | 69,780 |  |  | (69,720) |
Unrealized (Loss) Gain on Commodity Derivative Instruments | (288,235) |  |  | 306,325 |  |  | 39,508 |
Purchased Gas Revenue | 105,792 |  |  | 94,027 |  |  | 65,986 |
Total Revenue | 1,175,519 |  |  | 1,834,457 |  |  | 1,613,711 |
Lease Operating Expense | 40,407 |  |  | 65,443 |  |  | 95,139 |
Production, Ad Valorem and Other Fees | 24,196 |  |  | 27,461 |  |  | 32,750 |
Transportation, Gathering and Compression | 285,683 |  |  | 330,539 |  |  | 302,933 |
Purchased Gas Costs | 100,902 |  |  | 90,553 |  |  | 64,817 |
Impairment of Exploration and Production Properties | 61,849 |  |  | 327,400 |  |  | — |
Impairment of Undeveloped Properties | — |  |  | 119,429 |  |  | — |
Exploration Costs | 14,994 |  |  | 44,380 |  |  | 12,033 |
Depreciation, Depletion and Amortization | 501,821 |  |  | 508,463 |  |  | 493,423 |
Total Costs | 1,029,852 |  |  | 1,513,668 |  |  | 1,001,095 |
Pre-tax Operating Income | 145,667 |  |  | 320,789 |  |  | 612,616 |
Income Tax Expense | 42,098 |  |  | 149,167 |  |  | 120,073 |
Results of Operations for Producing Activities excluding Corporate and Interest Costs | $ | 103,569 |  |  | $ | 171,622 |  |  | $ | 492,543 |

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The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:

| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Production (MMcfe) | 511,072 |  |  | 539,149 |  |  | 507,104 |
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe) | $ | 1.75 |  |  | $ | 2.53 |  |  | $ | 3.11 |
Average Effects of Commodity Derivative Financial Settlements (per Mcfe) | $ | 0.74 |  |  | $ | 0.14 |  |  | $ | (0.15) |
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe) | $ | 2.49 |  |  | $ | 2.66 |  |  | $ | 2.97 |
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe) | $ | 0.08 |  |  | $ | 0.12 |  |  | $ | 0.19 |

During the years ended December 31, 2020, 2019 and 2018, the Company drilled 29.0, 75.7, and 83.9 net development wells, respectively. There were no net dry development wells in 2020 and 2018, and 1.0 net dry development well in 2019.
During the years ended December 31, 2020 and 2019, the Company drilled 2.0 and 5.0 net exploratory wells, respectively. During the year ended December 31, 2018, the Company drilled no net exploratory wells. There were no net dry exploratory wells in 2020, 2019 or 2018.
At December 31, 2020, there were 23.0 net development wells and 1.0 exploratory well that are drilled but uncompleted. Additionally, there are 2.0 net exploratory wells that have been completed and are awaiting final tie-in to production.
CNX is committed to provide 492.5 Bcf of gas under existing sales contracts or agreements over the course of the next four years. The Company expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.
Most of the Company's 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, the number of producing wells, developed acreage and undeveloped acreage:

| Gross(1) |  | Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest | 4,712 |  |  | 4,401 |
Producing Oil Wells - Working Interest | — |  |  | — |
Producing Gas Wells - Royalty Interest | 1,810 |  |  | — |
Producing Oil Wells - Royalty Interest | 152 |  |  | — |
Acreage Position: |  |  |
Proved Developed Acreage | 351,537 |  |  | 351,537 |
Proved Undeveloped Acreage | 43,713 |  |  | 43,713 |
Unproved Acreage | 4,986,196 |  |  | 3,637,982 |
Total Acreage | 5,381,446 |  |  | 4,033,232 |

____________
(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.
Proved Oil and Gas Reserves Quantities:
Annually, the preparation of natural gas reserves estimates is completed in accordance with CNX prescribed internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as multi-functional management review. As part of the annual review, management reviews and approves changes in the
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future development plan and the impact to proved-undeveloped locations to ensure that annual changes are aligned with the overall strategic business plan of the Company. A detailed review is completed to ensure that all proved undeveloped locations will be fully developed within five-years of the reserves booking. As part of the development plan review, management reviews current well production data, acreage position, downstream infrastructure availability, operational leases and other commitments, financial capacity to complete the development and individual project economics in expected future gas pricing scenarios. The input data verification includes reviews of the price and operating, and development cost assumptions as well as tax rates by jurisdiction used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a registered professional engineer in the state of West Virginia with over 16 years of experience in the oil and gas industry. The Company's gas reserves results, which are reported in the Supplemental Gas Data for the year ended December 31, 2020 Form 10-K, were audited by independent petroleum engineers, Netherland, Sewell & Associates, Inc. The technical person primarily responsible for overseeing the audit of the Company's reserves is a registered professional engineer in the state of Texas with over 13 years of experience in the oil and gas industry.
The gas reserves estimates are as follows:

|  |  |  |  |  | Condensate |  | Consolidated
|  | Natural Gas |  | NGLs |  | & Crude Oil |  | Operations
|  | (MMcf) |  | (Mbbls) |  | (Mbbls) |  | (MMcfe)
Balance December 31, 2017 (a) |  | 7,121,758 |  |  | 71,691 |  |  | 4,950 |  |  | 7,581,612 |
Revisions (b) |  | 313,091 |  |  | 441 |  |  | 865 |  |  | 320,925 |
Price Changes |  | 28,100 |  |  | 32 |  |  | 4 |  |  | 28,315 |
Extensions and Discoveries (c) |  | 839,268 |  |  | 16,247 |  |  | 4,010 |  |  | 960,808 |
Production |  | (468,228) |  |  | (6,011) |  |  | (468) |  |  | (507,104) |
Sales of Reserves In-Place (d) |  | (715,088) |  |  | (17,252) |  |  | (1,100) |  |  | (825,196) |
Balance December 31, 2018 (a) |  | 7,436,338 |  |  | 65,904 |  |  | 8,261 |  |  | 7,881,335 |
Revisions (e) |  | (521,617) |  |  | 5,926 |  |  | (5,418) |  |  | (518,570) |
Price Changes |  | (40,773) |  |  | (740) |  |  | (5) |  |  | (45,246) |
Extensions and Discoveries (c) |  | 1,569,813 |  |  | 10,182 |  |  | 2,732 |  |  | 1,647,297 |
Production |  | (505,355) |  |  | (5,428) |  |  | (204) |  |  | (539,149) |
Balance December 31, 2019 (a) |  | 7,938,406 |  |  | 75,844 |  |  | 5,366 |  |  | 8,425,667 |
Revisions (f) |  | 407,836 |  |  | 51,857 |  |  | 3,525 |  |  | 740,129 |
Price Changes |  | (1,019,523) |  |  | (50,456) |  |  | (4,946) |  |  | (1,351,934) |
Extensions and Discoveries (c) |  | 2,188,773 |  |  | 9,299 |  |  | 400 |  |  | 2,246,968 |
Production |  | (481,426) |  |  | (4,677) |  |  | (264) |  |  | (511,072) |
Balance December 31, 2020 (a) |  | 9,034,066 |  |  | 81,867 |  |  | 4,081 |  |  | 9,549,758 |
Proved developed reserves: |  |  |  |  |  |  |  |
December 31, 2018 |  | 4,242,579 |  |  | 40,180 |  |  | 1,870 |  |  | 4,494,878 |
December 31, 2019 |  | 4,473,534 |  |  | 59,800 |  |  | 1,087 |  |  | 4,838,858 |
December 31, 2020 |  | 4,939,283 |  |  | 42,204 |  |  | 1,207 |  |  | 5,199,748 |
Proved undeveloped reserves: |  |  |  |  |  |  |  |
December 31, 2018 |  | 3,193,759 |  |  | 25,724 |  |  | 6,391 |  |  | 3,386,457 |
December 31, 2019 |  | 3,464,873 |  |  | 16,044 |  |  | 4,278 |  |  | 3,586,809 |
December 31, 2020 |  | 4,094,783 |  |  | 39,664 |  |  | 2,874 |  |  | 4,350,010 |

__________
(a) Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years
129

from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods.
(b) The upward revision for 2018 of 321 Bcfe is primarily due to a 472 Bcfe upward revision from increased performance through our continued focus on optimization. This is partially offset by a 151 Bcfe downward revision due to plan changes.
(c) Extensions and Discoveries in 2018, 2019, and 2020 are due to the addition of wells on the Company's Shale acreage more than one offset location away with continued use of reliable technology. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sits and data exchanges to confirm continuity of the formation. Total proved extensions and discoveries are a combination of proved developed and proved undeveloped reserves; and, extensions and discoveries for proven developed reserves are associated with non-operated assets and exploratory wells. In 2020 and 2019, the Company added 70 Bcfe and 77 Bcfe, respectively, related to exploratory and non-operated wells.
(d) The sales of reserves in-place is related to the divestiture of our Utica JV assets and substantially all of our conventional properties. Refer to Note 4 - Acquisitions and Dispositions for more information.
(e) The downward revisions in 2019 are due to changes in our five-year development plan due to increased dry gas investment which increased dry gas proved undeveloped reserves and decreased wet gas investment which lowered wet gas proved undeveloped reserves. The investment shift was a result of a significant decrease in forecasted liquids price realizations in the five-year plan. These five-year plan changes resulted in the removal of 872 Bcfe in reserves for wet gas investment. There was additionally a reduction of 304 Bcfe related to removal of proved undeveloped locations removed from our plans due to the SEC five-year development rule. These downward revisions were partially offset by efficiencies in operations investment in dry gas properties which increased reserves by 657 Bcfe.
(f) Upward revisions in 2020 are due to performance revisions of 579 Bcfe related to production performance and an 853 Bcfe increase in reserves due to a decrease in operating costs in 2020. These upward revisions were partially offset by negative revisions of 677 Bcfe due to changes in our development plan related to the removal of four Utica wells and 23 Marcellus wells from our development plan.

|  | For the Year
|  | Ended
|  | December 31,
|  | 2020
Proved Undeveloped Reserves (MMcfe) |  |
Beginning Proved Undeveloped Reserves |  | 3,586,809 |
Undeveloped Reserves Transferred to Developed (a) |  | (1,152,598) |
Price Revisions |  | (380,200) |
Revisions Due to Plan Changes (b) |  | (691,054) |
Revisions Due to Changes Due to Well Performance (c) |  | 810,727 |
Extension and Discoveries (d) |  | 2,176,326 |
Ending Proved Undeveloped Reserves(e) |  | 4,350,010 |

_________
(a) During 2020, various exploration and development drilling and evaluations were completed. Approximately, $257,952 of capital was spent in the year ended December 31, 2020 related to undeveloped reserves that were transferred to developed.
(b) The downward revisions for 2020 plan changes is due to the removal of 88 Bcfe of reserves related to 4 Utica wells and 579 Bcfe of reserves related to 23 Marcellus wells which were removed from our development plan.
(c) The upward revisions due to a 342 Bcfe increase in reserves of liquids rich Marcellus production which requires processing due to a reduction in the Company's operating costs as a result of the CNXM take-in transaction completed in 2020. The remaining portion is due to production performance.
(d) Extensions and discoveries are due mainly to the addition of 1,465 Bcfe related to 47 net Marcellus wells within our Southwest Pennsylvania and West Virginia dry gas operations and 711 Bcfe of 23 net Utica wells within our Central Pennsylvania and Southwest Pennsylvania operations. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sites and data exchanges to confirm continuity of the formation.
(e) Included in proved undeveloped reserves at December 31, 2020 are approximately 320,987 MMcfe of reserves that have been reported for more than five years. These reserves are all attributable to acreage within the current operating plan
130

identified by the life-of-mine timing maps for the Buchanan mine. The annual increase in proved undeveloped gob reserves is a result of a change in planned mining activity, which includes an expanded mining footprint, partially offset by the conversion to proved developed gob reserves. These reserves specifically relate to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine that was sold in March 2016 to Coronado IV LLC with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons constitute the specific circumstances that exist to continue recognizing these reserves for CNX.
The following table indicates the changes to the Company's suspended exploratory well costs for the three years ended December 31, 2020:

| 2020 |  | 2019 |  | 2018
Balance, Beginning of Period | $ | 8,984 |  |  | $ | 8,178 |  |  | $ | 6,388 |
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves | 28,336 |  |  | 66,409 |  |  | 49,213 |
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves | (28,258) |  |  | (65,603) |  |  | (46,614) |
Capitalized Exploratory Well Costs Charged to Expense | — |  |  | — |  |  | (809) |
Balance, End of Period | $ | 9,062 |  |  | $ | 8,984 |  |  | $ | 8,178 |

At December 31, 2020 there was one well pending the determination of proved reserves. The $9,062 of exploratory well costs capitalized for more than one year is related to one partially constructed well that the Company is currently evaluating to determine the most economic approach to access the natural gas reserves. The company expects to make a determination in 2021 to either finalize the well or to access the natural gas reserves from an alternative location.
CNX proved natural gas reserves are located in the United States.
Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.
The standardized measure is intended to provide a better means for comparing the value of CNX proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.

| December 31,
| 2020 |  | 2019 |  | 2018
Future Cash Flows (a) |  |  |  |  |
Revenues | $ | 16,577,563 |  |  | $ | 19,489,588 |  |  | $ | 26,610,100 |
Production Costs | (6,071,763) |  |  | (7,903,120) |  |  | (7,730,451) |
Development Costs (b) | (1,957,519) |  |  | (1,121,073) |  |  | (1,600,128) |
Income Tax Expense | (2,235,205) |  |  | (2,720,994) |  |  | (4,147,075) |
Future Net Cash Flows | 6,313,076 |  |  | 7,744,401 |  |  | 13,132,446 |
Discounted to Present Value at a 10% Annual Rate | (3,677,340) |  |  | (4,673,932) |  |  | (8,476,989) |
Total Standardized Measure of Discounted Net Cash Flows | $ | 2,635,736 |  |  | $ | 3,070,469 |  |  | $ | 4,655,457 |

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_________
(a) For 2020, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2020, adjusted for energy content and a regional price differential. For 2020, this adjusted natural gas price was $1.70 per Mcf, the adjusted oil price was $35.61 per barrel and the adjusted NGL price was $13.18 per barrel. In 2020, as the result of the CNXM take-in transaction (see Note 4 - Acquisitions and Dispositions), there was a change in production costs and development costs. Historically the production costs included contractual CNXM rates but in 2020 this was replaced with actual operating costs of the midstream infrastructure. Additionally, our development costs in 2020 include capital related to connecting undeveloped Shale wells to the midstream gathering systems; in prior years this was captured within the CNXM contractual rate within production costs. These changes resulted in an increase of $932 million to the current year Standardized Measure of Discounted Net Cash Flows.
(b) Development costs for 2020 include $402,174 of plugging and abandonment costs and $286,724 of Midstream capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $18,357 and $231,512, respectively. The addition of Midstream capital is the result of the Merger that occurred on September 28, 2020 (See Note 4 - Acquisitions and Dispositions).
For 2019, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2019, adjusted for energy content and a regional price differential. For 2019, this adjusted natural gas price was $2.24 per Mcf, the adjusted oil price was $44.31 per barrel and the adjusted NGL price was $19.10 per barrel.
For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2018, adjusted for energy content and a regional price differential. For 2018, this adjusted natural gas price was $3.28 per Mcf, the adjusted oil price was $51.68 per barrel and the adjusted NGL price was $27.58 per barrel.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:

| December 31,
| 2020 |  | 2019 |  | 2018
Balance at Beginning of Period | $ | 3,070,469 |  |  | $ | 4,655,457 |  |  | $ | 3,131,398 |
Net Changes in Sales Prices and Production Costs | (819,247) |  |  | (2,826,725) |  |  | 1,732,229 |
Sales Net of Production Costs | (719,441) |  |  | (1,130,685) |  |  | (995,630) |
Net Change Due to Revisions in Quantity Estimates | 322,820 |  |  | (252,796) |  |  | 307,030 |
Net Change Due to Extensions, Discoveries and Improved Recovery | 268,196 |  |  | 654,027 |  |  | 534,052 |
Development Costs Incurred During the Period | 434,273 |  |  | 739,874 |  |  | 844,081 |
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period | (129,642) |  |  | (323,922) |  |  | (434,817) |
Purchase of Reserves In-Place | — |  |  | — |  |  | 209,630 |
Sales of Reserves In-Place | — |  |  | — |  |  | (434,103) |
Changes in Estimated Future Development Costs | (499,316) |  |  | (24,469) |  |  | (49,294) |
Net Change in Future Income Taxes | 138,404 |  |  | 409,797 |  |  | (507,410) |
Timing and Other | 390,391 |  |  | 586,591 |  |  | (69,087) |
Accretion | 178,829 |  |  | 583,320 |  |  | 387,378 |
Total Discounted Cash Flow at End of Period | $ | 2,635,736 |  |  | $ | 3,070,469 |  |  | $ | 4,655,457 |

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Supplemental Quarterly Information (unaudited):
(Dollars in thousands, except per share data)

| Three Months Ended
| March 31, |  | June 30, |  | September 30, |  | December 31,
| 2020 |  | 2020 |  | 2020 |  | 2020
Revenue (a) | $ | 411,401 |  |  | $ | 145,088 |  |  | $ | 61,609 |  |  | $ | 622,131 |
Expenses (b) | $ | 149,004 |  |  | $ | 125,548 |  |  | $ | 142,327 |  |  | $ | 134,775 |
Net (Loss) Income (c) | $ | (305,222) |  |  | $ | (130,487) |  |  | $ | (188,793) |  |  | $ | 195,758 |
Net (Loss) Income Attributable to CNX Resources Shareholders | $ | (329,086) |  |  | $ | (145,749) |  |  | $ | (204,698) |  |  | $ | 195,758 |
(Loss) Earnings Per Share: |  |  |  |  |  |  |
Basic (Loss) Earnings Per Share | $ | (1.76) |  |  | $ | (0.78) |  |  | $ | (1.03) |  |  | $ | 0.88 |
Diluted (Loss) Earnings Per Share | $ | (1.76) |  |  | $ | (0.78) |  |  | $ | (1.03) |  |  | $ | 0.87 |

| Three Months Ended
| March 31, |  | June 30, |  | September 30, |  | December 31,
| 2019 |  | 2019 |  | 2019 |  | 2019
Revenue (a) | $ | 275,234 |  |  | $ | 602,109 |  |  | $ | 526,681 |  |  | $ | 504,747 |
Expenses (b) | $ | 147,928 |  |  | $ | 153,835 |  |  | $ | 153,833 |  |  | $ | 182,035 |
Net (Loss) Income (c) | $ | (64,651) |  |  | $ | 192,694 |  |  | $ | 143,960 |  |  | $ | (240,055) |
Net (Loss) Income Attributable to CNX Resources Shareholders | $ | (87,337) |  |  | $ | 162,477 |  |  | $ | 115,538 |  |  | $ | (271,408) |
(Loss) Earnings Per Share: |  |  |  |  |  |  |
Basic (Loss) Earnings Per Share | $ | (0.44) |  |  | $ | 0.85 |  |  | $ | 0.62 |  |  | $ | (1.45) |
Diluted (Loss) Earnings Per Share | $ | (0.44) |  |  | $ | 0.84 |  |  | $ | 0.61 |  |  | $ | (1.45) |

_________
(a) Includes natural gas, NGLs, and oil revenue; gain (loss) on commodity derivative instruments, purchased gas revenue and midstream revenue.
(b) Includes exploration and production costs and other operating expense; excludes depreciation, depletion and amortization, impairment charges, selling, general and administrative, gain (loss) on debt extinguishment, interest expense and other expense.
(c) Includes impairment charges of $61,849 and $473,045 that were recorded during the three months ended March 31, 2020 related to CNX's exploration and production properties and goodwill, respectively, and $327,400 and $119,429 that were recorded during the three months ended December 31, 2019 related to CNX's exploration and production properties and unproved properties, respectively. See Note 1 - Significant Accounting Policies in Item 8 of this Form 10-K for additional information.
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ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A.CONTROLS AND PROCEDURES
Disclosure controls and procedures. CNX, under the supervision and with the participation of its management, including CNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Form 10-K. Based on that evaluation, CNX’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2020 to ensure that information required to be disclosed by CNX in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CNX in such reports is accumulated and communicated to CNX’s management, including CNX’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Management's Annual Report on Internal Control Over Financial Reporting. CNX's management is responsible for establishing and maintaining adequate internal control over financial reporting. CNX's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
CNX's internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of CNX; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CNX's assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of CNX's internal control over financial reporting as of December 31, 2020. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO) in Internal Control-Integrated Framework. Based on management's assessment and those criteria, management has concluded that CNX maintained effective internal control over financial reporting as of December 31, 2020.
The effectiveness of CNX's internal control over financial reporting as of December 31, 2020 has been audited by Ernst & Young, LLP, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II. Item 9A of this Annual Report on Form 10-K.
Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
134

Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of CNX Resources Corporation
Opinion on Internal Control over Financial Reporting
We have audited CNX Resources Corporation and Subsidiaries’ internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, CNX Resources Corporation and Subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of CNX Resources Corporation and Subsidiaries as of December 31, 2020 and 2019, and the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2020 and the related notes and financial statement schedule listed in the Index at Item 15 (a) (2) of the Company and our report dated February 9, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 9, 2021
135

ITEM 9B.OTHER INFORMATION
None.
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated herein by reference from the information under the captions “PROPOSAL NO. 1-ELECTION OF DIRECTORS-Biographies of Nominees,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION and “DELINQUENT SECTION 16 REPORTS” in the Company's Proxy Statement for the annual meeting of shareholders to be held on May 6, 2021 (the “Proxy Statement”).
Information About Our Executive Officers
The following is a list, as of February 1, 2021, of CNX executive officers, their ages and their positions and offices held with CNX.

Name |  | Age |  | Position
Nicholas J. DeIuliis |  | 52 |  | President and Chief Executive Officer
Donald W. Rush |  | 38 |  | Executive Vice President and Chief Financial Officer
Chad A. Griffith |  | 43 |  | Executive Vice President and Chief Operating Officer
Olayemi Akinkugbe |  | 46 |  | Executive Vice President and Chief Excellence Officer
Alexander Reyes |  | 49 |  | Executive Vice President, General Counsel and Corporate Secretary

Nicholas J. DeIuliis has served as a Director and the Chief Executive Officer of CNX Resources Corporation since May 7, 2014. He was appointed President of the Company on February 23, 2011. Including the period prior to the separation of CONSOL Energy Inc. into two separate companies, Mr. DeIuliis has more than 30 years of experience with the Company and in that time has held the positions of President and Chief Executive Officer, Chief Operating Officer, Senior Vice President - Strategic Planning, and earlier in his career various engineering positions. He was a Director, President and Chief Executive Officer of CNX Gas Corporation from its creation in 2005 through 2009. Mr. DeIuliis is a registered engineer in the Commonwealth of Pennsylvania and a member of the Pennsylvania bar.
Donald W. Rush has served as the Executive Vice President and Chief Financial Officer of CNX Resources Corporation since August 2, 2017. In this role, he is responsible for development and execution of the Company's financial policies and strategy, including risk management, budgeting and planning, and compliance and reporting. Mr. Rush held the same position at CONSOL Energy Inc. prior to its separation into two separate companies. He previously served as Vice President of Energy Marketing where he oversaw the Company's commercial functions, including mergers and acquisitions, gas marketing and transportation, in addition to holding other strategy and planning, business development and engineering positions during his 13 years with the Company. He successfully guided the Company through every significant transaction during its transition into a pure play natural gas exploration and production company. Mr. Rush holds a B.S in civil engineering from the University of Pittsburgh and an M.B.A from Carnegie Mellon University’s Tepper School of Business.
Chad A. Griffith has served as the Executive Vice President and Chief Operating Officer of CNX Resources Corporation since July 30, 2019. In this role, he is responsible for daily management of the Company's asset base and safe and effective execution of its operational plan. Before being appointed to his current position, Mr. Griffith served as Vice President, Commercial and Vice President of Marketing of CNX from January 2018 to July 2019 and prior to that Mr. Griffith served as the Director of Marketing of CNX from November 2015 to January 2018. He was the Director of Diversified Business Units at CNX from April 2014 to November 2015. Mr. Griffith and holds a bachelor’s degree in physics from Frostburg State University, a law degree from West Virginia University College of Law, and an M.B.A. from Carnegie Mellon University’s Tepper School of Business. Mr. Griffith is a licensed attorney in Maryland and licensed, but inactive, in West Virginia.
Olayemi Akinkugbe has served as the Executive Vice President and Chief Excellence Officer of CNX Resources Corporation since July 30, 2019. As the Chief Excellence Officer of CNX, Mr. Akinkugbe oversees all operational and corporate support functions for the company. In this role, he is responsible for providing services to facilitate safe, environmentally compliant and efficient operational execution, rigorous corporate spend management, and overall daily administration of the enterprise. Prior to assuming this role, Mr. Akinkugbe served as Director Virginia Operations at CNX, a
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role he assumed in July 2018. Mr. Akinkugbe served as Director Business Development from September 2017 through July 2018, General Manager - Planning and Petroleum Reserves from February 2014 through September 2017, and served in various other positions, including with the Engineering Department, throughout his tenure at CNX, which started in 2003. Mr. Akinkugbe holds an undergraduate degree in mineral engineering, a master’s degree in engineering with a specialty in rock mechanics from West Virginia University, and an M.B.A. from Carnegie Mellon University’s Tepper School of Business.
Alexander Reye s has served as the Executive Vice President, General Counsel, and Corporate Secretary of CNX Resources Corporation since December 21, 2020. Mr. Reyes has a breadth of corporate legal and business expertise in the energy industry. He first joined CNX in 2006, and spent 14 years with the company, with responsibilities ranging from legal management of major transactions to leading the Company’s Land department. Before rejoining CNX to become General Counsel, for much of 2020 Alex served as Chair of the Corporate Practice Group of Pittsburgh-based Leech Tishman Fuscaldo & Lampl, LLC. He began his career at Buchanan Ingersoll PC where his practice focused on mergers and acquisitions, joint ventures, securities, financings, and corporate governance. He is a graduate of the Duquesne University School of Law where he served as an editor of The Duquesne Law Review. Mr. Reyes holds a Bachelors of Business Administration degree in finance from The George Washington University.
CNX has a written Code of Employee Business Conduct and Ethics that applies to CNX's Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer), Chief Accounting Officer (Principal Accounting Officer) and others. The Code of Employee Business Conduct and Ethics is available on CNX's website at www.cnx.com. Any amendments to, or waivers from, a provision of our Code of Employee Business Conduct and Ethics that applies to our Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer and that relates to any element enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website at www.cnx.com.
By certification dated May 27, 2020, CNX's Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the required Sarbanes-Oxley Act, Section 302 certifications regarding the quality of our public disclosures were filed by CNX Resources as exhibits to this Form 10-K.
ITEM 11.EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the information under the captions “BOARD OF DIRECTORS AND COMPENSATION INFORMATION and “EXECUTIVE COMPENSATION INFORMATION” (excluding the Compensation Committee Report) in the Proxy Statement.
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference from the information under the captions “BENEFICIAL OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CNX EQUITY COMPENSATION PLAN” in the Proxy Statement.
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information requested by this Item is incorporated by reference from the information under the caption “PROPOSAL NO. 1-ELECTION OF DIRECTORS - Related Party Policy and Procedures and PROPOSAL NO. 1 - ELECTION OF DIRECTORS - Determination of Director Independence in the Proxy Statement.
ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference from the information under the caption “ACCOUNTANTS AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
In reviewing any agreements incorporated by reference in this Form 10-K or filed with this Form 10-K, please remember that such agreements are included to provide information regarding their terms. They are not intended to be a source of financial, business or operational information about CNX or any of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of CNX or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.

(a)(1) |  | Financial Statements Contained in Item 8 hereof.
(a)(2) |  | Financial Statement Schedule-Schedule II Valuation and Qualifying Accounts contained below, following the signature page.
(a)(3) |  | Exhibits and Exhibit Index.
2.1 |  | Separation and Distribution Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.2 |  | Tax Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.3 |  | Employee Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.4 |  | Intellectual Property Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
2.5 |  | Agreement and Plan of Merger, dated as of July 26, 2020, by and among the Company, CNX Midstream Partners LP, CNX Midstream GP LLC and CNX Resources Holdings LLC, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on July 27, 2020.
3.1 |  | Restated Certificate of Incorporation of the Company, incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
3.2 |  | Certificate of Amendment to the Restated Certificate of Incorporation of the Company, incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
3.3 |  | Amended and Restated Bylaws of the Company, incorporated by reference to Exhibit 3.2 to Form 8-K (file no. 001-14901) filed on April 10, 2019.
4.1 |  | Description of the Company’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934, incorporated by reference to Exhibit 4.1 to Form 10-K (file no. 001-14901) filed on February 10, 2020.
4.2 |  | Indenture, dated as of April 16, 2014, by and among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, a national banking association, as trustee, with respect to the 5.875% Senior Notes due 2022, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
4.3 |  | Indenture, dated as of March 14, 2019, by and among the Company, the subsidiary guarantors party thereto and UMB Bank, N.A., a national banking association, as trustee, with respect to the 7.250% Senior Notes due 2027, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on March 14, 2019.
4.4 |  | Registration Rights Agreement, dated as of April 16, 2014, by and among the Company, the guarantors signatory thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
4.5 |  | Registration Rights Agreement, dated as of August 12, 2014, by and among the Company, the guarantors signatory thereto and Goldman, Sachs & Co., as the initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 12, 2014.

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4.6 |  | Indenture, dated as of May 1, 2020, by and among the Company, the subsidiary guarantors party thereto and UMB Bank, N.A., as trustee., incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on May 4, 2020.
4.7 |  | Indenture, dated as of November 30, 2020, by and among the Company, the subsidiary guarantors party thereto and UMB Bank, N.A., as Trustee., incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on November 30, 2020.
4.8 |  | Indenture, dated as of March 16, 2018, among CNX Midstream Partners LP, CNX Midstream Finance Corp., the guarantors party thereto and UMB Bank, N.A., as Trustee., incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-36635) filed on March 16, 2018.
10.1 |  | Second Amended and Restated Credit Agreement, dated as of March 8, 2018, by and among the Company, certain of its subsidiaries, PNC Bank, National Association, as administrative agent and collateral agent, JPMorgan Chase Bank, N.A., as syndication agent and the lender parties thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 12, 2018.
10.2 |  | Waiver No. 1 to Second Amended and Restated Credit Agreement, dated as of February 27, 2019, by and among the Company, the guarantors party thereto, the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent, and PNC Bank, National Association, as administrative agent and collateral agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 4, 2019.
10.3 |  | Amendment No. 1, dated as of April 24, 2019, to the Second Amended and Restated Credit Agreement, dated as of March 8, 2018, by and among the Company, the guarantors party thereto, the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent, and PNC Bank, National Association, as administrative agent and collateral agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on April 30, 2019.
10.4 |  | Amendment No. 2, dated as of October 28, 2019, to the Second Amended and Restated Credit Agreement, dated as of March 8, 2018, by and among the Company, the guarantors party thereto, the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent, and PNC Bank, National Association, as administrative agent and collateral agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on October 29, 2019.
10.5 |  | Amendment No. 4, dated as of April 24, 2020, to the Second Amended and Restated Credit Agreement, dated as of March 8, 2018, by and among the Company, the guarantors party thereto, the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent, and PNC Bank, National Association, as administrative agent and collateral agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on April 28, 2020.
10.6 |  | Transition Services Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
10.7 |  | CNX Resources Corporation to CONSOL Energy Inc. Trademark License Agreement dated as of November 28, 2017, by and between the Company and CONSOL Energy Inc., incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
10.8 |  | CONSOL Energy Inc. to CNX Resources Corporation Trademark License Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Energy Inc., incorporated by reference to Exhibit 10.3 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
10.9 |  | Exchange Agreement, dated as of January 29, 2020, by and among CNX Midstream Partners LP, CNX Midstream GP LLC, and CNX Gas Company LLC, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on January 30, 2020.
10.1 0 |  | Form of Confirmation of Base Capped Call Transaction, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 4, 2020.
10.11 |  | Form of Confirmation of Additional Capped Call Transaction, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on May 4, 2020.
10.12 |  | Support Agreement, dated as of July 26, 2020, by and among CNX Midstream Partners LP, CNX Gas Company LLC and CNX Gas Holdings, Inc. incorporated by reference to Exhibit 10.1 to Form 8-K (file number 001-14901) filed on July 27, 2020.
10.13 |  | Purchase Agreement, dated as of April 28, 2020, by and among the Company, the subsidiary guarantors party thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC as representatives of the several initial purchasers named therein., incorporated by reference to Exhibit 1.1 to Form 8-K (file no. 001-14901) filed on May 4, 2020.
10.14 |  | Purchase Agreement, dated as of September 8, 2020 by and among the Company, the subsidiary guarantors party thereto and BofA Securities, Inc. and Wells Fargo Securities, LLC, as representatives of the initial purchasers named therein., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on September 9, 2020.
10.15 |  | Purchase Agreement, dated as of November 24, 2020 by and among the Company, the subsidiary guarantors party thereto and BofA Securities, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on November 25, 2020.

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10.16 |  | Credit Agreement dated as of March 8, 2018, among CNX Midstream Partners LP, certain of its subsidiaries, PNC Bank, National Association, as administrative agent and collateral agent, JPMorgan Chase Bank, N.A., as syndication agent and the lender parties thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-36635) filed on March 12, 2018.
10.17 |  | Amendment No. 1 to Credit Agreement, dated as of March 15, 2018, to the Credit Agreement, dated as of March 8, 2018, among CNX Midstream Partners LP, certain of its subsidiaries, PNC Bank, National Association, as administrative agent and collateral agent, JPMorgan Chase Bank, N.A. as syndication agent and the lender parties thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-36635) filed on March 16, 2018.
10.18 |  | Amendment No. 2 to Credit Agreement, dated as of April 24, 2019, to the Credit Agreement, dated as of March 8, 2018, among CNX Midstream Partners LP, certain of its subsidiaries, PNC Bank, National Association, as administrative agent and collateral agent, JPMorgan Chase Bank, N.A. as syndication agent and the lender parties thereto., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-36635) filed on April 30, 2019.
10.19 |  | Limited Consent and Amendment to Credit Agreement, dated December 22, 2017, by and among CONE Midstream Partners LP, as Borrower, certain subsidiaries of the Borrower as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and other lender parties thereto, incorporated by reference to Exhibit 10.10 to Form 10-K (file no. 001-36635) filed on February 7, 2018.
10.20 |  | Purchase and Sale Agreement, dated as of February 7, 2018, by and among CNX Midstream Partners LP, CNX Midstream DevCo I LP, CNX Midstream DevCo III LP, CNX Gathering LLC, and, for certain purposes, CNX Midstream DevCo I GP LLC, CNX Midstream DevCo III GP LLC and CNX Midstream Operating Company LLC, incorporated by reference to Exhibit 10.75 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
10.21* |  | Letter Agreement, dated August 24, 2007, by and between the Company and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.
10.22* |  | Change in Control Agreement, dated as of December 30, 2008, by and between the Company and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.7 to Form 10-K (file no. 001-14901) for the year ended December 31, 2008, filed on February 17, 2009.
10.23* |  | Change in Control Severance Agreement, dated August 24, 2015, between the Company and Donald W. Rush, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
10.24* |  | Change in Control Severance Agreement, dated October 28, 2019, by and between the Company and Chad A. Griffith, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2019, filed on October 29, 2019.
10.25* |  | Change in Control Severance Agreement, dated October 28, 2019, by and between the Company and Olayemi Akinkugbe, incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2019, filed on October 29, 2019.
10.26* |  | Form of Indemnification Agreement for Directors and Executive Officers of the Company, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
10.27* |  | Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
10.28* |  | CNX Resources Corporation Equity Incentive Plan, as amended and restated effective January 26, 2018, incorporated by reference to Exhibit 10.48 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
10.29* |  | Amended and Restated CNX Resources Corporation Executive Annual Incentive Plan, incorporated by reference to Exhibit 10.49 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
10.30* |  | CNX Resources Corporation Amended and Restated Equity and Incentive Compensation Plan, effective May 6, 2020, incorporated by reference to Exhibit 99.1 to Form 8-K (file no. 001-14901) filed on May 7, 2020.
10.31* |  | Amendment to CNX Resources Corporation Amended and Restated Equity and Incentive Compensation Plan, effective September 28, 2020, incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-8 filed on September 28, 2020.
10.32* |  | Form of Non-Qualified Stock Option Award Agreement for Employees (February 17, 2009 and through 2012), incorporated by reference to Exhibit 10.28 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
10.33* |  | Form of Non-Qualified Performance Stock Option Agreement for Employees, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on June 21, 2010.
10.34* |  | Form of Employee Nonqualified Stock Option Agreement (May 26, 2016), incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2016, filed on July 29, 2016.
10.35* |  | Form of Non-Qualified Stock Option Agreement for Directors, incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2019, filed on July 30, 2019.

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10.36* |  | Form of CNX Resources Corporation Non-Employee Director Non-Qualified Stock Option agreement, incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2020, filed on August 3, 2020.
10.37* |  | Form of Non-Qualified Stock Option Agreement for Employees (for 2020 awards), incorporated by reference to Exhibit 10.31 to Form 10-K (file no. 001-14901) for the year ended December 31, 2019, filed on February 10, 2020.
10.38* |  | Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.5 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2019, filed on July 30, 2019.
10.39* |  | Form of Restricted Stock Unit Award Under CNX Resources Corporation Amended and Restated Equity and Incentive Compensation Plan for Non-Employee Directors, incorporated by reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2020, filed on August 3, 2020.
10.40* |  | Form of Restricted Stock Unit Award Agreement for CEO (for 2019 awards), incorporated by reference to Exhibit 10.37 to Form 10-K (file no. 001-14901) for the year ended December 31, 2018, filed on February 7, 2019.
10.41* |  | Form of Restricted Stock Unit Award Agreement for VP and Above (for 2019 awards), incorporated by reference to Exhibit 10.38 to Form 10-K (file no. 001-14901) for the year ended December 31, 2018, filed on February 7, 2019.
10.42* |  | Form of Restricted Stock Unit Award Agreement for Non-VP and Below (for 2019 awards), incorporated by reference to Exhibit 10.39 to Form 10-K (file no. 001-14901) for the year ended December 31, 2018, filed on February 7, 2019.
10.43* |  | Form of Restricted Stock Unit Award Agreement for Employees (for 2020 awards), incorporated by reference to Exhibit 10.42 to Form 10-K (file no. 001-14901) for the year ended December 31, 2019, filed on February 10, 2020.
10.44* |  | Form of Performance Share Unit Award Agreement (for 2016 awards), incorporated by reference to Exhibit 10.79 to Form 10-K (file no. 001-14901) for the year ended December 31, 2015, filed on February 5, 2016.
10.45* |  | Form of Performance Share Unit Award Agreement (for 2017 awards), incorporated by reference to Exhibit 10.80 to Form 10-K (file no. 001-14901) for the year ended December 31, 2016, filed on February 8, 2017.
10.46* |  | Form of Performance Share Unit Award Agreement (for 2018 awards), incorporated by reference to Exhibit 10.63 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
10.47* |  | Form of Performance Share Unit Award Agreement for CEO (for 2019 awards), incorporated by reference to Exhibit 10.44 to Form 10-K (file no. 001-14901) for the year ended December 31, 2018, filed on February 7, 2019.
10.48* |  | Form of Performance Share Unit Agreement for VP and Above (for 2019 awards), incorporated by reference to Exhibit 10.45 to Form 10-K (file no. 001-14901) for the year ended December 31, 2018, filed on February 7, 2019.
10.49* |  | Form of Performance Share Unit Agreement for Non-VP and Below (for 2019 awards), incorporated by reference to Exhibit 10.46 to Form 10-K (file no. 001-14901) for the year ended December 31, 2018, filed on February 7, 2019.
10.50* |  | Form of Performance Share Unit Award Agreement (for 2020 awards), incorporated by reference to Exhibit 10.48 to Form 10-K (file no. 001-14901) for the year ended December 31, 2019, filed on February 10, 2020.
10.51* |  | Directors' Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.52* |  | Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by reference to Exhibit 10.50 to Form 10-K (file no. 001-14901) for the year ended December 31, 2007, filed on February 19, 2008.
10.53* |  | Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
10.54* |  | Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
10.55* |  | Form of Director Deferred Stock Unit Grant Agreement, updated May 2019, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2019, filed on July 30, 2019.
10.56* |  | Form of CNX Resources Corporation Amended and Restated Equity and Incentive Compensation Plan Deferred Stock Unit Grant Agreement for Non-Employee Directors, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2020, filed on August 3, 2020.
10.57* |  | Trust Agreement (Amended and Restated on March 20, 2008) (Directors' Deferred Fee Plan (2004 Plan)), incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
10.58* |  | Amended and Restated Retirement Restoration Plan of CNX Resources Corporation, as amended and restated effective December 2, 2008, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.71 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.

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10.59* |  | Amended and Restated Supplemental Retirement Plan of CNX Resources Corporation effective January 1, 2007, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.72 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
10.60* |  | Amendment, effective May 30, 2019, to the Amended and Restated Supplemental Retirement Plan of CNX Resources Corporation, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2019, filed on July 30, 2019.
10.61* |  | Amendment, effective September 24, 2019, to the Amended and Restated Supplemental Retirement Plan of CNX Resources Corporation as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.61 to Form 10-K (file no. 001-14901) for the year ended December 31, 2019, filed on February 10, 2020.
10.62* |  | CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.73 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
10.63* |  | Amendment, dated as of July 1, 2018, to the CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2018, filed on August 2, 2018.
10.64* |  | Executive Compensation Clawback Policy of the Company, dated as of January 28, 2014, incorporated by reference to Exhibit 10.11 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
10.65* |  | Change in Control Severance Agreement, dated as of February 8, 2021, by and between the Company and Alexander Reyes, filed herewith.
10.66* |  | Letter Agreement, dated as of December 4, 2020, by and between the Company and Stephanie Gill, filed herewith.
10.67* |  | Form of Restricted Stock Unit Award Agreement for CEO (for 2021 awards), filed herewith.
10.68* |  | Form of Performance Share Unit Award Agreement for CEO (for 2021 awards), filed herewith.
10.69* |  | Form of Performance-Based Restricted Stock Unit Award Agreement for CEO (for 2021 awards), filed herewith.
10.7 0* |  | Form of Restricted Stock Unit Award Agreement for Non-CEO (for 2021 awards), filed herewith.
10.71* |  | Form of Performance Share Unit Award Agreement for Non-CEO (for 2021 awards), filed herewith.
10.72* |  | Form of Performance-Based Restricted Stock Unit Award Agreement for Non-CEO (for 2021 awards), filed herewith.
21 |  | Subsidiaries of CNX Resources Corporation.
23.1 |  | Consent of Ernst & Young LLP
23.2 |  | Consent of Netherland, Sewell & Associates, Inc.
31.1 |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1 |  | Engineers' Audit Letter
101.INS |  | XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH |  | XBRL Taxonomy Extension Schema Document.
101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB |  | XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document.
104 |  | Cover Page Interactive Data File (formatted as Inline XBRL with applicable taxonomy extension information contained in Exhibits 101).

* Denotes the management contracts and compensatory arrangements in which any director or any named executive officer participates.
Supplemental Information
142

No annual report or proxy material has been sent to shareholders of CNX at the time of filing of this Form 10-K. An annual report will be sent to shareholders and to the commission subsequent to the filing of this Form 10-K.
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 9th day of February, 2021.

| CNX RESOURCES CORPORATION
| By: |  | /s/ N ICHOLAS J. D E I ULIIS
|  |  | Nicholas J. DeIuliis
|  |  | Director, Chief Executive Officer and President
|  |  | (Duly Authorized Officer and Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 9th day of February, 2021, by the following persons on behalf of the registrant in the capacities indicated:

Signature |  | Title
/s/ N ICHOLAS J. D E I ULIIS |  | Director, Chief Executive Officer and President
Nicholas J. DeIuliis |  | (Duly Authorized Officer and Principal Executive Officer)
/s/ D ONALD W. R USH |  | Chief Financial Officer
Donald W. Rush |  | (Duly Authorized Officer and Principal Financial Officer)
/s/ ALAN K. SHEPARD |  | Chief Accounting Officer and Vice President
Alan K. Shepard |  | (Duly Authorized Officer and Principal Accounting Officer)
/s/ J ASON L. M UMFORD |  | Vice President and Controller
Jason L. Mumford |  |
/s/ W ILLIAM N. T HORNDIKE J R. |  | Director and Chairman of the Board
William N. Thorndike Jr. |  |
/s/ J. P ALMER C LARKSON |  | Director
J. Palmer Clarkson |  |
/s/ M AUREEN E. L ALLY-G REEN |  | Director
Maureen E. Lally-Green |  |
/s/ B ERNARD L ANIGAN JR. |  | Director
Bernard Lanigan Jr. |  |
/s/ IAN MCGUIRE |  | Director
Ian McGuire |  |

143

SCHEDULE II
CNX RESOURCES CORPORATION AND SUBSIDIARIES
Valuation and Qualifying Accounts
(Dollars in thousands)

|  |  |  | Additions |  | Deductions |  |
|  | Balance at |  |  |  | Release of |  |  |  | Balance at
|  | Beginning |  | Charged to |  | Valuation |  | Charged to |  | End
|  | of Period |  | Expense |  | Allowance |  | Expense |  | of Period
Year Ended December 31, 2020 |  |  |  |  |  |  |  |  |  |
State Operating Loss Carry-Forwards |  | $ | 81,202 |  |  | $ | — |  |  | $ | (2,004) |  |  | $ | — |  |  | $ | 79,198 |
Charitable Contributions |  | 658 |  |  | 48 |  |  | — |  |  | — |  |  | 706 |
Foreign Tax Credits |  | 43,194 |  |  | — |  |  | — |  |  | — |  |  | 43,194 |
Total |  | $ | 125,054 |  |  | $ | 48 |  |  | $ | (2,004) |  |  | $ | — |  |  | $ | 123,098 |
Year Ended December 31, 2019 |  |  |  |  |  |  |  |  |  |
State Operating Loss Carry-Forwards |  | $ | 47,964 |  |  | $ | 33,238 |  |  | $ | — |  |  | $ | — |  |  | $ | 81,202 |
Charitable Contributions |  | 3,297 |  |  | — |  |  | (2,639) |  |  | — |  |  | 658 |
Foreign Tax Credits |  | 43,194 |  |  | — |  |  | — |  |  | — |  |  | 43,194 |
Total |  | $ | 94,455 |  |  | $ | 33,238 |  |  | $ | (2,639) |  |  | $ | — |  |  | $ | 125,054 |
Year Ended December 31, 2018 |  |  |  |  |  |  |  |  |  |
State Operating Loss Carry-Forwards |  | $ | 61,560 |  |  | $ | — |  |  | $ | (13,596) |  |  | $ | — |  |  | $ | 47,964 |
Deferred Deductible Temporary Differences |  | 9,088 |  |  | — |  |  | (9,088) |  |  | — |  |  | — |
Charitable Contributions |  | 3,156 |  |  | 141 |  |  | — |  |  | — |  |  | 3,297 |
162(m) Officers Compensation |  | 5,957 |  |  | — |  |  | (5,957) |  |  | — |  |  | — |
AMT Credit |  | 12,413 |  |  | 1,983 |  |  | (14,396) |  |  | — |  |  | — |
Foreign Tax Credits |  | 44,402 |  |  | — |  |  | (1,208) |  |  | — |  |  | 43,194 |
Total |  | $ | 136,576 |  |  | $ | 2,124 |  |  | $ | (44,245) |  |  | $ | — |  |  | $ | 94,455 |

144