CNX Resources Corporation
10-K on 02/10/2020   Download
SEC Document
SEC Filing
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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, 2019
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 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, 2019, 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 $800,152,980.
The number of shares outstanding of the registrant's common stock as of January 20, 2020 is 186,642,962 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of CNX's Proxy Statement for the Annual Meeting of Shareholders to be held on May 6, 2020, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III.
 




TABLE OF CONTENTS

 
 
Page
PART I
 
ITEM 1.
Business
ITEM 1A.
Risk Factors
ITEM 1B.
Unresolved Staff Comments
ITEM 2.
Properties
ITEM 3.
Legal Proceedings
ITEM 4.
Mine Safety and Health Administration Safety Data
 
 
PART II
 
ITEM 5.
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
ITEM 6.
Selected Financial Data
ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
ITEM 7A.
Quantitative and Qualitative Disclosures About Market Risk
ITEM 8.
Financial Statements and Supplementary Data
ITEM 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
ITEM 9A.
Controls and Procedures
ITEM 9B.
Other Information
 
 
 
PART III
 
ITEM 10.
Directors and Executive Officers of the Registrant
ITEM 11.
Executive Compensation
ITEM 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
ITEM 13.
Certain Relationships and Related Transactions and Director Independence
ITEM 14.
Principal Accounting Fees and Services
 
 
 
PART IV
 
ITEM 15.
Exhibits and Financial Statement Schedules
ITEM 16.
Form 10-K Summary
SIGNATURES


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.
net - “net” natural gas or “net” acres are determined by adding the fractional ownership working interests the Company has in gross wells or acres.
TIL - turn-in-line; a well turned to sales.
blending - process of mixing dry and damp gas in order to meet downstream pipeline specifications.
lease operating expense - costs of operating wells and equipment on a producing lease, many of which are recurring. Includes items such as water disposal, repairs and maintenance, equipment rental, and operating supplies among others.
proved reserves - quantities of oil, natural gas, and NGLs which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
proved developed reserves (PDPs) - proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
proved undeveloped reserves (PUDs) - proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
reservoir - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
development well - a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
exploratory well - a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
gob well  - a well drilled or vent hole converted to a well which produces or is capable of producing coalbed methane or other natural gas from a distressed zone created above and below a mined-out coal seam by any prior full seam extraction of the coal.
service well - a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.
play - a proven geological formation that contains commercial amounts of hydrocarbons.
royalty interest - the land owner’s share of oil or gas production, typically 1/8.
throughput - the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period. 
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.
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.




    



3




FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Annual Report on Form 10-K 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 Annual Report on 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 Annual Report on Form 10-K speak only as of the date of this Annual Report on 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 NGLs are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand for our products, weather and the price and availability of alternative fuels;
our dependence on gathering, processing and transportation facilities and other midstream facilities owned by CNX Midstream Partners LP (NYSE: CNXM) (CNXM) and others;
uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates;
the high-risk nature of drilling, 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;
challenges associated with strategic determinations, including the allocation of capital and other resources to strategic opportunities;
the substantial capital expenditures required for our development and exploration projects, as well as CNXM’s midstream system development;
the impact of potential, as well as any adopted, environmental regulations, including those relating to greenhouse gas emissions;
environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities;
decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials in sufficient quantities or at reasonable costs to support our operations;
if natural gas prices decrease or drilling efforts are unsuccessful, we may be required to record write-downs of our proved natural gas properties, and;
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;
existing and future government laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations;
significant costs and liabilities may be incurred as a result of pipeline operations and related increase in the regulation of gas gathering pipelines;
our ability to find adequate water sources for our use in shale gas drilling and production operations, or our ability to dispose of, transport or recycle water used or removed in connection with our gas operations at a reasonable cost and within applicable environmental rules;
failure to successfully estimate the rate of decline or existing reserves or to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;


4



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;
changes in federal or state income tax laws;
cyber-incidents could have a material adverse effect on our business, financial condition or results of operations;
construction of new gathering, compression, dehydration, treating or other midstream assets by CNXM may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks;
our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel;
terrorist activities could materially adversely affect our business and results of operations;
we may operate a portion of our business with one or more joint venture partners or in circumstances where we are not the operator, which may restrict our operational and corporate flexibility and we may not realize the benefits we expect to realize from a joint venture;
acquisitions and divestitures, we anticipate may not occur or produce anticipated benefits;
the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the Exchange Act;
there is no guarantee that we will continue to repurchase shares of our common stock under our current or any future share repurchase program at levels undertaken previously or at all;
negative public perception regarding our industry could have an adverse effect on our operations;
CONSOL Energy may not be able to satisfy its indemnification obligations in the future and such indemnities may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy will be allocated responsibility; and
other factors discussed in this 2019 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which are on file with the Securities and Exchange Commission.






5



PART I

ITEM 1.
Business

General

CNX Resources Corporation ("CNX," the "Company," or "we," "us," or "our") is a premiere independent oil and gas company focused on the exploration, development, production, gathering, processing and acquisition of natural gas properties primarily in the Appalachian Basin. Our operations are centered on unconventional shale formations, primarily the Marcellus Shale and Utica Shale.

CNX’s wholly owned subsidiary, CNX Gathering LLC, which holds the general partner interest and limited partner interest (previously incentive distribution rights - See Note 25 - Subsequent Events in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K for more information) in CNX Midstream Partners LP (a public master limited partnership), which was formed to own, operate, and develop midstream energy assets to service CNX and third-party production, drilling, and completion activities under long-term service contracts. CNX’s consolidated financial statements include CNX Gathering LLC’s financial position and results of operations beginning after January 3, 2018 (see Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K).

CNX was incorporated in Delaware in 1991, but its predecessors had been mining coal, primarily in the Appalachian Basin, since 1864. In November 2017, CNX completed the tax-free spin-off of its coal business (see Note 5 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K). CNX entered the natural gas business in the 1980s initially to increase the safety and efficiency of its Virginia coal mines by capturing methane from coal seams prior to mining, which makes the mining process safer and more efficient. The natural gas business grew from the coalbed methane production in Virginia into other unconventional production, including hydraulic fracturing in the Marcellus Shale and Utica Shale in the Appalachian Basin. This growth was accelerated with the 2010 asset acquisition of the Appalachian Exploration & Production business of Dominion Resources, Inc.

CNX currently operates, develops and explores for natural gas in Appalachia (Pennsylvania, West Virginia, Ohio, and Virginia). Our primary focus is the continued development of our Marcellus Shale acreage and delineation and development of our unique Utica Shale acreage and stacked pay opportunity set. We believe that our concentrated operating area, legacy surface acreage position, regional operating expertise, extensive data set from development, as well as from non-operated participation wells and our held-by-production acreage position, provides us a significant competitive advantage over our competitors. Over the past ten years, CNX's natural gas production has grown by approximately 471% to produce a total of 539.1 net Bcfe in 2019.

Our land holdings in the Marcellus and Utica Shale plays cover large areas, provide multi-year drilling opportunities and, collectively, have sustainable lower-risk growth profiles. We currently control approximately 519,000 net acres in the Marcellus Shale and approximately 608,000 net acres that have Utica Shale potential in Ohio, West Virginia, and Pennsylvania. We also have approximately 2.4 million net acres in our coalbed methane play.

Highlights of our 2019 production include the following:
Total average production of 1,477,120 Mcfe per day;
94% Natural Gas, 6% Liquids; and
69% Marcellus, 21% Utica, and 10% coalbed methane.

At December 31, 2019, our proved natural gas, NGL, condensate and oil reserves (collectively, "natural gas reserves") had the following characteristics:
8.4 Tcfe of proved reserves;
94.2% natural gas;
57.43% proved developed;
98.6% operated; and
A reserve life ratio of 15.63 years (based on 2019 production).









6




The following map provides the location of CNX's E&P operations by region:
map.jpg
CNX's Strategy and Corporate Values

CNX's strategy is to increase shareholder value through the development and growth of its existing natural gas assets and selective acquisition of natural gas acreage leases within its 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. We will also continue to focus on the monetization of non-core assets to accelerate value creation and to minimize any shortfall between operating cash flows and our capital growth requirements.

CNX defines itself through its corporate values which serve as the compass for 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 value for the long-term. CNX also 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. More than a short-term “bridge” fuel that is useful in the transition from more carbon-intensive energy sources to renewable, natural gas is inextricably linked to the long-term success of renewable energy. The EIA forecasts that global natural gas consumption is expected to increase by more than 40% from current levels by the year 2050. Increasing demand for natural gas comes with a variety of economic, environmental, and social benefits, including: reduced emissions, improved energy security, industrial applications and reliable heat.



7



CNX's Capital Expenditure Budget    

In 2020, CNX expects capital expenditures of approximately $530-$610 million. The 2020 budget currently includes $360-$410 million of drilling and completion ("D&C") capital, approximately $95 million of capital associated with land, midstream, and water infrastructure and $80-$100 million of capital for CNX Midstream Partners LP ("CNXM"). The Company continuously evaluates multiple factors to determine incremental activity throughout the year, and as such, may update guidance accordingly.
DETAIL OF OPERATIONS

Our operations are located throughout Appalachia and include the following plays:

Marcellus Shale

We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 519,000 net Marcellus Shale acres at December 31, 2019.

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 44,000 acres of incremental Upper Devonian acres; however, these acres have historically not been disclosed separately as they generally coincide with our Marcellus acreage.

On January 3, 2018, the Company acquired the remaining 50% membership interest in CONE Gathering LLC (which has since been renamed CNX Gathering LLC), which holds the general partner interest and limited partner interests (previously incentive distribution rights - See Note 25 - Subsequent Events in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K for more information) in CNXM, the entity that constructs and operates the gathering system for most of our Marcellus shale production. See "Midstream Gas Services" below for a more detailed explanation.

Utica Shale

We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 608,000 net Utica Shale acres at December 31, 2019. Approximately 349,000 Utica acres coincide with Marcellus Shale acreage in Pennsylvania, West Virginia, and Ohio. During the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets, including approximately 35,000 net acres in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).

Coalbed Methane (CBM)

We have the rights to extract CBM in Virginia from approximately 308,000 net CBM acres in Central Appalachia. We produce CBM natural gas primarily from the Pocahontas #3 seam and still have a nominal drilling program.

We also have the rights to extract CBM from approximately 2,122,000 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 981,700 net acres at December 31, 2019. The majority of our shallow oil and gas leasehold position is held by production and all of it is extensively overlain by existing third-party gas gathering and transmission infrastructure. In March 2018, CNX Gas completed the sale of substantially all of its shallow oil and gas assets in Pennsylvania and West Virginia, including approximately 833,000 net acres (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).





8



Summary of Properties as of December 31, 2019
 
 
Marcellus
 
Utica
 
CBM
 
Other Gas
 
 
 
 
Segment
 
Segment
 
Segment
 
Segment
 
Total
Estimated Net Proved Reserves (MMcfe)
 
6,401,288

 
910,667

 
1,103,724

 
9,988

 
8,425,667

Percent Developed
 
55
%
 
49
%
 
77
%
 
100
%
 
57
%
Net Producing Wells (including oil and gob wells)
 
397

 
55

 
3,943

 
115

 
4,510

Net Acreage Position:
 
 
 
 
 
 
 
 
 
 
Net Proved Developed Acres
 
46,701

 
14,101

 
274,512

 
2,386

 
337,700

Net Proved Undeveloped Acres
 
22,737

 
6,179

 

 

 
28,916

Net Unproved Acres(1)
 
494,251

 
238,720

 
2,156,231

 
979,331

 
3,868,533

     Total Net Acres(2)
 
563,689

 
259,000

 
2,430,743

 
981,717

 
4,235,149

_________
(1)
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.
(2)
Acreage amounts are only included under the target strata CNX expects to produce with the exception of certain CBM acres governed by separate leases, although the reported acres may include rights to multiple gas seams (e.g. we have rights to the Marcellus segment that are disclosed under the Utica segment and we have rights to Utica segment that are disclosed under the Marcellus segment). We have reviewed our drilling plans, and our acreage rights and have used our best judgment to reflect the acres in the strata we expect to primarily produce. As more information is obtained or circumstances change, the acreage classification may change.

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, 2019, the number of producing wells, developed acreage and undeveloped acreage:
 
 
Gross
 
Net(1)
Producing Gas Wells (including gob wells)
 
6,512

 
4,510

Producing Oil Wells
 
151

 

Net Acreage Position:
 
 
 
 
Proved Developed Acreage
 
337,700

 
337,700

Proved Undeveloped Acreage
 
28,916

 
28,916

Unproved Acreage
 
5,192,777

 
3,868,533

     Total Acreage
 
5,559,393

 
4,235,149


(1)
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.










9



The following table represents the terms under which we hold these acres:    
 
 
Gross Unproved Acres
 
Net Unproved Acres
 
Net Proved Undeveloped Acres
Held by Production/Fee
 
4,354,734

 
3,305,639

 
21,874

Expiration Within 2 Years
 
43,468

 
24,102

 
4,235

Expiration Beyond 2 Years
 
47,137

 
26,176

 
6,325

    Total Acreage
 
4,445,339

 
3,355,917

 
32,434


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, 2019, 2018 and 2017, we drilled 75.7, 83.9 and 90.0 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. In 2019, there were 35.0 net development wells and 1.0 exploratory well drilled but uncompleted. There was 1.0 net dry development well in 2019 and no net dry development wells in 2018 or 2017. As of December 31, 2019, there are 7.0 gross completed developmental wells ready to be turned in-line. The following table illustrates the net wells drilled by well classification type:
 
 
For the Year
 
 
Ended December 31,
 
 
2019
 
2018
 
2017
Marcellus Segment
 
47.0

 
65.9

 
9.0

Utica Segment
 
17.7

 
12.0

 
17.0

CBM Segment
 
11.0

 
6.0

 
64.0

Other Gas Segment
 

 

 

     Total Development Wells (Net)
 
75.7

 
83.9

 
90.0


Exploratory Wells (Net)

There were 5.0 and 4.0 net exploratory wells drilled during the years ended December 31, 2019 and 2017, respectively. There were no net exploratory wells drilled during the year ended December 31, 2018. As of December 31, 2019, 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,
 
 
2019
 
2018
 
2017
 
 
Producing
 
Dry
 
Still Eval*.
 
Producing
 
Dry
 
Still Eval.
 
Producing
 
Dry
 
Still Eval.
Marcellus Segment
 

 

 

 

 

 

 

 

 

Utica Segment
 
4.0

 

 
1.0

 

 

 

 
4.0

 

 

CBM Segment
 

 

 

 

 

 

 

 

 

Other Gas Segment
 

 

 

 

 

 

 

 

 

     Total Exploratory Wells (Net)
 
4.0

 

 
1.0

 

 

 

 
4.0

 

 

* Still evaluating includes wells that were drilled and uncompleted or in the process of being completed at the end of the year.







10




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,
 
 
2019
 
2018
 
2017
Proved Developed Reserves
 
4,838,858

 
4,494,878

 
4,409,065

Proved Undeveloped Reserves
 
3,586,809

 
3,386,457

 
3,172,547

Total Proved Developed and Undeveloped Reserves(1)
 
8,425,667

 
7,881,335

 
7,581,612

___________
(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.

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,
 
 
2019
 
2018
 
2017
 
 
(Dollars in millions)
Future Net Cash Flows
 
$
7,744

 
$
13,132

 
$
7,841

Total PV-10 Measure of Pre-Tax Discounted Future Net Cash Flows (1)
 
$
4,176

 
$
6,172

 
$
4,140

Total Standardized Measure of After-Tax Discounted Future Net Cash Flows
 
$
3,070

 
$
4,655

 
$
3,131

____________
(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,
 
 
2019
 
2018
 
2017
 
 
(Dollars in millions)
Future Cash Inflows
 
$
19,490

 
$
26,610

 
$
19,262

Future Production Costs
 
(7,903
)
 
(7,730
)
 
(7,234
)
Future Development Costs (including Abandonments)
 
(1,121
)
 
(1,600
)
 
(1,711
)
Future Net Cash Flows (pre-tax)
 
10,466

 
17,280

 
10,317

10% Discount Factor
 
(6,290
)
 
(11,108
)
 
(6,177
)
PV-10 (Non-GAAP Measure)
 
4,176

 
6,172

 
4,140

Undiscounted Income Taxes
 
(2,721
)
 
(4,147
)
 
(2,476
)
10% Discount Factor
 
1,615

 
2,630

 
1,467

Discounted Income Taxes
 
(1,106
)
 
(1,517
)
 
(1,009
)
Standardized GAAP Measure
 
$
3,070

 
$
4,655

 
$
3,131



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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,
 
 
2019
 
2018
 
2017
Natural Gas
 
 
 
 
 
 
  Sales Volume (MMcf)
 
 
 
 
 
 
      Marcellus
 
335,993

 
255,127

 
209,687

      Utica
 
113,676

 
148,117

 
70,708

      CBM
 
55,445

 
60,268

 
65,373

      Other
 
241

 
4,714

 
19,125

          Total
 
505,355

 
468,226

 
364,893

 
 
 
 
 
 
 
NGL
 
 
 
 
 
 
  Sales Volume (Mbbls)
 
 
 
 
 
 
      Marcellus
 
5,423

 
5,227

 
4,604

      Utica
 
5

 
853

 
1,851

      Other
 

 
1

 
1

          Total
 
5,428

 
6,081

 
6,456

 
 
 
 
 
 
 
Oil and Condensate
 
 
 
 
 
 
  Sales Volume (Mbbls)
 
 
 
 
 
 
      Marcellus
 
186

 
286

 
346

      Utica
 
9

 
78

 
204

      Other
 
8

 
35

 
39

          Total
 
203

 
399

 
589

 
 
 
 
 
 
 
Total Sales Volume (MMcfe)
 
 
 
 
 
 
      Marcellus
 
369,652

 
288,203

 
239,387

      Utica
 
113,761

 
153,704

 
83,038

      CBM
 
55,445

 
60,268

 
65,373

      Other
 
291

 
4,929

 
19,368

          Total
 
539,149

 
507,104

 
407,166

*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 the year. For additional information, see Note 6 - 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 a minimum base for 2020 annual natural gas production volumes of 525-555 Bcfe, which is consistent with 2019 volumes, based on the midpoint of guidance.











12





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.
 
 
For the Year
 
 
Ended December 31,
 
 
2019
 
2018
 
2017
Average Sales Price - Gas (Mcf)
 
$
2.48

 
$
2.97

 
$
2.59

Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
 
$
0.14

 
$
(0.15
)
 
$
(0.11
)
Average Sales Price - NGLs (Mcfe)*
 
$
3.20

 
$
4.55

 
$
4.03

Average Sales Price - Oil (Mcfe)*
 
$
8.13

 
$
9.89

 
$
7.56

Average Sales Price - Condensate (Mcfe)*
 
$
7.47

 
$
8.43

 
$
6.59

 
 
 
 
 
 
 
Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments
 
$
2.66

 
$
2.97

 
$
2.66

Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments
 
$
2.53

 
$
3.11

 
$
2.76

Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)
 
$
0.12

 
$
0.19

 
$
0.22

 
 
 
 
 
 
 
Average Sales Price - NGLs (Bbl)
 
$
19.20

 
$
27.30

 
$
24.18

Average Sales Price - Oil (Bbl)
 
$
48.78

 
$
59.34

 
$
45.36

Average Sales Price - Condensate (Bbl)
 
$
44.82

 
$
50.58

 
$
39.54

*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 $0.05 per Mcfe, $0.14 per Mcfe, and $0.17 per Mcfe for 2019, 2018, and 2017, 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.

We enter into physical natural gas sales transactions with various counterparties 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. We also enter into various natural gas swap transactions. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 389.2 Bcf of our produced gas sales volumes for the year ended December 31, 2019 at an average price of $2.70 per Mcf. The notional volumes associated with these gas swaps represented approximately 356.3 Bcf of our produced gas sales volumes for the year ended December 31, 2018 at an average price of $2.76 per Mcf. As of January 8, 2020, these physical and swap transactions represent approximately 497.5 Bcf of our estimated 2020 production at an average price of $2.55 per Mcf, 443.3 Bcf of our estimated 2021 production at an average price of $2.42 per Mcf, 305.2 Bcf of our estimated 2022 production at an average price of $2.44 per Mcf, approximately 174.1 Bcf of our estimated 2023 production at an average price of $2.29 per Mcf, and approximately 151.5 Bcf of our estimated 2024 production at an average price of $2.32 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 21 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.






13




Midstream Gas Services

E&P Midstream Gas Services

CNX has traditionally designed, built and operated 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. CNX now owns or operates approximately 2,600 miles of natural gas gathering pipelines as well as a number of natural gas processing facilities. These assets are part of the E&P Division (See Note 24 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).

CNX's Midstream Division (see below) owns substantially all of CNX's Marcellus Shale gathering systems which also transports CNX's Utica Shale volumes in Pennsylvania. With respect to the Utica Shale in Ohio, CNX primarily contracts with third-party gathering services.

CNX has developed a diversified portfolio of firm transportation capacity options to support its production growth plan. 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 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 the projected 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 CBM and lower Btu Utica wells in close proximity to higher Btu Marcellus wells. Separately, the low Btu CBM gas and the high Btu Marcellus gas may need processing in order to meet downstream pipeline specifications. However, 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 gas that does not meet pipeline specification. These different gas types allow us more flexibility in bringing Marcellus and Utica shale wells on-line at qualities that meet interstate pipeline specifications.

Midstream Division

In January 2018, CNX acquired Noble Energy’s ("Noble") 50% membership interest in CNX Gathering LLC (then named CONE Gathering) ("CNX Gathering"), which holds the general partner interest and limited partner interests (previously incentive distribution rights) in CNX Midstream Partners LP (then named CONE Midstream Partners LP) ("CNX Midstream" or "CNXM"). See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information. As part of the transaction, CNX Midstream amended its gas gathering agreement with CNX Gas Company LLC, a wholly-owned subsidiary of CNX.

CNX Gathering develops, operates and owns substantially all of CNX’s Marcellus Shale gathering systems. Prior to its acquisition of Noble’s interest, CNX accounted for its interest in CNX Gathering under the equity method of accounting. Subsequent to the acquisition, CNX is the single sponsor of CNXM, and beginning in the first quarter of 2018 CNX Gathering was consolidated into the Company’s financial statements as the Midstream Division (See Note 24 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). We believe that the network of rights-of-way, vast surface holdings, experience in building and operating gathering systems in the Appalachian basin, and increased control and flexibility will give CNX Gathering an advantage in building the midstream assets required to execute our future development plans.

Natural Gas Competition

The United States natural gas industry is highly competitive. CNX competes with other large producers, as well as a myriad of smaller producers and marketers. CNX also competes for pipeline and other services to deliver its products to customers. According to data from the Natural Gas Supply Association and the Energy Information Agency (EIA), the five largest U.S. producers of natural gas produced about 14% of dry natural gas production during the first ten months of 2019. The EIA reported 522,631 producing natural gas wells in the United States at December 31, 2018 (the latest year for which government statistics are available), which is approximately 3% lower than 2017.


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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. According to the EIA, natural gas represented 38% of U.S. electricity generation during the twelve months ended October 31, 2019, up from 35% in 2018. Estimates from EIA indicate that an average of 31.0 billion cubic feet per day (Bcf/d) was consumed by electric generation in 2019, up 7% from 2018. EIA also reports that the United States exported 5.3 Bcf/d in 2019 which is up 2.0 Bcf/d, or about 61% from 2018. EIA expects this trend to persist with estimates pointing towards an increase to 7.3 Bcf/d in 2020 and 8.9 Bcf/d in 2021. The United States became a net exporter of natural gas on an annual basis in 2016 for the first time in almost 60 years. U.S. natural gas exports have increased primarily with the addition of new LNG export facilities in the Lower 48 states. EIA reported that in 2019, the United States averaged LNG exports of 5.0 Bcf/d with expectations of steady increases to 6.5 Bcf/d and 7.7 Bcf/d in 2020 and 2021, respectively. CNX expects the high level of U.S. gas exports to continue in the future. In addition, there is potential for natural gas to become a significant contributor to the transportation market. The EIA currently expects overall demand for U.S. natural gas in 2020 to increase 1.7% from 2019. Our increasing gas production will allow CNX to participate in growing markets.

CNX gas operations are primarily located in the eastern United States, specifically the Appalachian Basin. The gas market is highly fragmented and not dominated by any single producer. We believe that competition among producers is based primarily on acreage position, low drilling and operating costs as well as pipeline transportation availability to the various markets.

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/demand dynamics.

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 Marcellus Shale and Utica Shale production. We also derive value from this surface control by granting rights of way or development rights to third-parties when we are able to derive appropriate value for our shareholders.
 
Water Division

CNX Water Assets LLC ("CNX Water") is a wholly-owned subsidiary of CNX and supplies turnkey 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 Water works to develop solutions that coincide with our midstream operations to offer gas gathering and water delivery solutions in one package to third parties.

Employee and Labor Relations

At December 31, 2019, CNX had 467 employees, none of whom are subject to a collective bargaining agreement.

Industry Segments

Financial information concerning industry segments, as defined by GAAP, for the years ended December 31, 2019, 2018 and 2017 is included in Note 24 - 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.

Financial Information about Geographic Areas

All of the Company's assets and operations are located in the continental United States.



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Laws and Regulations

General

Our natural gas and midstream operations are subject to various federal, state and local (including county and municipal level) laws and regulations. These laws and regulations cover virtually every aspect of our operations including, among other things: 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; and gathering of natural gas production. Numerous governmental permits, authorizations and approvals under these laws and regulations are required for natural gas and midstream operations. These laws and regulations, and the permits, authorizations and approvals issued pursuant to those laws and regulations, are intended to protect, among other things: air quality; ground water and surface water resources, including drinking water supplies; wetlands; waterways; endangered plants and wildlife; state natural resources and the health and safety of our employees and the communities in which we operate.
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.
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, permit exceedances and violations 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 natural gas or midstream operations or on our customers' ability to use our natural gas and may require us or our customers to change 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.
Environmental Laws

Many of the laws and regulations referred to above are state level environmental laws and regulations, which vary according to the state in which we are conducting operations. However, 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 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 new 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 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.



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Clean Air Act. The federal Clean Air Act and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. Various activities in our operations are subject to air quality regulation, including pipeline compression, venting and flaring of natural gas, and hydraulic fracturing and completion processes, as well as fugitive emissions from operations. We obtain 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 - 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 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 in certain instances imposing requirements to dispose of produced wastes and other oil and 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.
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. See “Risk Factors -- We may incur significant costs and liabilities as a result of pipeline operations and related increase 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 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 coalbed methane 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 coalbed methane 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.
Available Information

CNX maintains a website at www.cnx.com. CNX makes available, free of charge on its website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished


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pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are electronically filed with, or furnished to the SEC. Those reports are also available at the SEC's website www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors, such as presentations to analysts.

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).


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 Annual Report on 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.

Prices for natural gas and NGLs are volatile and can fluctuate widely based upon a number of factors beyond our control, including oversupply relative to the demand for our products, weather and the price and availability of alternative fuels. 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 Marcellus and other new shale plays. The oversupply of natural gas beginning in 2012 has resulted in domestic prices continuing to hover around ten-year lows, and drilling has continued in these plays, despite these lower gas prices, to meet drilling commitments. 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 gas. The success of the Marcellus Shale and Utica Shale plays has resulted in growth in natural gas production in this region, with production per day in the Appalachian Basin increasing by more than 500 percent since 2011. 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 gas produced and sold locally to be priced at a discount to many other market hubs, such as the benchmark Louisiana Henry Hub price. This discount, or negative basis, to the Henry Hub price is forecasted to continue in future years. While we expect many of the planned interstate pipeline projects to reduce this discount, it could widen further if these projects to move gas out of the basin are delayed or denied for any reason, such as permitting issues or environmental lawsuits.

An extended period of lower natural gas prices can negatively affect us in several other ways, including reduced cash flow, which decreases funds available for capital expenditures to replace reserves or increase production. Also, our access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.

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 regarding natural gas. As a result of increasing supply, condensate and oil prices have exhibited great volatility. 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, boat 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:



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weather conditions in our markets that affect the demand for natural gas;
changes in the consumption pattern of industrial consumers, electricity generators and residential users of electricity and natural gas;
with respect to natural gas, the price and availability of alternative fuel sources used by electricity generators;
technological advances affecting energy consumption and conservation measures reducing demand;
the costs, availability and capacity of transportation infrastructure;
proximity and capacity of natural gas pipelines and other transportation facilities;
changes in levels of international demand and tariffs associated with international export; and
the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and delays.

Our business depends on gathering, processing and transportation facilities and other midstream facilities owned by CNXM and 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 or our investment in CNXM.

We gather, process and transport our natural gas to market by utilizing pipelines and facilities owned by others, including CNXM. If pipeline or facility capacity is limited or is unexpectedly disrupted for any reason, our sales of natural gas and/or NGLs could be reduced, which could negatively affect our profitability. If CNX cannot access processing pipeline transportation facilities, 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 CNX 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 a single pipeline, Texas Eastern Transmission, which could experience capacity issues, operational disruptions and unexpected downtime, and either no or little alternative transportation options are available for our natural gas. Reductions in capacity on the Texas Eastern pipeline, 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.

In addition to our relationship with CNXM, 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 through CNXM 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 CNXM compression and processing stations. An operational issue at any of those stations would materially impact CNX’s production, cash flow and results of operation. CNXM’s assets connect to other pipelines or facilities owned and operated by unaffiliated third parties, the continuing operation of which is not within our or CNXM’s 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.

We face uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

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


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operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas reserves, the economically recoverable quantities of natural gas 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 liquid reserves on historical average prices and costs. However, actual future net cash flows from our proved and unproved natural gas and liquid properties will 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 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, 2019 would decrease from $4.18 billion to $3.96 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 drilling program. Drilling for 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 drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control. Our future drilling 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 drill identified or budgeted wells within our expected time frame, or at all for various reasons, and a final determination with respect to the drilling 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 drilling 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 to drill the wells;
whether production levels align with estimates; and
economic and industry conditions at the time of drilling, 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 the Marcellus and Utica Shale plays 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 drilling program are spread over a smaller number of wells, and in order to be profitable, each horizontal well will need to produce at a higher level. 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 drilling 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 drilling will be increased in some respects, with the result that CNX might find it more difficult to achieve economic success in our drilling program.

Our exploration and production of natural gas and CNXM’s gathering, compression and transportation operations involve


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numerous operational risks. The cost of drilling, completing 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 drilling 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 drilling 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 CNX and CNXM maintain insurance for a number of risks and hazards, CNX and CNXM 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 drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their development and/or drilling.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our development strategy. Our ability to drill and 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 drilling 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 drilling 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.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, 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 (primarily completions), 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 fail to optimize our capital investment and


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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.

Our development and exploration projects, as well as CNXM’s midstream development projects, require substantial capital expenditures and if we fail to generate sufficient cash flow or obtain required capital or financing on satisfactory terms, our natural gas reserves may decline, and financial results may suffer.

As part of our strategic determinations, CNX expects to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves and CNXM expects to fund its share of growth capital expenditures associated with its Anchor Systems, its 5% controlling interests in the Additional Systems or to purchase or construct new midstream systems. If CNX or CNXM are unable to make sufficient or effective capital expenditures, we will be unable to maintain and grow our respective businesses.

CNXM's amended gathering agreement with us, CNXM's largest customer, includes minimum well commitments; however, that gas gathering agreement and those CNXM has with other third-parties impose obligations on CNXM to invest capital which is not fully protected against volumetric risks associated with lower-than-forecast volumes flowing through its gathering systems. To the extent CNXM’s customers are not contractually obligated to, and determine not to, develop their properties in the areas covered by CNXM’s acreage dedications, the resulting decrease in the development of reserves by CNXM customers could result in reduced volumes serviced by CNXM and a commensurate decline in revenues and cash flows.

There is no assurance that CNX or CNXM will have sufficient cash from operations, borrowing capacity under each company’s respective credit facilities, or the ability to raise additional funds in the capital markets to meet our respective capital requirements. If cash flow generated by our operations or available borrowings under either company’s credit facilities are not sufficient to meet our capital requirements, or we are unable to obtain additional financing, CNX could be required to curtail the pace of the development of our natural gas properties and midstream activities, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

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.

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, on the environment.

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 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 source permits.

The EPA has also adopted, changed and amended rules to control volatile organic compound emissions from certain oil and 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 that 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 gas industry. Additional revisions were proposed in August 2019. As these rules are adopted, changed or modified, these rules may result in increased costs for permitting, equipping, and monitoring methane emissions or otherwise restrict operations.

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, and Virginia is also considering this issue. Most of these


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types of programs require major source of emissions or major producers of fuels to acquire and 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.

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 and CNXM are 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 our, CNXM’s, and our respective 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 CNXM’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 public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

Our operations, and those of CNXM, 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 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 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 natural gas, midstream and water businesses. 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 been developing a proposed rule that would revise 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 will be a notice-and-comment rulemaking in which federal agencies will conduct a substantive reevaluation of such definition. While CNX cannot at this time predict the final form that the rule will ultimately take, such 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 gas agencies. The disposal of produced water and other wastes in underground injection disposal wells is regulated by the EPA under the federal Safe Drinking Water Act or 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 crude 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 Annual Report on Form 10-K.


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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 workover 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. 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. For example, in the year ended December 31, 2019 and 2018, due to the oversupply of gas in our markets, CNX made payments under these types of contracts of approximately $12 million and $7 million, respectively, for field services that we did not use. Having to pay for services we do not use decreases our cash flow and increases our costs.

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 whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management's plans change with respect to those assets, and in the past have had to take an impairment charge for certain of our assets. 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, 2019, as a result of the annual impairment test, an impairment of $327 million was recognized within the Central Pennsylvania Marcellus proved properties. 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.
 
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


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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. 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, competition in the international markets. The industry has been experiencing increased competitive pressures as a result of both consolidation within the exploration and production space, along with the continued proliferation of stand-alone midstream companies. Midstream, transmission and processing consolidation in the industry could lead to a less competitive environment for CNX to find partners for projects needed to support development, which could increase costs. Many of the companies with which CNX and CNXM compete are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. In addition, larger companies may be able to pay more 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 highly competitive environment in which we operate may negatively impact our ability to acquire additional properties at prices or upon terms we view as favorable. Any reduction in our ability to compete in current or future natural gas markets could materially adversely affect our business, financial condition, results of operations and cash flows.

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

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 and/or whether we successfully complete various financing transactions the proceeds of which would be used to pay down or repurchase our senior notes;
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.

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 8, 2020, we expect these transactions will represent approximately 497.5 Bcf of our estimated 2020 production at an average price of $2.55 per Mcf, 443.3 Bcf of our estimated 2021 production at an average price of $2.42 per Mcf, 305.2 Bcf of our estimated 2022 production at an average price of $2.44 per Mcf, 174.1 Bcf of our estimated 2023 production at an average price of $2.29 per Mcf, and 151.5 Bcf of our estimated 2024 production at an average price of $2.32


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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;
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.

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 or expansion, future modifications to which may adversely affect, among other things, our ability to develop the resource, obtain permits, as well as pricing or marketing of natural gas production.
 
For example, currently CNXM’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 CNXM’s facilities considered to be gathering facilities, CNXM believes that the natural gas pipelines in its 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 for CNXM.
 
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 midstream activities of CNXM and other third-party providers with whom we interact, 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 are 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. While these cases are still pending, the ultimate judicial outcomes could negatively impact future shale drilling and hydraulic fracturing within the Commonwealth of Pennsylvania if the court finds that fracing could violate the constitutional or property rights of Pennsylvania citizens and residents.

CNX may incur significant costs and liabilities as a result of pipeline operations and related increase in the regulation of gas gathering pipelines.

Pipeline and Hazardous Materials Safety Administration (PHMSA) has adopted safety, transportation and operational regulations applicable to pipeline operators. Should our or CNXM's 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


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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 or CNXM's operations. The adoption of these regulations, which apply 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.

We require adequate sources of water to use in the fracturing process, as well as the ability to dispose of, transport or recycle the water after hydraulic fracturing. Our CBM gas drilling and production operations also require the removal and disposal of water from the coal seams from which we produce gas. If CNX cannot find adequate sources of water for our use or we are unable to dispose of or recycle the water 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 over the life of the well during normal production 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 this water and locations where the water 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, storage, and 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 estimate the rate of decline of existing reserves and find or acquire economically recoverable natural gas or liquid reserves to replace our current natural gas and liquid reserves will cause our levels of natural gas and liquid reserves and production to decline, which would adversely affect our business, financial condition, results of operations, liquidity and cash flows.

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 or other circumstances arise that affect our ability to produce the wells. Thus, our future natural gas and liquid reserves and production and, therefore, our cash flow and income are highly dependent on our estimates and our success in efficiently developing, exploiting 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 and condensate volumes handled through the CNXM midstream systems depends on the level of production from natural gas wells dedicated to 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 CNXM’s midstream systems, CNXM must obtain production from new wells completed by us and any third-party customers on acreage dedicated to the CNXM midstream systems or in CNXM’s areas of operation. CNXM has no control over producers’ levels of development and completion activity in its areas of operations, the amount of reserves associated with wells connected to CNXM’s systems or the rate at which production from a well declines.

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


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As of December 31, 2019, CNX's total long-term indebtedness, excluding CNXM, was approximately $2.1 billion of which approximately (i) $894.3 million was under our 5.875% senior unsecured notes due 2022 plus $1.0 million of unamortized bond premium, (ii) $661.0 million was under our senior secured credit facility, (iii) $500.0 million was under our 7.25% senior unsecured notes due 2027, and (iv) $7.7 million of finance leases due through 2024. 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 facility. 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 5.875% senior unsecured notes and our 7.25% senior notes 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 CNX's or CNXM’s cash flows and capital resources are insufficient to fund their respective debt service obligations, including repayment of such obligations at maturity, CNX or CNXM, as the case may be, 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, both CNX and CNXM 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 $2.3 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 $2.3 billion senior secured credit facility is generally limited to a borrowing base. Our borrowing base is determined by the required number of lenders in good faith calculating a loan value of the Company’s proved natural gas reserves. The borrowing base under our senior secured credit facility is currently $2.3 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 2020. The various matters which we describe in other risk factors that can decrease our proved natural gas reserves including lower natural gas prices, operating difficulties, and failure to replace our proved reserves could also decrease our borrowing base. Our borrowing base could also decrease as a result of new lending requirements or regulations or the issuance of new indebtedness. If our borrowing base declined significantly below $2.3 billion, CNX may be unable to implement our drilling and development plans, make acquisitions or otherwise carry out our business plan which could materially adversely


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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.

Changes in federal or state income tax laws focused on natural gas exploration and development could cause our financial position and profitability to deteriorate.

The passage of legislation or any other changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas exploration and development. Any such change could negatively affect our financial condition and results of operations. For instance, recent tax law changes decreased the regular 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 changes could adversely impact our current and deferred federal and state income tax liabilities.
 
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.
 
Cyber-incidents 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 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.

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;


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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 units.

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.
Construction of new gathering, compression, dehydration, treating or other midstream assets by CNXM may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect CNXM‘s cash flows, results of operations and our financial condition.

The construction of additions or modifications to CNXM’s existing systems involves numerous regulatory, environmental, political and legal uncertainties beyond its control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If these projects are undertaken, they may not be completed on schedule, at the budgeted cost or at all. The construction of additions to CNXM’s existing assets may require it 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 CNXM to connect new natural gas supplies to existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may 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.  

Revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. For instance, if a processing facility is built, the construction may occur over an extended period of time, and CNXM may not receive any material increases in revenues until the project is completed. Additionally, facilities may be constructed to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering, compression, dehydration, treating or other midstream assets may not be able to attract enough throughput to achieve the expected investment return, which could adversely affect CNXM’s business, financial condition, results of operations, cash flows and ability to make cash distributions.

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.



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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 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.

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 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 elimination of management distraction by selling non-core assets and the receipt of cash proceeds that contribute to our liquidity. Additionally, if assets are held jointly with another party, CNX may not be permitted to dispose of these assets without the consent of our joint interest partner. Also, there can be no assurance that the assets we divest will produce anticipated proceeds. In addition, the terms of divestitures may cause a substantial portion of the benefits we anticipate receiving from them to be subject to future matters that we do not control. 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.

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. There is also the possibility that CNX may become involved in future investigations or suits, including, for example, those being brought by communities against fossil fuel producers relating to climate change, which are beginning to gain prevalence in the courts. 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 22 - 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.

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 previously announced a one-year $200 million share repurchase program that was authorized by our board of directors in September 2017, amended to increase the program to $450 million on October 30, 2017 and extended on July 30, 2018 to December 31, 2018. On October 26, 2018, our board of directors approved an additional $300 million share repurchase authorization, which is not subject to an expiration date. 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,


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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.

Negative public perception regarding our industry could have an adverse effect on our operations.

Negative public perception regarding our industry resulting from, among other things, operational incidents or concerns raised by advocacy groups, related to environmental, health, or community impacts 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 increased risk of litigation. 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.
 
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 $192 million at the time of the separation. 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. 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.

ITEM 1B.
Unresolved Staff Comments

None.

ITEM 2.
Properties

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

ITEM 3.
Legal Proceedings

Note 22–Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K is incorporated herein by reference.

ITEM 4.
Mine Safety and Health Administration Safety Data

Not applicable.



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PART II

ITEM 5.
Market for Registrant's Common Equity and 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, 2019, there were 108 holders of record of our common stock.

The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CNX to the cumulative shareholder return for the same period of a peer group and the Standard & Poor's 500 Stock Index. The peer group has changed from the prior year in order to benchmark CNX against core peers found in the Appalachian Basin. 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, 2014. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2019.
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
2019
CNX Resources Corporation
 
100.0

 
23.9

 
55.2

 
51.2

 
40.0

 
31.0

Peer Group
 
100.0

 
49.2