2018 Annual Report
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, 2018
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
(State or other jurisdiction of
incorporation or organization)
51-0337383
(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
Common Stock ($.01 par value)
Preferred Share Purchase Rights
Name of exchange on which registered
New York Stock Exchange
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
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
No
Securities registered pursuant to Section 12(g) of the Act: None
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-
K or any amendment to this Form 10-K.
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
Smaller Reporting Company
Emerging Growth Company
Non-accelerated filer
Accelerated filer
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, 2018, the last business day of the registrant's
most recently completed second fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was
$1,652,490,069.
The number of shares outstanding of the registrant's common stock as of January 18, 2019 is 198,335,252 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of CNX's Proxy Statement for the Annual Meeting of Shareholders to be held on May 29, 2019, are incorporated by reference in Items 10,
11, 12, 13 and 14 of Part III.
TABLE OF CONTENTS
PART I
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety and Health Administration Safety Data
PART II
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases
of Equity Securities
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
Controls and Procedures
Other Information
Directors and Executive Officers of the Registrant
Executive Compensation
PART III
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions and Director Independence
Principal Accounting Fees and Services
Exhibits and Financial Statement Schedules
Form 10-K Summary
PART IV
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
ITEM 15.
ITEM 16.
SIGNATURES
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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 - 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.
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.
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:
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prices for natural gas and natural gas liquids are volatile and can fluctuate widely based upon a number of factors beyond
our control including oversupply relative to the demand for our products, weather and the price and availability of
alternative fuels;
our dependence on gathering, processing and transportation facilities and other midstream facilities owned by 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 and developing natural gas wells;
our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that
could materially alter the occurrence or timing of their drilling;
challenges associated with strategic determinations, including the allocation of capital and other resources to strategic
opportunities;
our development and exploration projects, as well as CNXM’s midstream system development, require substantial capital
expenditures;
the impact of potential, as well as any adopted environmental regulations including any relating to greenhouse gas
emissions on our operating costs as well as on the market for natural gas and for our securities;
environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural
gas with potential short and long-term liabilities;
our operations are subject to operating risks that could increase our operating expenses and decrease our production levels
which could adversely affect our results of operation and our operations are also subject to hazards and any losses or
liabilities we suffer from hazards, which occur in our operations may not be fully covered by our insurance policies;
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;
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, which
could impair our profitability;
deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide
financial downturn, or negative credit market conditions;
hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
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;
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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 find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves;
risks associated with our debt;
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 and 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;
the separation of CONSOL Energy could result in substantial tax liability; and
other factors discussed in this 2018 Form 10-K under “Risk Factors,” as updated by any subsequent Forms 10-Q, which
are on file with the Securities and Exchange Commission.
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5
ITEM 1.
Business
General
PART I
CNX Resources Corporation (CNX or the Company) is a premiere independent oil and gas company that is 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 was incorporated in Delaware in 1991 under the name CONSOL Energy Inc. (CONSOL Energy), but its predecessors
had been mining coal, primarily in the Appalachian Basin, since 1864. 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.
On November 28, 2017, CNX completed the tax-free spin-off of its coal business resulting in two independent, publicly
traded companies: CONSOL Energy, a coal company, formerly known as CONSOL Mining Corporation; and CNX, a natural gas
exploration and production company. As a result of the separation of the two companies, CONSOL Energy and its subsidiaries
now hold the coal assets previously held by CNX, including its Pennsylvania Mining Complex, Baltimore Marine Terminal, its
direct and indirect ownership interest in CONSOL Coal Resources LP, formerly known as CNXC Coal Resources LP, and other
related coal assets previously held by CNX. The coal company, previously reported as the Company's Pennsylvania Mining
Operations division, has been reclassified in the Audited Consolidated Financial Statements in Item 8 of this Annual Report on
Form 10-K (the Form 10-K) to discontinued operations in 2017 as well as all prior periods presented.
CNX 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, our legacy surface acreage position,
our regional operating expertise, our 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 570% to produce a total of 507.1 net Bcfe in 2018, which 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 and
incorporated herein.
Our land holdings in the Marcellus Shale and Utica Shale plays cover large areas, provide multi-year drilling opportunities
and, collectively, have sustainable lower-risk growth profiles. We currently control approximately 539,000 net acres in the Marcellus
Shale and approximately 627,000 net acres that have Utica Shale potential in Ohio, West Virginia, and Pennsylvania. We also have
approximately 2.5 million net acres in our coalbed methane play.
Highlights of our 2018 production include the following:
• Total average production of 1,389,325 Mcfe per day;
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92% Natural Gas, 8% Liquids; and
57% Marcellus, 30% Utica, 12% coalbed methane, and 1% other.
At December 31, 2018, our proved natural gas, NGL, condensate and oil reserves (collectively, "natural gas reserves") had
the following characteristics:
7.9 Tcfe of proved reserves;
94.4% natural gas;
57.0% proved developed;
98.6% operated; and
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• A reserve life ratio of 15.54 years (based on 2018 production).
6
The following map provides the location of CNX's E&P operations by region:
CNX defines itself through its core 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. The U.S.
electric power industry generates more than half of its output by burning fossil fuels. We believe that the use of natural gas as one
of the principal fuel sources for electricity in the United States will continue for many years; in fact, the Energy Information Agency
(EIA) forecasts that U.S. electricity generation from natural gas will increase by 40% by 2030 and by more than 50% by 2040.
Natural gas is the dominant choice for space and water heating fuel in the U.S. domestic residential sector, and EIA forecasts gas
consumption for this use to increase modestly over the next decades. Plentiful natural gas is also creating growing opportunities
as feedstock for chemicals, plastics, and fertilizer manufacturing in the U.S. and for rapidly expanding exports, as the U.S. becomes
a net exporter of the fuel. Additionally, we believe that, as both worldwide economies and U.S. export facilities expand, the demand
for our natural gas will grow as well.
CNX's Strategy
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 and NGL 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 growth capital requirements.
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We expect natural gas to continue to be the dominant contributor to the domestic electricity generation mix, while fueling
industrial growth in the U.S. economy. EIA forecasts that natural gas will be the single dominant fuel (including renewables and
nuclear as “fuels”) for electricity generation out through 2050, and that total domestic natural gas consumption will increase 19%
in that time. The Gas Exporting Countries Forum (GECF) forecasts global demand for gas to increase by 46% to 5.43 trillion cubic
meters by 2040, according to the "Global Gas Outlook 2040". It also stated that generating electricity and the industrial sector will
contribute the most to the growing demand and that the share of natural gas in the global energy balance will increase from 22%
to 26% by 2040. With the recent growth of natural gas exports to Mexico and Canada, the United States becoming a net exporter
of natural gas, and increasing liquefied natural gas (LNG) demand, we expect new markets to open in the coming years. We believe
that our growth in natural gas production, our low drilling and operating costs, our leverage and liquidity positions, and our vast
acreage will allow CNX to take advantage of these markets.
CNX's Capital Expenditure Budget
In 2019, CNX expects capital expenditures of approximately $1,000-$1,080 million. The 2019 budget includes $575-$625
million of drilling and completion ("D&C") capital and approximately $175 million of capital associated with land, midstream,
and water infrastructure and $250-$280 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 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 539,000 net Marcellus
Shale acres at December 31, 2018.
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 45,000 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 incentive distribution rights in CNXM,
the entity that constructs and operates the gathering system for most of our Marcellus shale production. See "Midstream Gas
Services" for a more detailed explanation.
Utica Shale
We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 627,000 net Utica
Shale acres at December 31, 2018. Approximately 356,000 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 2,100,00 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 968,000 net acres at December 31, 2018. The
majority of our shallow oil and gas leasehold position is held by production and all of it is extensively overlain by existing third-
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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).
Summary of Properties as of December 31, 2018
Estimated Net Proved Reserves (MMcfe)
Percent Developed
Net Producing Wells (including oil and gob
wells)
Net Acreage Position:
Net Proved Developed Acres
Net Proved Undeveloped Acres
Net Unproved Acres(1)
Total Net Acres(2)
_________
Marcellus
Segment
5,595,409
Utica
Segment
CBM
Segment
Other Gas
Segment
Total
1,067,617
1,209,638
8,671
7,881,335
54%
355
42,853
26,324
515,073
584,250
49%
45
77%
100%
57%
4,152
71
4,623
12,090
7,046
252,473
271,609
231,415
—
2,227,764
2,459,179
3,244
—
965,118
968,362
289,602
33,370
3,960,428
4,283,400
(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, 2018, the number of producing wells, developed acreage and undeveloped
acreage:
Producing Gas Wells (including gob wells)
Producing Oil Wells
Net Acreage Position:
Proved Developed Acreage
Proved Undeveloped Acreage
Unproved Acreage
Total Acreage
Gross
Net(1)
6,453
149
4,623
1
289,602
33,370
4,940,180
5,263,152
289,602
33,370
3,960,428
4,283,400
(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:
Held by production/fee
Expiration within 2 years
Expiration beyond 2 years
Total Acreage
Gross
Unproved Acres
Net Unproved
Acres
4,797,145
3,896,613
87,553
55,482
37,115
26,700
4,940,180
3,960,428
Net Proved
Undeveloped
Acres
18,524
7,628
7,218
33,370
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, 2018, 2017 and 2016, we drilled 83.9, 90.0 and 36.0 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 2018, there were 22.0 net development wells and no exploratory wells drilled but uncompleted. There were no dry
development wells in 2018, 2017, or 2016. As of December 31, 2018, there are 8.0 gross completed developmental wells ready
to be turned in-line. The following table illustrates the net wells drilled by well classification type:
Marcellus segment
Utica segment
CBM segment
Other Gas segment
Total Development Wells (Net)
Exploratory Wells (Net)
For the Year
Ended December 31,
2018
2017
2016
65.9
12.0
6.0
—
83.9
9.0
17.0
64.0
—
90.0
—
13.0
23.0
—
36.0
There were no exploratory wells drilled during the year ended December 31, 2018. There were 4.0 net exploratory wells
drilled during the year ended December 31, 2017 and no exploratory wells drilled during the year ended December 31, 2016. As
of December 31, 2018, there are 4.0 net exploratory wells in process. The following table illustrates the exploratory wells drilled
by well classification type:
For the Year Ended December 31,
2018
2017
2016
Producing Dry
Still Eval.
Producing Dry
Still Eval.
Producing Dry
Still Eval.
Marcellus segment
Utica segment
CBM segment
Other Gas segment
Total Exploratory Wells (Net)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— —
4.0 —
—
—
—
—
4.0 —
—
—
—
—
—
—
—
—
—
— —
— —
— —
—
—
—
—
—
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).
Proved developed reserves
Proved undeveloped reserves
Total proved developed and undeveloped reserves(1)
Net Reserves
(Million cubic feet equivalent)
as of December 31,
2018
2017
2016
4,494,878
4,409,065
3,683,302
3,386,457
3,172,547
2,568,346
7,881,335
7,581,612
6,251,648
___________
(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%:
Future net cash flows
Total PV-10 measure of pre-tax discounted future net cash flows (1)
Total standardized measure of after tax discounted future net cash flows
____________
Discounted Future
Net Cash Flows
(Dollars in millions)
2018
2017
2016
$ 13,132
$ 7,841
$ 2,419
$ 6,172
$ 4,140
$ 1,559
$ 4,655
$ 3,131
$
955
(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.
11
Reconciliation of PV-10 to Standardized Measure
Future cash inflows
Future production costs
Future development costs (including abandonments)
Future net cash flows (pre-tax)
10% discount factor
PV-10 (Non-GAAP measure)
Undiscounted income taxes
10% discount factor
Discounted income taxes
Standardized GAAP measure
Gas Production
The following table sets forth net sales volumes produced for the periods indicated:
2016
2018
As of December 31,
2017
(Dollars in millions)
$ 19,262
(7,234)
(1,711)
10,317
(6,177)
4,140
(2,476)
1,467
(1,009)
3,131
$ 26,610
(7,730)
(1,600)
17,280
(11,108)
6,172
(4,147)
2,630
(1,517)
4,655
$ 11,303
(5,851)
(1,550)
3,902
(2,343)
1,559
(1,483)
879
(604)
955
$
$
$
For the Year
Ended December 31,
2017
2016
2018
Natural Gas
Sales Volume (MMcf)
Marcellus
Utica
CBM
Other
Total
NGL
Sales Volume (Mbbls)
Marcellus
Utica
Other
Total
Oil and Condensate
Sales Volume (Mbbls)
Marcellus
Utica
Other
Total
255,127
148,117
60,268
4,714
468,226
209,687
70,708
65,373
19,125
364,893
186,812
71,277
68,971
21,693
348,753
5,227
853
1
6,081
286
78
35
399
4,604
1,851
1
6,456
346
204
39
589
3,922
2,787
1
6,710
360
470
65
895
Total Sales Volume (MMcfe)
Marcellus
Utica
CBM
Other
Total
*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 and incorporated herein.
239,387
83,038
65,373
19,368
407,166
212,504
90,820
68,971
22,092
394,387
288,203
153,704
60,268
4,929
507,104
12
CNX expects a minimum base for 2019 annual natural gas production volumes of 495-515 Bcfe, which equates to an
approximately 5% annual increase, based on the midpoint of guidance, compared to 2018 volumes when excluding production
from assets that were sold.
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.
Average Sales Price - Gas (Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
Average Sales Price - NGLs (Mcfe)*
Average Sales Price - Oil (Mcfe)*
Average Sales Price - Condensate (Mcfe)*
Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments
Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments
Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)
Average Sales Price - NGLs (Bbl)
Average Sales Price - Oil (Bbl)
Average Sales Price - Condensate (Bbl)
For the Year
Ended December 31,
2018
2017
2016
$ 1.92
$ 2.59
$ 2.97
$ (0.15) $ (0.11) $ 0.70
$ 2.42
$ 4.03
$ 4.55
$ 9.89
$ 7.56
$ 6.15
$ 8.43
$ 6.59
$ 4.58
$ 2.97
$ 2.66
$ 2.63
$ 3.11
$ 2.76
$ 2.01
$ 0.19
$ 0.22
$ 0.24
$ 27.30
$ 24.18
$ 14.52
$ 59.34
$ 45.36
$ 36.90
$ 50.58
$ 39.54
$ 27.48
*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 $0.14 per Mcfe, $0.17 per Mcfe, and $0.09 per Mcfe for 2018, 2017, and
2016, 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 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. The notional volumes associated with these gas swaps represented
approximately 312.2 Bcf of our produced gas sales volumes for the year ended December 31, 2017 at an average price of $2.60
per Mcf. As of January 18, 2019, these physical and swap transactions represent approximately 376.0 Bcf of our estimated 2019
production at an average price of $2.71 per Mcf, 468.6 Bcf of our estimated 2020 production at an average price of $2.55 per Mcf,
410.3 Bcf of our estimated 2021 production at an average price of $2.44 per Mcf, approximately 276.6 Bcf of our estimated 2022
production at an average price of $2.48 per Mcf, and approximately 127.0 Bcf of our estimated 2023 production at an average
price of $2.35 per Mcf.
The 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, overtime CNX has acquired extensive gathering assets. CNX now owns or operates
approximately 2,500 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. With respect to
the Utica Shale, 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
On January 3, 2018, CNX closed its previously announced acquisition of Noble Energy’s (Noble) 50% membership interest
in CONE Gathering LLC, which holds the general partner interest and incentive distribution rights in CONE Midstream Partners
LP. In conjunction with the closing, CONE Midstream Partners LP was renamed CNX Midstream Partners LP (CNX Midstream
or CNXM) and CONE Gathering LLC was renamed CNX Gathering LLC (CNX Gathering) (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).
Also on January 3, 2018, the Company’s board of directors authorized CNX Midstream to enter into an amendment to 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 right-of-
ways, 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 Marcellus Shale
development plan.
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 2018. The EIA reported
485,383 producing natural gas wells in the United States at December 31, 2017 (the latest year for which government statistics
are available), which is approximately 15% lower than 2016.
14
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 35% of U.S. electricity
generation during the twelve months ended October 31, 2018, up from 32% in 2017. According to the EIA, from January through
June of 2018, net natural gas exports from the United States averaged 0.87 billion cubic feet per day (Bcf/d), more than double
the average daily net exports during all of 2017 (0.34 Bcf/d). The United States, which became a net natural gas exporter on an
annual basis in 2016 for the first time in almost 60 years, has continued to export more natural gas than it imports for five of the
first six months in 2018. U.S. natural gas exports have increased primarily with the addition of new LNG export facilities in the
Lower 48 states. The EIA also states that U.S. exports of LNG through the first half of 2018 rose 58% compared with the same
period in 2017. 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 2019 to increase 1.3% from 2018. CNX estimates 2019 in-basin (Ohio, West Virginia, and Pennsylvania) demand to increase
by approximately 3% compared with 2018. 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, 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, 2018, CNX had 564 employees, none of whom are subject to a collective bargaining agreement.
Industry Segments
Financial information concerning industry segments, as defined by accounting principles generally accepted in the United
States, for the years ended December 31, 2018, 2017 and 2016 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 incorporated herein.
Financial Information about Geographic Areas
All of the Company's assets and operations are located in the continental United States.
15
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.
Scrutiny of hydraulic fracturing activities also continues in other ways. 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.
16
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 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 such changes which 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 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. The consent order requires the EPA to revise the applicability determination by
March 15, 2019.
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
17
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 facilities is the subject of ongoing 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 this 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
pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are available,
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.
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Executive Officers of the Registrant
Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Executive
Officers of CNX” (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. The
following sets forth factors related to our business, operations, financial position or future financial performance or cash flows
which 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. The disposition in 2017 of our entire coal operations has increased our
exposure to fluctuations in the price of natural gas, NGLs, oil and condensate.
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 in 2012 resulted in domestic prices hovering around ten-year lows, and
drilling continued in these plays, despite these lower gas prices, to meet drilling commitments. Although gas prices have arguably
recovered as of 2018, 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 Pennsylvania, West
Virginia and Ohio more than tripling 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 through pipelines. This export causes gas purchased 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. In addition, similar to the oversupply of
natural gas, increased drilling activity by third-parties in formations containing NGLs has led to a decline of over 40% since 2014
in the uplift we receive, on an Mcf equivalent basis when excluding hedging impact, from 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
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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 interconnected
to third parties’ or CNXM’s gathering systems 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 if pipeline or facility capacity is unexpectedly disrupted for any reason, our
natural gas sales and/or sales of NGLs could be reduced, which could negatively affect our profitability. If we cannot access
processing pipeline transportation facilities, we may have to reduce our production of natural gas. If our sales of natural gas or
NGLs are reduced because of transportation or processing constraints, our revenues will be reduced and our unit costs will increase.
If pipeline quality standards change or we cannot meet applicable standards, we might be required to install additional processing
equipment which could increase our costs. Further, in some circumstances we need to meet predetermined specifications with
respect to our blending of dry and damp gas; changes in the production mix could negatively impact our ability to efficiently meet
our specified requirements. Pipelines could also curtail our flows until the natural gas delivered to their pipeline is in compliance.
Any reduction in our production of natural gas or increase in our costs could have a material adverse effect on 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. Any reduction in capacity on the Texas Eastern
pipeline could result in curtailments and reduce our production of natural gas. A reduction in capacity 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. We are obligated to pay
fees on minimum volumes to our service providers regardless of actual volume throughput. Reductions in our drilling program
may result in insufficient production to utilize our full firm transportation and processing capacity. If we have insufficient production
to meet the minimum volumes, our cash flow from operations will be reduced, 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 through CNXM is intended, among other items, to connect our wells to other
existing gathering and transmission pipelines. Our infrastructure development and maintenance programs, through CNXM, can
involve significant risks, including those relating to timing, cost overruns and operational efficiency, which risks can be further
affected by other issues. For example, approximately 34% of our 2018 production flowed through CNXM’s Majorsville and
McQuay Stations. An operational issue at either 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 third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities is not
within our or CNXM’s control. These third-party pipelines, processing and fractionation plants, compressor stations and other
midstream 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. Natural gas reserves require subjective estimates of underground accumulations of natural
gas, and assumptions concerning natural gas prices, production levels, reserve estimates and operating and development costs. As
a result, estimated quantities of proved natural gas reserves and projections of future production rates and the timing of development
expenditures may prove to be incorrect. For example, a significant amount of our proved undeveloped reserves extensions and
discoveries during the last three years were due to the addition of wells on our Marcellus Shale acreage more than one offset
location away from existing production with reliable technology, which may be more susceptible to positive and negative changes
in reserve estimates than our proved developed reserves. Over time, material changes to reserve estimates may be made, taking
into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding natural gas prices,
production levels, and operating and development costs that may prove to be incorrect. Any significant variance from these
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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. Numerous changes over time to the assumptions on which our reserve estimates are
based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from reserve
estimates. 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 reserves. We base the estimated discounted future net cash flows from our
proved natural gas reserves on historical average prices and costs. However, actual future net cash flows from our natural gas
properties also will be affected by factors such as:
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geological conditions;
our acreage position, and our ability to acquire additional acreage, including 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 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, 2018 would decrease from $6.2 billion to $6.0 billion.
Each of the factors impacting reserve estimation may in fact vary considerably from the assumptions used in estimating
the reserves. For these reasons, estimates of natural gas reserves may vary substantially. Actual production, revenues and
expenditures with respect to our natural gas reserves will likely vary from estimates, and these variances may be material. As a
result, our estimates may not accurately reflect our actual natural gas reserves.
Developing and producing natural gas wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil 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, including those discussed in “Our operations are subject
to operating risks that could increase our operating expenses and decrease our production levels which could adversely affect
our results of operations. Our operations are also subject to hazards, and any losses or liabilities, we suffer from such hazards
may not be fully covered by our insurance policies” set forth below.
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. Our overall drilling success rate or our drilling success rate within a
particular geographic area may decline. We may be unable to drill identified or budgeted wells within our expected time frame,
or at all. We may be unable to drill a particular well because, in some cases, we identify a drilling location before we have leased
all of the interests required to drill the well in that location. Similarly, our drilling schedule may vary from our capital budget. The
final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors,
including:
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the results of delineation efforts and the acquisition, review and analysis of 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;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural
gas and oil and the availability of drilling rigs and crews;
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the formation as to which we drill, as the cost structure between wet gas which requires additional processing
and dry gas varies; and
our financial resources and results.
Our business strategy focuses on horizontal drilling and production in the Marcellus and Utica Shale plays in the Appalachian
Basin. Drilling horizontal wells is technologically difficult and involves risks relating to our ability to fracture stimulate the planned
number of stages and to successfully run casing the length of the well bore and involves a higher risk of failure when compared
to vertical wells. Additionally, drilling a horizontal well involves higher costs, which results in the risks of our drilling program
being spread over a smaller number of wells, and that, in order to be profitable, each horizontal well will need to produce at a
higher level in order to cover the higher drilling costs. Similarly, the average lateral length of the horizontal wells we drill has
generally been increasing. Longer-lateral wells are typically more expensive and require more time for preparation and permitting.
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 we
might find it more difficult to achieve economic success in our drilling program.
Our operations are subject to operating risks that could increase our operating expenses and decrease our production levels,
which could adversely affect our results of operations. Our operations are also subject to hazards, and any losses or liabilities
we suffer from such hazards may not be fully covered by our insurance policies.
Our exploration for and production of natural gas and CNXM’s gathering, compression and transportation operations
involve numerous operational risks. The cost of drilling, completing and operating our shale gas wells, shallow oil and gas wells
and coalbed methane (CBM) wells 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 thereby
adversely affecting our operating results. The risks that may have a significant impact on our natural gas operations include those
relating to, among other things, unexpected drilling conditions (pressure or irregularities in geologic formations or wells, material
and equipment failures, fires, ruptures, landslides, mine subsidence, explosions or other accidents and environmental concerns
and adverse weather conditions); similar operational or design issues relating to pipelines, compressor stations, pump stations,
related equipment and surrounding properties, including with respect to materials and equipment developed, designed or installed
or properties owned or operated by third-parties; challenges relating to transportation, pipeline infrastructure and capacity for
treatment or disposal of waste water generated in drilling, completion and production 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:
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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 of these events in our gas operations that prevents delivery of natural gas to a customer and is not
excusable as a force majeure event under our supply agreement, could result in economic penalties, suspension or ultimately
termination of the supply agreement.
Although we and CNXM maintain insurance for a number of risks and hazards, we may not be insured or fully insured
against the losses or liabilities that could arise from a significant accident or disruption in our operations. We may elect not to
obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not
fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash
flows.
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Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could
materially alter the occurrence or timing of their drilling.
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 growth strategy. Our
ability to drill and develop these locations depends on a number of uncertainties, 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. We will 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 have a material adverse effect on 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 drilling), 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 we fail to identify optimal business strategies or fail to optimize our capital investment and capital
raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future
growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our
business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Our development and exploration projects, as well as CNXM’s midstream system development, 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, we expect to continue to make substantial capital expenditures in the development
and acquisition of natural gas reserves. Further, CNXM will need to make substantial capital expenditures to fund its share of
growth capital expenditures associated with its Anchor Systems, as well as to fund its share of expenditures associated with its
5% controlling interests in the Additional Systems or to purchase or construct new midstream systems. If CNXM is unable to
make sufficient or effective capital expenditures, it will be unable to maintain and grow its business.
CNXM's amended gathering agreement with us, CNXM's largest customer, includes minimum well commitments; however,
that gas gathering agreement and the gas gathering agreements 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 decreases 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 we 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 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, we could be required to curtail the pace of the development
of our natural gas properties and midstream activities, which in turn could lead to a decline in our reserves and production, and
could adversely affect our business, financial condition and results of operations.
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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. On August 3, 2015, the EPA finalized the Carbon Pollution Standards to cut carbon
emissions from new, modified and reconstructed power plants, which became effective on October 23, 2015. In August 2015, the
EPA finalized the Clean Power Plan Rule to cut carbon pollution from existing power plants, which became effective on December
22, 2015. While consolidated petitions challenging the Clean Power Plan Rule are ongoing at the circuit court level, a mid-litigation
application to the Supreme Court has resulted in a current stay of the Clean Power Plan Rule. 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.” The comment period on the proposal closed on October 31, 2018, and the EPA is considering
the comments submitted. On November 21, 2018, the EPA filed a status report in which the EPA indicated that it expected to take
final rulemaking action on a replacement rule for the Clean Power Plan by the first part of 2019.
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 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, but this rule is not yet final and is subject to public
notice, comment, and legal challenges.
Additionally, the application of the CAA to CNX and CNXM facilities, as well as the application of state sponsored permitting
programs provide regulatory uncertainty and therefore present risks, including risks regarding hitting production objectives, and
cost for controls and compliance. Some states in which we operate, including Pennsylvania are contemplating measures, or have
issued mandates, to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and
potential cap-and-trade programs. Most of these 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.
We 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. Numerous governmental authorities, such as the EPA and analogous state
agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes
requiring difficult and costly response actions. 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 permits 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, may also have the right to pursue legal actions to enforce
compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or
property damage. We 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, 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 hazardous substances,
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hydrocarbons or solid wastes have been stored or released. We may also be subject to fines and penalties for such releases. We
may be required to remediate contaminated properties currently or formerly operated by us regardless of whether such contamination
resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at
the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result
from the environmental, health and safety impacts of our operations.
The Federal Endangered Species Act (ESA) and similar state laws protect species endangered or threatened with extinction.
Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, or to develop
and implement species-specific protection and enhancement plans and schedules to avoid or minimize impacts to endangered
species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA, including
the Northern Long-Earned and Indiana bats. Further consideration for listing species within our operating region is expected, and
CNX considers this uncertainty, as well as the cost to comply with stringent mitigation requirements, a risk to cost and operational
timing.
CNX utilizes pipelines extensively for its natural gas and water businesses. Stream encroachment and crossing permits
from the Army Corps of Engineers (ACOE) are often required for certain impacts these pipelines cause to streams and wetlands.
In June 2017, the EPA and the Army Corps of Engineers proposed a rule that would initiate the first step in a two-step process
intended to review and 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. This proposal is subject to public comment and the rulemaking process. The second step would be a notice-
and-comment rulemaking in which federal agencies will conduct a substantive reevaluation of such definition. While we 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.
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.
We 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. We contract 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, this equipment and for qualified and experienced field personnel to drill wells,
construct pipelines and conduct field operations, geologists, geophysicists, engineers, 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, we cannot assure that we will be able
to obtain necessary services, drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience
shortages of, or increases in the costs of, drilling equipment, crews and associated supplies, equipment and field services in the
future.
Any of the above shortages may lead to escalating prices for drilling equipment, land services, crews and associated
supplies, equipment and services. Shortages may lead to poor service and inefficient drilling operations and increase the possibility
of accidents due to the hiring of inexperienced personnel and overuse of equipment by contractors. Additionally, a decrease in the
availability of these services, equipment and personnel could lead to a decrease in our natural gas production, 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 and adversely impact our business,
financial condition, results of operations, or cash flows.
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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, 2018 and 2017,
due to the oversupply of gas in our markets, we made payments under these types of contracts of approximately $7 million and
$40 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 we can produce economically. This may result in our having to make substantial downward adjustments to our
estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our
exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value
of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances
lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may
not be recoverable or whenever management's plans change with respect to those assets. For example, in the second quarter of
2015, we had an impairment charge of approximately $829 million for certain of our natural gas assets, primarily shallow oil and
gas assets. We may incur impairment charges in the future, which could have an adverse effect on our results of operations in the
period taken.
As a result of our acquisition of the 50% interest in CNX Gathering in the first quarter of 2018, we acquired approximately
$925 million of goodwill and other intangible assets. Future acquisitions may also lead to the acquisition of additional goodwill
or other intangible assets. At least annually, or whenever events or changes in circumstances indicate a potential impairment in
the carrying value as defined by GAAP, we will evaluate this goodwill and other intangible assets for impairment by first assessing
qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely
than not that the fair value of the reporting unit is less than the carrying amount. Estimated fair values could change if, for example,
there are changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions
or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market
capitalization. The future impairment of these assets could require material non-cash charges to our results of operations, which
could have a material adverse effect on our reported earnings and results of operations for the affected periods. In May 2018, CNX
determined that the carrying value of a portion of the customer relationship intangible assets that were acquired in connection with
the Midstream Acquisition exceeded their fair value in conjunction with the Asset Exchange Agreement with HG Energy II
Appalachia, LLC (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in
Item 8 of this Form 10-K for further discussion). CNX recognized an impairment on this intangible asset of $19 million, which
is included in Impairment of Other Intangible Assets in the Consolidated Statements of Income.
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
emergence of stand-alone midstream companies. Many of the companies with which we 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. 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. The competitive environment can
also make it more challenging to discover new natural gas resources, evaluate and select suitable properties and to consummate
these transactions on acceptable terms. Any reduction in our ability to compete in current or future natural gas markets could have
a material adverse effect on our business, financial condition, results of operations and cash flows.
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Additionally, CNXM’s ability to increase throughput on its midstream systems and any related revenue from third-parties
is subject to capacity availability on its existing systems, its ability to expand its existing systems, contractual obligations to its
existing customers and competition from third parties, primarily operators of other natural gas gathering systems. The fact that a
substantial majority of the capacity of CNXM’s midstream systems will be necessary to service the production of CNX and one
third-party customer and we and that third-party will receive priority of service for the provision of CNXM midstream services
over other third-parties, may result in CNXM not having the capacity to provide services to other third-party customers. 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 have a material adverse effect on CNXM’s
business, results of operations, financial condition, cash flows and ability to make cash distributions and therefore, could have a
material adverse effect on 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 we 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. In addition, liquidity is essential to
our business and developing our assets. 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:
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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;
the tightening of credit or lack of credit availability to our customers could adversely affect us, as our ability to
receive payment for natural gas sold and delivered depends on the continued creditworthiness of our customers;
our ability to access the capital markets may be restricted at a time when we 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 18, 2019, we expect these transactions will represent approximately 376.0 Bcf
of our estimated 2019 production at an average price of $2.71 per Mcf, 468.6 Bcf of our estimated 2020 production at an average
price of $2.55 per Mcf, 410.3 Bcf of our estimated 2021 production at an average price of $2.44 per Mcf, 276.6 Bcf of our estimated
2022 production at an average price of $2.48 per Mcf, and 127.0 Bcf of our estimated 2023 production at an average price of $2.35
per Mcf. To the extent that we engage in hedging activities, we 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 hedging arrangements in the future, reduce our future use
of hedging arrangements or are unable to engage in hedging arrangements due to lack of acceptable counterparties, we may be
more adversely affected by changes in natural gas prices than 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.
In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in
which:
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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 governmental regulations applicable to the natural gas industry that are not directly related to
environmental regulation, many of which are under constant review for amendment or expansion at the federal and state level.
Any future modifications in such regulations, changes promulgated by the courts, or interruptions experienced in the operation of
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our governing bodies, may affect, among other things, our ability to develop the resource, obtain permits, as well as, potential
impacts to the 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 the facility or services provided by it are 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 begun to adopt 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. For example, a recent Pennsylvania case currently on appeal involves concepts of
landowner rights, trespass claims and the historic common law concept of “rule of capture.” Although the case has not yet been
resolved, the ultimate judicial outcome could negatively impact future shale drilling and hydraulic fracturing within the
Commonwealth of Pennsylvania if the court finds that fracking could be considered trespassing in certain circumstances.
We 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 regulations requiring pipeline operators
to develop integrity management programs for transportation pipelines and related facilities located where a leak or rupture could
do the most harm, i.e., in “high consequence areas.” The regulations require operators to:
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perform ongoing assessments of pipeline and related facility integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
Should our or CNXM's operations fail to comply with PHMSA or comparable state regulations, we could be subject to
substantial penalties and fines, including civil penalties of up to $209,000 per violation, with a maximum of $2,909,022 for those
related series of violations. In January 2017, PHMSA released a pre-publication copy of its final hazardous liquid pipeline safety
regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would
impose additional obligations on hazardous liquid pipeline operators that are already subject to the integrity management
requirements. However, due to the change in Presidential administrations, PHMSA’s final hazardous liquid pipeline safety rule
has not yet taken effect, though PHMSA is expected to finalize its hazardous liquid pipeline safety in the near term. PHMSA’s
proposed rule would also require annual reporting of safety-related conditions and incident reports for all hazardous liquid gathering
lines and gravity lines, including pipelines exempt from PHMSA regulations.
PHMSA also issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and
response measures on natural gas and hazardous liquid pipeline operators and in April 2016, published a Notice of Proposed Rule
making that would significantly modify existing regulations related to reporting, impact, design, construction, maintenance,
operations and integrity management of gas transmission and gathering pipelines. As proposed, compliance with the rule could
have a material adverse effect on our or CNXM's operations. However, the ultimate impact of the rule on our and CNXM remains
uncertain until the rulemaking is finalized. 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 we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory
changes could have a material effect on our cash flow.
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Our shale gas drilling and production operations require both 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 we 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. These processes 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 that we have adequate water available for our operations, we 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,
we may be required to truck water, and we may not be able to contract for sufficient water hauling trucks to meet our needs.
Further, we must remove the portion of the water that flows back to the well bore, as well as drilling fluids and other
wastes associated with the exploration, development or production of natural gas. This water can be either disposed of or recycled
for use in other hydraulic fracturing operations. In the event we are forced to dispose of water rather than recycle it, our costs may
increase. In addition, in our CBM drilling and production, coal seams frequently contain water that must be removed and disposed
of in order for the natural gas to detach from the coal and flow to the well bore.
Our inability to obtain sufficient amounts of water with respect to our shale operations, or the inability to dispose of or
recycle water and other wastes used in 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 find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves will cause
our levels of natural gas 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. Because total estimated proved reserves include our proved undeveloped reserves at
December 31, 2018, production is expected to decline even if those proved undeveloped reserves are developed and the wells
produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we
have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore,
our cash flow and income are highly dependent on our success in efficiently developing, exploiting and selling our current reserves
and economically finding or acquiring additional economically recoverable reserves. We 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 execute agreements with other third-parties 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.
The provisions of our debt agreements and those of CNXM, and the risks associated therewith could adversely affect our
business, financial condition, liquidity and results of operations.
As of December 31, 2018, CNX's total long-term indebtedness, excluding CNXM, was approximately $1.9 billion of
which approximately (i) $1.3 billion was under our 5.875% senior unsecured notes due 2022 plus $2.1 million of unamortized
bond premium, (ii) $612.0 million was under our senior secured credit facility and (iii) $13.3 million of capitalized leases due
through 2021. The degree to which we are leveraged could have important consequences, including, but not limited to:
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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;
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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.
Further, LIBOR and certain other interest rate “benchmarks” are the subject of recent national, international, and other
regulatory guidance and proposals for reform. These reforms may cause such benchmarks to perform differently than in the past
or have other consequences which cannot be predicted. On July 27, 2017, the United Kingdom’s Financial Conduct Authority,
which regulates LIBOR, publicly announced that it intends to stop persuading or compelling banks to submit LIBOR rates after
2021. It is expected that a transition away from the widespread use of LIBOR to alternative rates will occur over the course of the
next several years. As a result of this transition, LIBOR may disappear entirely or perform differently than in the past, and interest
rates on our variable rate indebtedness and other financial instruments tied to LIBOR rates, as well as the revenue and expenses
associated with those financial instruments, may be adversely affected.
Our senior secured credit facility and the indentures governing our 5.875% senior unsecured notes limit the incurrence
of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the
indentures governing our 5.875% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior
secured credit agreement, we must comply with certain financial covenants on a quarterly basis including a maximum net leverage
ratio and a minimum current ratio, as defined therein. Our senior secured credit agreement and the indentures governing our 5.875%
senior unsecured notes 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 by us to comply with these
covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on 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 certain financial and/or other restrictive covenants and other restrictions similar to those
in our senior secured credit agreement and indentures.
If our or CNXM’s cash flows and capital resources are insufficient to fund our respective debt service obligations, including
repayment of such obligations at maturity, we 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, we could face
substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and
other obligations. Our senior secured credit agreement and the indentures governing our 5.875% senior unsecured notes restrict
our ability to sell assets and the use of the proceeds from the sales. 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 lenders use the loan value of our proved natural gas reserves to determine the borrowing base under our $2.1 billion senior
secured credit facility. Our borrowing base 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 $2.1 billion could have a material adverse effect on our results of operations, financial condition and liquidity.
Our ability to borrow and have letters of credit issued under our $2.1 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 $2.1
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 2019. 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. Please read: “Risk Factors - 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” and - “Unless we replace our natural gas reserves, our natural gas reserves and production will decline,
which would adversely affect our business, financial condition, results of operations and cash flows.” 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 $2.1 billion, we may be unable to implement our drilling and development plans, make acquisitions
or otherwise carry out our business plan which could have a material adverse effect on our financial condition and results of
operations. We also could be required to repay any outstanding indebtedness in excess of the redetermined borrowing base. We
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. We may not be able to consummate
those sales or to obtain the proceeds which we could realize from them and those proceeds may not be adequate to meet any debt
service obligations then due.
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Changes in federal or state income tax laws 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 effective as of the beginning of 2018
will limit the ability of corporations to take certain interest deductions and have eliminated a corporation’s ability to take deductions
for income attributable to domestic production activities.
Additionally, legislation has been proposed from time to time in the states in which we operate - primarily Pennsylvania,
Ohio 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.
Cyber-incidents could have a material adverse effect on 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. Our insurance may not protect us against such occurrences.
Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our
business, financial condition and results of operations.
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, 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:
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a cyber-incident impacting one of our vendors or service providers could result in supply chain disruptions, loss or
corruption of our information or other negative consequences, any of which could delay or halt development of additional
infrastructure, effectively delaying the start of cash flows from the project;
a cyber-incident related to our facilities may result in equipment damage or failure;
a cyber-incident impacting midstream or downstream pipelines could prevent our product from being delivered, resulting
in a loss of revenues;
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.
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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, we 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.
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.
The construction of additions to CNXM’s existing assets may require it to obtain new rights-of-way 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.
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 have a material adverse effect on our business. Furthermore, competition for experienced technical and other
professional personnel remains strong. If we 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 and 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 and adversely affect our business and results of operations.
Our insurance may not protect us against such occurrences.
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; 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, we 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 we 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,
32
our costs of operations could be increased. We 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, we 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 we 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, we may not be permitted to dispose of these assets without the consent of our joint
venture 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.
In the future we may make acquisitions of assets or businesses that complement or expand our current business. No
assurance can be given that we 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 have a
material adverse effect on our financial condition and results of operations.
CNX and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on our business.
We are party to a number of legal proceedings in the normal course of business activities. 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 we may become involved in future 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 18- 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 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. 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.
We 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,
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 about hydraulic fracturing, emissions and pipeline projects, 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.
33
In connection with the separation, 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, CONSOL
Energy has agreed to indemnify us for certain liabilities, and we have agreed to indemnify CONSOL Energy for certain liabilities,
in each case for uncapped amounts. More specifically, CONSOL Energy assumed all liabilities related to their current and our
former coal business, including liabilities having a book value of $955 million and liabilities that may arise due to the failure of
purchasers of coal assets that we had previously disposed. Additionally, 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 we 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, we may be temporarily required to bear such losses. Each of these risks could
negatively affect our business, results of operations and financial condition.
The separation of CONSOL Energy could result in substantial tax liability.
Under current U.S. federal income tax law, even if the distribution, together with certain related transactions, otherwise
qualifies for tax-free treatment under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code, the distribution may nevertheless
be rendered taxable to us and our shareholders as a result of certain post-distribution transactions, including certain acquisitions
of shares or assets of CNX or CONSOL Energy. The possibility of rendering the distribution taxable as a result of such transactions
may limit our ability to pursue certain equity issuances, strategic transactions or other transactions that would otherwise maximize
the value of our business. Under the Tax Matters Agreement that we entered into with CONSOL Energy, CONSOL Energy may
be required to indemnify us against any additional taxes and related amounts resulting from (i) an acquisition of all or a portion
of the equity securities or assets of CONSOL Energy, whether by merger or otherwise (and regardless of whether CONSOL Energy
participated in or otherwise facilitated the acquisition), (ii) issuing equity securities beyond certain thresholds, (iii) repurchasing
shares of CONSOL Energy stock other than in certain open-market transactions, (iv) ceasing to actively conduct certain of its
businesses, (v) other actions or failures to act by CONSOL Energy or (vi) any of CONSOL Energy’s representations, covenants
or undertakings contained in any of the separation-related agreements and documents or in any documents relating to the IRS
private letter ruling and/or the opinions of tax advisors being incorrect or violated. However, the indemnity from CONSOL Energy
may not be sufficient to protect us against the full amount of such additional taxes or related 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, we may be temporarily required to bear such losses. Each of these risks could
negatively affect CNX’s business, results of operations and financial condition.
ITEM 1B.
Unresolved Staff Comments
None.
ITEM 2.
Properties
See Detail Operations in Item 1 of this 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.
34
ITEM 4.
Mine Safety and Health Administration Safety Data
Not applicable.
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, 2018, there were 116 holders of record of our common stock.
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the
common stock of CNX to the cumulative shareholder return for the same period of a peer group and the Standard & Poor's 500
Stock Index. The current peer group is comprised of CNX, Antero Resources Corporation, Cabot Oil & Gas Corporation,
Chesapeake Energy Corporation, Energen Corporation, EQT Corporation, Gulfport Energy Corporation, PDC Energy, Inc., Range
Resources Corporation, SM Energy Company, Southwestern Energy Co., Whiting Petroleum Corporation, and WPX Energy, Inc.
The graph assumes that the value of the investment in CNX common stock and each index was $100 at December 31, 2013. The
graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2018.
CNX Resources Corporation
Peer Group
S&P 500 Stock Index
2013
2014
2015
2016
2017
2018
100.0
100.0
100.0
107.4
88.3
144.4
25.7
38.8
59.3
53.1
55.0
42.3
42.9
27.6
143.4
157.0
187.4
175.8
Cumulative Total Shareholder Return Among CNX Resources Corporation, Peer Group and S&P 500 Stock Index
The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).
35
The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance
can be given that CNX will pay dividends in the future. CNX suspended its quarterly dividend in March 2016 to further reflect
the Company's increased emphasis on growth. CNX’s Board of Directors determines whether dividends will be paid quarterly.
The determination to pay dividends will depend upon, among other things, general business conditions, CNX’s financial results,
contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX and such other factors
as the Board of Directors deems relevant. The Company's credit facility limits CNX's ability to pay dividends in excess of an
annual rate of $0.50 per share when the Company's leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to
a cumulative credit calculation set forth in the facility. The total leverage ratio was 2.26 to 1.00 at December 31, 2018. The credit
facility does not permit dividend payments in the event of default. The indentures to the 2022 notes limit dividends to $0.50 per
share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other
payment limitations under the indentures. There were no defaults in the year ended December 31, 2018.
Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth repurchases of our common stock during the three months ended December 31, 2018:
ISSUER PURCHASES OF EQUITY SECURITIES
Period
(a)
Total Number of Shares
Purchased (1)
(b)
Average Price Paid per
Share
(c)
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs (2)
(d)
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs (000's
omitted)
October 1, 2018-
October 31, 2018
November 1, 2018-
November 30, 2018
December 1, 2018-
December 31, 2018
Total
3,552,158 $
712,300 $
2,230,834 $
6,495,292
14.06
14.10
12.06
3,552,158 $
712,300 $
2,230,834 $
6,495,292 $
300,643
290,597
263,684
854,924,000
(1) Includes shares withheld from employees to satisfy minimum tax withholding obligations associated with the vesting of
restricted stock during the period.
(2) Shares repurchased as part of the Company’s previously announced one-year $450 million share repurchase program authorized
by the Board of Directors in September 2017, as amended on October 30, 2017, extended on July 30, 2018, and expired on
December 31, 2018. On October 26, 2018, the Company's Board of Directors approved an additional $300 million share repurchase
authorization, which is not subject to an expiration date.
See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters”
for information relating to CNX's equity compensation plans.
36
ITEM 6.
Selected Financial Data
The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the
periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2018,
2017, 2016, 2015 and 2014 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year
data have been made to conform to the year ended December 31, 2018 presentation. The selected consolidated financial and
operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated
financial and operating data should be read in conjunction with Item 7 “Management's Discussion and Analysis of Financial
Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.
(Dollars in thousands, except per share data)
For the Years Ended December 31,
Revenue and Other Operating Income from
Continuing Operations
Income (Loss) from Continuing Operations
Net Income (Loss) Attributable to CNX
Resources Shareholders
Earnings per share:
Basic:
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations
Net Income (Loss)
Diluted:
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations
Net Income (Loss)
2018
2017
2016
2015
2014
$ 1,730,434
883,111
$
$ 1,455,131
295,039
$
759,968
$
$ 1,080,351
$ 1,198,737
$ (550,945) $ (650,198) $ (269,625)
$
796,533
$
380,747
$ (848,102) $ (374,885) $
163,090
$
$
$
$
3.75
—
3.75
3.71
—
3.71
$
$
$
$
1.29
0.37
1.66
1.28
0.37
1.65
$
$
$
$
(2.40) $
(1.30)
(3.70) $
(2.40) $
(1.30)
(3.70) $
(2.84) $
1.20
(1.64) $
(2.84) $
1.20
(1.64) $
(1.17)
1.88
0.71
(1.17)
1.87
0.70
Assets from Continuing Operations
Assets from Discontinued Operations
Total Assets
$ 8,592,170
—
$ 8,592,170
$ 6,931,913
—
$ 6,931,913
$ 6,682,770
2,496,921
$ 9,179,691
$ 7,302,119
3,627,783
$10,929,902
$ 7,968,069
3,686,576
$11,654,645
Long-Term Debt from Continuing Operations
(including current portion)
$ 2,398,501
$ 2,214,484
$ 2,456,354
$ 2,460,633
$ 3,129,433
Long-Term Debt from Discontinued Operations
(including current portion)
Total Long-Term Debt (including current portion)
Cash Dividends Declared Per Share of Common
Stock
See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
for a discussion of an adjustment to operating income for all periods and other matters that affect the comparability of the selected
financial data as well as uncertainties that might affect the Company’s future financial condition.
294,222
$ 2,754,855
120,128
$ 3,249,561
—
$ 2,214,484
—
$ 2,398,501
317,715
$ 2,774,069
— $
— $
0.250
0.010
0.145
$
$
$
OTHER OPERATING DATA
(unaudited)
Gas:
Net sales volumes produced (in Bcfe)
Average sales price ($ per Mcfe) (A)
Average cost ($ per Mcfe)
Proved reserves (in Bcfe) (B)
2018
Years Ended December 31,
2015
2016
2017
2014
$
$
507.1
2.97
1.98
7,881
$
$
407.2
2.66
2.23
7,582
$
$
394.4
2.63
2.32
6,252
$
$
328.7
2.81
2.62
5,643
$
$
235.7
4.37
3.13
6,828
____________
(A) Represents average net sales price including the effect of derivative transactions.
(B) Represents proved developed and undeveloped gas reserves at period end.
37
ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
General
2018 Highlights
• Record total gas production of 507.1 Bcfe in 2018, 24.5% higher than 2017
Included in CNX's 2018 production is approximately 27 Bcfe of production related to assets that were
sold in 2018.
• Record Marcellus Shale production of 288.2 Bcfe in 2018, 20.4% higher than 2017.
•
Increased proved reserves to 7.9 Tcfe, 4% higher than 2017.
Increase even after a reduction of approximately 825 Bcfe of reserves related to assets that were sold in
2018.
• 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 incentive
distribution rights in CNXM, the entity that constructs and operates the gathering system for most of our Marcellus
shale production.
• CNX sold substantially all of its shallow oil and gas assets and certain Coalbed Methane (CBM) assets in
Pennsylvania and West Virginia during the second quarter of 2018.
• During the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets
in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties, which included
approximately 26,000 net undeveloped acres.
• Gas production costs continue to decline - for the year ended December 31, 2018, total gas production costs were
$1.98 per Mcfe, which includes $0.90 per Mcfe of depreciation, depletion and amortization, a 11.2% decline from
the prior year.
• Repurchased $384 million of common stock on the open market.
• Repurchased $411 million of 5.875% notes due in 2022.
• Called the remaining $500 million balance of 8% senior notes due April 2023.
2019 Outlook:
• Our 2019 annual gas production is expected to be at a minimum base of approximately 495-515 Bcfe.
• Our 2019 E&P capital investment is expected to be approximately $1,000-$1,080 million.
38
Results of Operations: Year Ended December 31, 2018 Compared with the Year Ended December 31, 2017
Net Income Attributable to CNX Resources Shareholders
CNX reported net income attributable to CNX Resources shareholders of $797 million, or earnings per diluted share of
$3.71, for the year ended December 31, 2018, compared to net income of $381 million, or earnings per diluted share of $1.65, for
the year ended December 31, 2017.
(Dollars in thousands)
Income from Continuing Operations
Income from Discontinued Operations, Net
Net Income
Less: Net Income Attributable to Noncontrolling Interest
Net Income Attributable to CNX Resources Shareholders
For the Years Ended December 31,
2018
883,111
—
883,111
86,578
796,533
$
$
$
2017
295,039
85,708
380,747
—
380,747
Variance
$
$
$
588,072
(85,708)
502,364
86,578
415,786
$
$
$
CNX consists of two principal business divisions: Exploration and Production (E&P) and Midstream.
The principal activity of the E&P Division is to produce pipeline quality natural gas for sale primarily to gas wholesalers.
The E&P division's reportable segments are Marcellus Shale, Utica Shale, CBM, and Other Gas.
CNX's E&P Division had earnings from continuing operations before income tax of $245 million for the year ended
December 31, 2018, compared to a loss from continuing operations before income tax of $63 million for the year ended
December 31, 2017. Included in 2018 earnings was an unrealized gain on commodity derivative instruments of $40 million.
Included in the 2017 loss was an unrealized gain on commodity derivative instruments of $248 million and $138 million of expense
relating to the impairment in carrying value of Knox Energy LLC and Coalfield Pipeline Company (collectively, "Knox Energy").
See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form
10-K for additional information.
CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas
gathering and other midstream energy assets, through CNX Gathering and CNXM, which provide natural gas gathering services
for the Company's produced gas, as well as for other independent third-parties in the Marcellus Shale and Utica Shale in Pennsylvania
and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been
contributed to CNX Gathering and CNXM.
CNX's Midstream Division, which is the result of CNX's acquisition of NBL Midstream, LLC's interest in CNX Gathering
LLC (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this
Form 10-K for additional information) on January 3, 2018 (the Midstream Acquisition), had earnings from continuing operations
before income tax of $134 million for the period from January 3, 2018 through December 31, 2018. As a result of the Midstream
Acquisition, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership. Prior
to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment and as such a
period to period analysis is not meaningful. The resulting gain on remeasurement to fair value of the previously held equity interest
in CNX Gathering and CNXM of $624 million has been included in Gain on Previously Held Equity Interest in the Consolidated
Statements of Income and is part of CNX's unallocated expenses.
39
E&P Division Summary
Sales volumes, average sales price (including the effects of derivatives instruments), and average costs for the E&P Division
were as follows:
Sales Volume (Bcfe)
For the Years Ended December 31,
2018
507.1
2017
Variance
Percent
Change
407.2
99.9
24.5 %
Average Sales Price (per Mcfe)
Lease Operating Expense (per Mcfe)
Production, Ad Valorem, and Other Fees (per Mcfe)
Transportation, Gathering and Compression (per Mcfe)
Depreciation, Depletion and Amortization (DD&A) (per Mcfe)
Average Costs (per Mcfe)
Average Margin (per Mcfe)
$
$
$
2.97
0.19
0.06
0.84
0.89
1.98
0.99
$
$
$
2.66
0.22
0.07
0.94
1.00
2.23
0.43
$
$
$
0.31
(0.03)
(0.01)
(0.10)
(0.11)
(0.25)
0.56
11.7 %
(13.6)%
(14.3)%
(10.6)%
(11.0)%
(11.2)%
130.2 %
Natural gas, NGLs, and oil revenue was $1,578 million for the year ended December 31, 2018, compared to $1,125 million
for the year ended December 31, 2017. The increase was primarily due to the 24.5% increase in total sales volumes and 11.7%
increase in average sales price.
The 24.5% increase in total sales volumes was primarily due to additional natural gas wells that were turned-in-line in the
latter half of the 2017 period as well as throughout the 2018 period. These wells were primarily Marcellus and Utica wells. The
production for 2018 also 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 and incorporated herein.
The increase in average sales price was primarily the result of a $0.38 per Mcf increase in general natural gas market prices
in the Appalachian basin during the current period, partially offset by a $0.03 per Mcfe decrease in the uplift from NGLs and
condensate sales volumes when excluding the impact of hedging and the $0.04 increase in the realized loss on commodity derivative
instruments related to the Company's hedging program.
Changes in the average costs per Mcfe were primarily related to the following items:
• Lease operating expense decreased on a per unit basis due to the overall increase in sales volumes, primarily Utica, in
the 2018. There were also significant decreases in routine well operating costs, repairs and maintenance expenses and
employee costs, partially due to the sale of substantially all our shallow oil and gas properties in the first quarter. See
Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this
Form 10-K for additional information. In 2018, the company also deployed more in-house resources that maintained
overall lease operating costs and increased operational efficiencies while significantly increasing production. The
decreases were partially offset by increased water disposal costs, primarily in the first quarter of 2018, resulting from
increased production volumes and gaps in the completions schedule for new wells.
• Transportation, gathering, and compression expense decreased on a per-unit basis primarily due to the 24.5% increase
in sales volumes, and the shift towards dry Utica Shale production which has lower gathering costs and no processing
costs. In the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets in
the wet gas Utica Shale areas (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).
• Depreciation, depletion, and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus Shale
and Utica Shale rates as a result of an increase in the Company's associated reserves and an overall change in production
mix.
40
The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the
Company’s natural gas production and sales portfolio.
in thousands (unless noted)
LIQUIDS
NGLs:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Oil:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Condensate:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
GAS
Sales Volume (MMcf)
Sales Price ($/Mcf)
Gross Revenue
Hedging Impact ($/Mcf)
Loss on Commodity Derivative Instruments - Cash Settlement
Selling, General and Administrative (SG&A) - Total Company
For the Years Ended December 31,
2018
2017
Variance
Percent
Change
36,489
6,081
27.30
165,883
307
51
59.34
3,036
2,082
347
50.58
17,559
$
$
$
$
$
$
468,226
$
2.97
$ 1,391,459
$
$
$
$
$
$
$
$
38,736
6,456
24.18
156,132
421
70
45.36
3,179
3,116
519
39.54
20,531
364,893
2.59
945,382
$
$
$
$
$
$
$
$
(2,247)
(375)
3.12
9,751
(114)
(19)
13.98
(143)
(1,034)
(172)
11.04
(2,972)
103,333
0.38
446,077
$
$
(0.15) $
(69,720) $
(0.11) $
(41,174) $
(0.04)
(28,546)
(5.8)%
(5.8)%
12.9 %
6.2 %
(27.1)%
(27.1)%
30.8 %
(4.5)%
(33.2)%
(33.1)%
27.9 %
(14.5)%
28.3 %
14.7 %
47.2 %
(36.4)%
(69.3)%
SG&A costs include costs such as overhead, including employee wages and benefit costs, short-term incentive compensation,
costs of maintaining our headquarters, audit and other professional fees, and legal compliance expenses. SG&A costs also include
noncash equity-based compensation expense.
SG&A costs were $135 million for the year ended December 31, 2018, compared to $93 million for the year ended
December 31, 2017. SG&A costs increased primarily due to the Midstream Acquisition in January 2018, which now requires us
to consolidate CNX Gathering and CNXM expenses as well as an increase in short-term incentive compensation expense. See
Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 1 of this Form 10-
K for additional information on the Midstream Acquisition. Prior to the Midstream Acquisition, CNX accounted for its interests
in CNX Gathering and CNXM as an equity-method investment.
Unallocated Expense
Certain costs and expenses, such as other (income) expense, gain on sale of assets related to non-core assets, gain on previously
held equity interest, loss on debt extinguishment, impairment of other intangible assets and income taxes are unallocated expenses
and therefore are excluded from the per unit costs above as well as segment reporting. Below is a summary of these costs and
expenses:
41
Other (Income) Expense
(in millions)
Other Income
Right of Way Sales
Royalty Income
Interest Income
Other
Total Other Income
Other Expense
Bank Fees
Professional Services
Other Land Rental Expense
Other Corporate Expense
Total Other Expense
Total Other (Income) Expense
Gain on Sale of Assets
For the Years Ended December 31,
2018
2017
Variance
$
$
$
$
$
14
15
—
8
37
$
$
$
2
10
9
6
27
$
11
$
13
$
7
4
—
22
$
(15) $
6
6
6
31
4
$
$
Percent
Change
600.0 %
50.0 %
(100.0)%
33.3 %
37.0 %
(15.4)%
16.7 %
(33.3)%
(100.0)%
(29.0)%
12
5
(9)
2
10
(2)
1
(2)
(6)
(9)
(19)
(475.0)%
CNX recognized a gain on sale of assets of $157 million in the year ended December 31, 2018 compared to a gain of $188
million in the year ended December 31, 2017. During the year ended December 31, 2018, CNX closed on the sale of substantially
all of its Ohio Utica Joint Venture Assets in the wet gas Utica Shale areas of Ohio and substantially all of its shallow oil and gas
assets and certain CBM assets in Pennsylvania and West Virginia. The net gain on the sale of these assets was $136 million and
is included in the Gain on Sale of Assets line on the Consolidated Statements of Income. During the year ended December 31,
2017, CNX closed on the sale of approximately 22,000 acres of surface land in Colorado, the sale of approximately 7,500 net
undeveloped acres of the Marcellus Shale in Pennsylvania, the sale of approximately 11,100 net undeveloped acres of the Marcellus
and Utica Shale in Pennsylvania, and the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in
Ohio. The net gain on the sale of these assets was $165 million and is included in Gain on Sale of Assets in the Consolidated
Statements of Income. The remaining decrease in the period-to-period comparison is due to various items that occurred throughout
both periods, none of which were individually material. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited
Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Gain on Previously Held Equity Interest
CNX recognized a gain on previously held equity interest of $624 million in the year ended December 31, 2018 due to the
Midstream Acquisition in January 2018. No such transactions occurred in the year ended December 31, 2017. See Note 6 -
Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for
additional information.
Loss on Debt Extinguishment
A loss on debt extinguishment of $54 million was recognized in the year ended December 31, 2018 compared to a loss on
debt extinguishment of $2 million in the year ended December 31, 2017. During the year ended December 31, 2018, CNX purchased
a portion of its 5.875% senior notes due in April 2022 at an average price equal to103.5% of the principal amount and redeemed
the 8.00% senior notes due in April 2023 at a call price equal to 106.0% of the principal amount. In the year ended December 31,
2017, CNX purchased a portion of its 5.875% senior notes due in April 2022 at an average price equal to 99.5% of the principal
amount, redeemed the 8.25% senior notes due in April 2020 at a call price equal to 101.375% of the principal amount, and redeemed
the 6.375% senior notes due in March 2021 at a call price equal to 102.125% of the principal amount. See Note 14 - Long Term
Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
42
Impairment of Other Intangible Assets
Intangible assets are tested for impairment whenever events or circumstances indicate that the carrying amount of an asset
may not be recoverable. An impairment loss would be recognized when the carrying amount of the asset exceeds the estimated
undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. The impairment loss to
be recorded would be the excess of the asset's carrying value over its fair value.
In connection with the Asset Exchange Agreement (AEA) with HG Energy transactions (See Note 6 - Acquisition and
Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information)
that occurred during the year ended December 31, 2018, CNX determined that the carrying value of the other intangible asset -
customer relationship exceeded its fair value, and an impairment of $19 million was included in Impairment of Other Intangible
Assets in the Consolidated Statement of Income. No such transactions occurred in the prior period.
Income Taxes
The effective income tax rate for continuing operations was 19.6% for the year ended December 31, 2018, compared to
(148.9)% for the year ended December 31, 2017. During the year ended December 31, 2018, CNX obtained a controlling interest
in CNX Gathering LLC and, through CNX Gathering's ownership of the general partner, control over the CNXM. All of CNXM’s
income is included in the Company's pre-tax income. However, the Company is not required to record income tax expense with
respect to the portions of CNXM’s income allocated to the noncontrolling public limited partners of CNXM, which reduces the
Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the Company's effective
tax rate in periods when the Company has consolidated pre-tax loss. The effective tax rate for the year ended December 31, 2018
was lower than the U.S. federal statutory rate primarily due to the non-controlling interest in CNXM, the effect of the filing of a
Federal net operating loss ("NOL") carryback for 2017 and 2016 resulting in a financial statement benefit of $23 million through
the realization of the Federal NOLs at a 35% tax rate as a carryback versus the current 21% tax rate as a carryforward generating
cash tax refunds to be received in 2019, the reversal of the alternative minimum tax ("AMT") credit sequestration valuation
allowance, and the release of certain state valuation allowances as a result of a corporate reorganization during the year.
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the "Act") which, among other things, lowered
the U.S. Federal income tax rate from 35% to 21%, repealed the corporate AMT, and provided for a refund of previously accrued
AMT credits. The Company reclassified $102 million from Deferred Income Taxes to Recoverable Income Taxes on the
Consolidated Balance Sheets in anticipation of a refund of 50% of the AMT credits expected to be received in 2019. The valuation
allowance associated with the AMT credits of $12 million was released as the Internal Revenue Service ("IRS") announced that
the AMT credits are no longer subject to government sequestration.
The Company recorded a net tax benefit to reflect the impact of the Act as of December 31, 2017, as it is required to reflect
the change in the period in which the law is enacted. Largely, the benefits recorded in the prior period related to tax reform are in
recognition of the revaluation of deferred tax assets and liabilities, a benefit of $115 million, and the benefit for reversal of valuation
allowance previously recorded against AMT credits which are now refundable, a benefit of $154 million.
See Note 8 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for
additional information.
Total Company Earnings Before Income Tax
Income Tax Expense (Benefit)
Effective Income Tax Rate
For the Years Ended December 31,
2018
2017
Variance
$
$
$
$
1,099
216
19.6%
119
(176)
(148.9)%
$
$
980
392
168.5%
Percent
Change
823.5 %
(222.7)%
43
TOTAL E&P DIVISION ANALYSIS for the year ended December 31, 2018 compared to the year ended December 31, 2017:
The E&P division had earnings from continuing operations before income tax of $245 million for the year ended December 31,
2018 compared to a loss from continuing operations before income tax of $63 million for the year ended December 31, 2017.
Variances by individual operating segment are discussed below.
For the Year Ended
December 31, 2018
Difference to Year Ended
December 31, 2017
(in millions)
Marcellus
Utica
CBM
Other
Gas
Total
Marcellus
Utica
CBM
$
903
$
446
$
213
$
16
$ 1,578
$
257
$
229
$
Natural Gas, NGLs and Oil
Revenue
(Loss) Gain on Commodity
Derivative Instruments
Purchased Gas Revenue
Other Operating Income
Total Revenue and Other
Operating Income
Lease Operating Expense
Production, Ad Valorem,
and Other Fees
Transportation, Gathering
and Compression
Depreciation, Depletion
and Amortization
Impairment of Exploration
and Production Properties
Exploration and
Production Related Other
Costs
Purchased Gas Costs
Other Operating Expense
Selling, General, and
Administrative Costs
Total Operating Costs and
Expenses
Interest Expense
Total E&P Division Costs
Earnings (Loss) from
Continuing Operations Before
Income Tax
39
66
27
(30)
66
27
(10)
(21)
—
—
(40)
(20)
—
—
863
41
18
320
230
—
—
—
—
—
609
—
609
—
—
426
30
7
52
143
—
—
—
—
—
232
—
232
(9)
—
—
204
22
7
48
77
—
—
—
—
—
154
—
154
148
1,641
247
2
1
4
11
—
12
65
72
112
279
122
401
95
33
424
461
—
12
65
72
112
1,274
122
1,396
9
3
64
8
—
—
—
—
—
84
—
84
12
(42)
186
6
4
41
49
Other
Gas
Total
$
(37) $
453
(207)
(237)
4
1
—
—
5
(3)
—
12
(42)
(274)
(11)
(1)
(16)
(14)
(6)
(12)
—
(138)
(138)
—
—
—
—
(25)
—
(25)
(36)
12
(40)
(36)
12
(40)
19
19
(221)
(39)
(260)
(83)
(39)
(122)
—
—
208
11
2
7
59
—
—
—
—
—
79
—
79
$
254
$
194
$
50
$ (253) $
245
$
163
$
129
$
30
$
(14) $
308
44
MARCELLUS SEGMENT
The Marcellus segment had earnings from continuing operations before income tax of $254 million for the year ended
December 31, 2018 compared to earnings from continuing operations before income tax of $91 million for the year ended
December 31, 2017.
For the Years Ended December 31,
Variance
45.4
2018
255.1
31.4
1.7
288.2
2017
209.7
27.6
2.1
239.4
Marcellus Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Marcellus Sales Volumes (Bcfe)*
Average Sales Price - Gas (per Mcf)
Loss on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
Average Sales Price - NGLs (per Mcfe)*
Average Sales Price - Condensate (per Mcfe)*
Total Average Marcellus Sales Price (per Mcfe)
Average Marcellus Lease Operating Expenses (per Mcfe)
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)
Average Marcellus Transportation, Gathering and Compression Costs (per
Mcfe)
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Marcellus Costs (per Mcfe)
Average Margin for Marcellus (per Mcfe)
$
$
$
$
$
$
$
$
2.93
(0.16) $
$
4.55
$
2.50
(0.14) $
$
3.96
8.32
2.99
0.14
0.07
1.11
0.79
2.11
0.88
$
$
$
$
6.44
2.57
0.13
0.07
1.07
0.92
2.19
0.38
$
$
$
$
Percent
Change
21.6 %
13.8 %
(19.0)%
20.4 %
17.2 %
(14.3)%
14.9 %
29.2 %
16.3 %
7.7 %
— %
3.7 %
(14.1)%
(3.7)%
131.6 %
3.8
(0.4)
48.8
0.43
(0.02)
0.59
1.88
0.42
0.01
—
0.04
(0.13)
(0.08)
0.50
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Marcellus segment had natural gas, NGLs and oil revenue of $903 million for the year ended December 31, 2018
compared to $646 million for the year ended December 31, 2017. The $257 million increase was primarily due to the 20.4%
increase in total Marcellus sales volumes, including liquids, as well as the 16.3% increase in the total average Marcellus sales
price in the period-to-period comparison. The increase in sales volumes was primarily due to additional wells being turned-in-
line in the latter half of 2017 and throughout 2018.
The increase in the total average Marcellus sales price was primarily the result of the $0.43 per Mcf increase in average gas
sales price and a $0.01 per Mcfe increase in the uplift from NGLs and condensate sales volume when excluding the impact of
hedging, partially offset by the $0.02 per Mcfe increase in the loss on commodity derivative instruments resulting from the
Company's hedging program. The notional amounts associated with these financial hedges represented approximately 206.7 Bcf
of the Company's produced Marcellus gas sales volumes for the year ended December 31, 2018 at an average loss of $0.20 per
Mcf. For the year ended December 31, 2017, these financial hedges represented approximately 177.6 Bcf at an average loss of
$0.17 per Mcf.
Total operating costs and expenses for the Marcellus segment were $609 million for the year ended December 31, 2018
compared to $525 million for the year ended December 31, 2017. The increase in total dollars and decrease in unit costs for the
Marcellus segment were due primarily to the following items:
• Marcellus lease operating expense was $41 million for the year ended December 31, 2018 compared to $32 million for
the year ended December 31, 2017. The increase in total dollars was primarily due to an increase in water disposal costs in the
current period due to increased production volumes along with proportionally more water being sent to disposal in the first quarter
of 2018 instead of being reused in completions. The increase in unit costs was driven by the increase in total dollars, partially
offset by the 20.4% increase in total Marcellus sales volumes.
45
• Marcellus production, ad valorem, and other fees were $18 million for the year ended December 31, 2018 compared to
$15 million for the year ended December 31, 2017. The increase in total dollars was primarily due to the increase in overall
Marcellus production as well as a change in production mix by state as new wells are turned in line.
• Marcellus transportation, gathering and compression costs were $320 million for the year ended December 31, 2018
compared to $256 million for the year ended December 31, 2017. The $64 million increase in total dollars was primarily related
to an increase in gathering, processing and utilized firm transportation costs due to increased volumes and increased processing
costs due to a change in production mix which includes a greater proportion of higher cost wet gas. The increase in unit costs was
due to the increased total dollars described above, partially offset by the 20.4% increase in Marcellus sales volumes.
• Depreciation, depletion and amortization costs attributable to the Marcellus segment were $230 million for the year ended
December 31, 2018 compared to $222 million for the year ended December 31, 2017. These amounts included depletion on a unit
of production basis of $0.79 per Mcf and $0.91 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
UTICA SEGMENT
The Utica segment had earnings from continuing operations before income tax of $194 million for the year ended
December 31, 2018 compared to earnings from continuing operations before income tax of $65 million for the year ended
December 31, 2017.
Utica Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Oil Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Utica Sales Volumes (Bcfe)*
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per
Mcf)
Average Sales Price - NGLs (per Mcfe)*
Average Sales Price - Oil (per Mcfe)*
Average Sales Price - Condensate (per Mcfe)*
Total Average Utica Sales Price (per Mcfe)
Average Utica Lease Operating Expenses (per Mcfe)
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Utica Costs (per Mcfe)
Average Margin for Utica (per Mcfe)
For the Years Ended December 31,
2018
148.1
5.1
0.1
0.4
153.7
2017
70.7
11.1
0.2
1.0
83.0
Variance
77.4
(6.0)
(0.1)
(0.6)
70.7
Percent
Change
109.5 %
(54.1)%
(50.0)%
(60.0)%
85.2 %
$
$
$
$
$
$
$
$
2.82
$
2.29
$ 0.53
23.1 %
(0.13) $
$
4.54
9.46
8.96
2.77
0.19
0.05
0.34
0.93
1.51
1.26
$
$
$
$
$
0.02
4.20
7.31
6.88
2.63
0.23
0.06
0.54
1.02
1.85
0.78
$ (0.15)
$ 0.34
$ 2.15
$ 2.08
$ 0.14
(0.04)
(0.01)
(0.20)
(0.09)
$ (0.34)
$ 0.48
(750.0)%
8.1 %
29.4 %
30.2 %
5.3 %
(17.4)%
(16.7)%
(37.0)%
(8.8)%
(18.4)%
61.5 %
*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Utica segment had natural gas, NGLs and oil revenue of $446 million for the year ended December 31, 2018 compared
to $217 million for the year ended December 31, 2017. The $229 million increase was due to the 85.2% increase in total Utica
sales volumes as well as the 5.3% increase in total average Utica sales price. The 70.7 Bcfe increase in total Utica sales volumes
was primarily due to additional wells turned-in-line beginning in the third quarter of 2017 and throughout the 2018 period, primarily
in Monroe County, Ohio. The increase was partially offset by the sale of substantially all of CNX's Ohio Utica Joint Venture Assets,
46
during the third quarter of 2018, in the wet gas Utica Shale areas (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).
The increase in the total average Utica sales price was primarily due to the $0.53 increase in average gas sales price, offset,
in part, by a $0.24 decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging. Part
of the decrease in the uplift from NGLs and condensate sales volumes was due to the sale of the CNX's Ohio Utica Joint Venture
Assets in the wet gas Utica Shale areas, as discussed above. There was also a $0.15 per Mcf decrease in the (loss) gain on commodity
derivative instruments in the current period. The notional amounts associated with these financial hedges represented approximately
101.6 Bcf of the Company's produced Utica gas sales volumes for the year ended December 31, 2018 at an average loss of $0.20
per Mcf. For the year ended December 31, 2017, these financial hedges represented approximately 39.8 Bcf at an average gain
of $0.04 per Mcf.
Total operating costs and expenses for the Utica segment were $232 million for the year ended December 31, 2018 compared
to $153 million for the year ended December 31, 2017. The increase in total dollars and decrease in unit costs for the Utica segment
are due to the following items:
• Utica lease operating expense increased to $30 million for the year ended December 31, 2018, compared to $19 million
for the year ended December 31, 2017. The increase in total dollars was primarily due to higher well tending and water disposal
costs in the current period associated with the additional sales volumes. The decrease in unit costs was due to the 85.2% increase
in total Utica sales volumes.
• Utica production, ad valorem, and other fees were $7 million for the year ended December 31, 2018 compared to $5
million for the year ended December 31, 2017. The increase in total dollars was primarily due to the overall increase in Utica
production as well as a change in production mix by state as new wells are turned-in-line. The decrease in unit costs was due to
the increase in production volumes.
• Utica transportation, gathering and compression costs were $52 million for the year ended December 31, 2018 compared
to $45 million for the year ended December 31, 2017. The $7 million increase in total dollars was primarily related to the increased
production in the current period. The decrease in unit costs was due to the increase in total Utica sales volumes, predominantly
dry Utica which does not require processing. In the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio
Utica Joint Venture Assets in the wet gas Utica Shale areas (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).
• Depreciation, depletion and amortization costs attributable to the Utica segment were $143 million for the year ended
December 31, 2018 compared to $84 million for the year ended December 31, 2017. These amounts included depletion on a unit
of production basis of $0.93 per Mcf and $1.01 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
47
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings from continuing operations before income tax of $50 million for the year ended December 31,
2018 compared to earnings from continuing operations before income tax of $20 million for the year ended December 31, 2017.
CBM Gas Sales Volumes (Bcf)
Average Sales Price - Gas (per Mcf)
Loss on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
Total Average CBM Sales Price (per Mcf)
Average CBM Lease Operating Expenses (per Mcf)
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
Total Average CBM Costs (per Mcf)
Average Margin for CBM (per Mcf)
For the Years Ended December 31,
2018
2017
Variance
Percent
Change
60.3
65.4
(5.1)
(7.8)%
$
3.53
(0.15) $
$
3.19
(0.15) $
0.34
—
10.7 %
— %
3.39
0.37
0.12
0.80
1.28
2.57
0.82
$
$
$
3.05
0.39
0.11
0.98
1.26
2.74
0.31
$
$
$
0.34
(0.02)
0.01
(0.18)
0.02
(0.17)
0.51
11.1 %
(5.1)%
9.1 %
(18.4)%
1.6 %
(6.2)%
164.5 %
$
$
$
$
$
The CBM segment had natural gas sales of $213 million for the year ended December 31, 2018 compared to $209 million
for the year ended December 31, 2017. The $4 million increase was due to a 11.1% increase in the total average CBM sales price,
offset, in part, by the 7.8% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal
well declines, less drilling activity and the sale of certain CBM assets that were sold along with the majority of CNX's shallow
oil and gas assets (See Note 6 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial Statements in
Item 8 of this Form 10-K for additional information).
The total average CBM sales price increased due to the $0.34 per Mcf increase in the average gas sales price. The loss on
commodity derivative instruments remained consistent year over year. The notional amounts associated with these financial hedges
represented approximately 44.8 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2018 at an
average loss of $0.20 per Mcf. For the year ended December 31, 2017, these financial hedges represented approximately 56.3 Bcf
at an average loss of $0.17 per Mcf.
Total operating costs and expenses for the CBM segment were $154 million for the year ended December 31, 2018 compared
to $179 million for the year ended December 31, 2017. The decrease in total dollars and decrease in unit costs were due to the
following items:
• CBM lease operating expense was $22 million for the year ended December 31, 2018 compared to $25 million for the
year ended December 31, 2017. The decrease in total dollars was primarily due to reductions in contract services. The decrease
in unit costs was due to the decrease in total dollars as well as the decrease in CBM gas sales volumes.
• CBM production, ad valorem, and other fees remained consistent at $7 million for each of the years ended December 31,
2018 and December 31, 2017. Unit costs were negatively impacted by the decrease in CBM gas sales volumes.
• CBM transportation, gathering and compression costs were $48 million for the year ended December 31, 2018 compared
to $64 million for the year ended December 31, 2017. The $16 million decrease was primarily related to a decrease in contractor
services. The decrease was also due to a decrease in utilized firm transportation expense due to a new compressor station that
began operating in the third quarter of 2017. This station allows CNX to flow more production through the Jewel Ridge Pipeline,
which is treated as a capital lease. Unit costs were also positively impacted by the decrease in total dollars which was offset, in
part, by the decrease in CBM gas sales volumes.
• Depreciation, depletion and amortization costs attributable to the CBM segment were $77 million for the year ended
December 31, 2018 compared to $83 million for the year ended December 31, 2017. These amounts included depletion on a unit
of production basis of $0.70 per Mcf and $0.78 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
48
7.1 %
30.2 %
17.9 %
(33.3)%
(66.7)%
(3.3)%
41.9 %
4.4 %
437.5 %
OTHER GAS SEGMENT
The Other Gas segment had a loss from continuing operations before income tax of $253 million for the year ended
December 31, 2018 compared to a loss from continuing operations before income tax of $239 million for the year ended
December 31, 2017.
Other Gas Sales Volumes (Bcf)
Oil Sales Volumes (Bcfe)*
Total Other Sales Volumes (Bcfe)*
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per
Mcf)
Average Sales Price - Oil (per Mcfe)*
For the Years Ended December 31,
2018
2017
4.7
0.2
4.9
19.2
0.2
19.4
Variance
(14.5)
—
(14.5)
Percent
Change
(75.5)%
— %
(74.7)%
$
2.91
$
2.69
$ 0.22
8.2 %
$ (0.13) $ (0.14) $ 0.01
$ 2.34
$ 10.09
7.75
$
Total Average Other Sales Price (per Mcfe)
Average Other Lease Operating Expenses (per Mcfe)
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)
Average Other Transportation, Gathering and Compression Costs (per Mcfe)
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Other Costs (per Mcfe)
Average Margin for Other (per Mcfe)
$
$
$
3.09
0.42
0.04
0.87
1.49
2.82
0.27
$
2.62
0.63
0.12
0.90
1.05
$ 0.47
(0.21)
(0.08)
(0.03)
0.44
2.70
$
$ 0.12
$ (0.08) $ 0.35
*Oil is converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of oil and natural gas prices.
The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes
purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other
costs, impairment of exploration and production properties and other operational activity not assigned to a specific segment.
Other Gas sales volumes are primarily related to CNX's remaining shallow oil and gas production. CNX sold substantially
all of these assets on March 30, 2018 (See Note 6 - Acquisitions and Dispositions of the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information). Natural gas, NGLs and oil revenue related to the Other Gas
segment were $16 million for the year ended December 31, 2018 compared to $53 million for the year ended December 31, 2017.
The decrease in natural gas and oil revenue resulted from the 74.7% decrease in total Other Gas sales volumes relating to the asset
sale. Total exploration and production costs related to these other sales were $18 million for the year ended December 31, 2018
compared to $56 million for the year ended December 31, 2017.
The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $40 million as well as cash
settlements paid of $1 million for the year ended December 31, 2018. For the year ended December 31, 2017, the Company
recognized an unrealized gain on commodity derivative instruments of $248 million as well as cash settlements paid of $2 million.
The unrealized gain on commodity derivative instruments represents changes in the fair value of all the Company's existing
commodity derivative hedges on a mark-to-market basis.
Purchased Gas
Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to
fulfill contracts with certain customers. Purchased gas revenue was $66 million for the year ended December 31, 2018 compared
to $54 million for the year ended December 31, 2017. Purchased gas costs were $65 million for the year ended December 31,
2018 compared to $53 million for the year ended December 31, 2017. The period-to-period increase in purchased gas revenue
was primarily due to the increase in market prices, partially offset by the decrease in purchased gas sales volumes.
49
Purchased Gas Sales Volumes (in billion cubic feet)
Average Sales Price (per Mcf)
Average Cost (per Mcf)
Other Operating Income
For the Years Ended December 31,
2018
2017
Variance
20.5
3.23
3.17
$
$
22.0
2.44
2.39
$
$
(1.5)
0.79
0.78
$
$
Percent
Change
(6.8)%
32.4 %
32.6 %
Other operating income was $27 million for the year ended December 31, 2018 compared to $69 million for the year ended
December 31, 2017. The $42 million decrease was primarily due to the following items:
(in millions)
Equity in Earnings of Affiliates
Gathering Income
Water Income
Other
Total Other Operating Income
For the Years Ended December 31,
2018
2017
Variance
$
$
5
10
11
1
27
$
$
50
11
5
3
69
$
$
(45)
(1)
6
(2)
(42)
Percent
Change
(90.0)%
(9.1)%
120.0 %
(66.7)%
(60.9)%
• Equity in Earnings of Affiliates decreased $45 million primarily due to the consolidation of CNX Gathering and CNXM
in the current year. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information.
• Water Income increased $6 million due to increased sales of freshwater to third-parties for hydraulic fracturing.
Impairment of Exploration and Production Related Properties
Impairment of Exploration and Production Properties of $138 million for the year ended December 31, 2017 related to an
impairment in the carrying value of Knox Energy in the first quarter of 2017. See Note 1 - Significant Accounting Policies and
Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-
K for additional information. No such impairments occurred in the year ended December 31, 2018.
Exploration and Production Related Other Costs
Exploration and production related other costs were $12 million for the year ended December 31, 2018 compared to $48
million for the year ended December 31, 2017. The $36 million decrease in costs was primarily related to the following items:
(in millions)
Lease Expiration Costs
Land Rentals
Other
Total Exploration and Production Related Other Costs
For the Years Ended December 31,
2018
2017
Variance
$
$
5
4
3
12
$
$
40
4
4
48
$
$
(35)
—
(1)
(36)
Percent
Change
(87.5)%
— %
(25.0)%
(75.0)%
• Lease Expiration Costs relate to leases where the primary term expired or will expire within the next 12 months. The $35
million decrease in the year ended December 31, 2018, was primarily due to leases in both Monroe and Noble County,
Ohio that were no longer in the Company's future drilling plans, so they were not renewed in the 2017 period.
50
Other Operating Expenses
Other operating expense was $72 million for the year ended December 31, 2018 compared to $112 million for the year ended
December 31, 2017. The $40 million decrease in the period-to-period comparison was made up of the following items:
Idle Rig Expense
Unutilized Firm Transportation and Processing Fees
Severance Expense
Insurance Expense
Litigation Settlements
Other
Total Other Operating Expense
For the Years Ended December 31,
2018
2017
Variance
5
42
1
3
4
17
72
$
$
41
50
1
3
3
14
112
$
$
(36)
(8)
—
—
1
3
(40)
$
$
Percent
Change
(87.8)%
(16.0)%
— %
— %
33.3 %
21.4 %
(35.7)%
•
Idle Rig Expense relates to the temporary idling of some of the Company's natural gas rigs. The total idle rig expense
incurred by the Company decreased $36 million in the period-to-period comparison due to contracts that expired in the
current period. Additionally, the total idle rig expense decreased in the period-to-period comparison due to a settlement
that was reached with a former joint-venture partner that resulted in CNX recording additional expense in the year ended
December 31, 2017.
• Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas
production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The
decrease in the period-to-period comparison was primarily due to the increase in the utilization of capacity. The Company
attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when
possible and when beneficial. The revenue received when this capacity is released (sold) is included in Gathering Income
in other operating income above.
Selling, General and Administrative
SG&A costs represent direct charges for the management and operation of CNX's E&P division. SG&A costs were $112
million for the year ended December 31, 2018 compared to $93 million for the year ended December 31, 2017. Refer to the
discussion of total company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders" of
this Form 10-K for a detailed cost explanation.
Interest Expense
Interest expense of $122 million was recognized in the year ended December 31, 2018 compared to $161 million in the year
ended December 31, 2017. The $39 million decrease was primarily due to a reduction in higher cost long-term debt, resulting
from the $411 million purchase of the outstanding 5.875% senior notes due in April 2022 and the $500 million purchase of the
outstanding 8% senior notes due in April 2023 in the year ended December 31, 2018, offset, in part, by additional borrowings on
the CNX credit facility. In the year ended December 31, 2017, CNX purchased $144 million of its outstanding 5.875% senior
notes due in April 2022. See Note 14 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8
of this Form 10-K for additional information.
51
TOTAL MIDSTREAM DIVISION ANALYSIS for the period January 3, 2018 through December 31, 2018:
CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas
gathering and other midstream energy assets of CNX Gathering and CNXM, which provide natural gas gathering services for the
Company's produced gas, as well as for other independent third-parties in the Marcellus Shale and Utica Shale in Pennsylvania
and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been
contributed to CNX Gathering and CNXM.
On January 3, 2018, CNX completed the Midstream Acquisition (See Note 6 - Acquisitions and Dispositions in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). CNX Gathering holds
all of the interests in CNX Midstream GP, LLC, which holds the general partner interest and incentive distribution rights in CNXM.
As a result of this transaction, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited
partnership and thus the Company consolidates both CNX Gathering and CNXM commencing on January 3, 2018. Prior to the
acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment and as such a period-
to-period analysis is not meaningful.
(in millions)
Midstream Revenue - Related Party
Midstream Revenue - Third Party
Total Revenue
Transportation, Gathering and Compression
Depreciation, Depletion and Amortization
Selling, General, and Administrative Costs
Total Operating Costs and Expenses
Gain on Asset Sales
Interest Expense
Total Midstream Division Costs
Earnings from Continuing Operations Before Income Tax
Midstream Revenue
For the period January 3, 2018
through December 31, 2018
$
$
$
$
168
90
258
47
32
23
102
(2)
24
124
134
Midstream revenue consists of revenue related to volumes gathered on behalf of CNX and other third-party natural gas
producers. CNXM charges a higher fee for natural gas that is shipped on its wet system compared to gas shipped through its dry
system. CNXM revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon
delivery point and may change dynamically depending on commodity prices at time of shipment.
The table below summaries volumes gathered by gas type for the period January 3, 2018 through December 31, 2018.
Dry Gas (BBtu/d) (*)
Wet Gas (BBtu/d) (*)
Other (BBtu/d) (*)(**)
Total Gathered Volumes
TOTAL
740
661
73
1,474
(*) Classification as dry or wet is based upon the shipping destination of the related volumes. Because CNXM's customers have the option to ship a portion of
their natural gas to destinations associated with either our wet system or our dry system, due to any number of factors, volumes may be classified as “wet” in one
period and as “dry” in the comparative period.
(**) Includes condensate handling and third-party volumes under high-pressure short-haul agreements.
Transportation, Gathering and Compression
Transportation, Gathering and Compression costs were $47 million for the period January 3, 2018 through December 31,
2018 and are comprised of items directly related to the cost of gathering natural gas at the wellhead and transporting it to interstate
pipelines or other local sales points. These costs include items such as electrical compression, repairs and maintenance, supplies,
treating and contract services.
52
SG&A Expense
SG&A expense is comprised of direct charges for the management and operation of CNXM assets. Refer to the discussion
of total Company SG&A costs contained in the section "Net Income Attributable to CNX Resources Shareholders" of this Form
10-K for a detailed cost explanation.
Depreciation, Depletion and Amortization
Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from
25 years to 40 years.
Gain on Asset Sales
During the period January 3, 2018 through December 31, 2018, CNXM sold property and equipment to an unrelated third-
party for $6 million in cash proceeds, resulting in a gain of $2 million.
Interest Expense
Interest expense is comprised of interest on the outstanding balance under CNXM's senior notes due 2026 and its revolving
credit facility. Interest expense was $24 million for the period January 3, 2018 through December 31, 2018.
53
Results of Operations: Year Ended December 31, 2017 Compared with the Year Ended December 31, 2016
Net Income (Loss)
CNX reported net income of $381 million, or earnings per diluted share of $1.65, for the year ended December 31, 2017,
compared to a net loss of $848 million, or a loss per diluted share of $3.70, for the year ended December 31, 2016.
For the Years Ended December 31,
(Dollars in thousands)
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations, net
Net Income (Loss)
2017
295,039
85,708
380,747
$
$
2016
Variance
845,984
$ (550,945) $
(297,157)
382,865
$ (848,102) $ 1,228,849
CNX currently consists of two principal business divisions: Exploration and Production (E&P) and Midstream. CNX's
Midstream Division was the result of the Midstream Acquisition that occurred on January 3, 2018 (See Note 6 - Acquisitions and
Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).
Prior to the acquisition, CNX accounted for its interests in CNX Gathering and CNXM as an equity-method investment which is
how it appears in the 2017 and 2016 analysis.
The principal activity of CNX, prior to the Midstream Acquisition, was to produce pipeline quality natural gas for sale
primarily to gas wholesalers. The Company's reportable segments were Marcellus Shale, Utica Shale, Coalbed Methane, and Other
Gas.
CNX had a total company earnings from continuing operations before income tax of $119 million for the year ended
December 31, 2017, compared to a loss from continuing operations before income tax of $585 million for the year ended
December 31, 2016. Included in the 2017 earnings from continuing operations before income tax was an unrealized gain on
commodity derivative instruments of $248 million and a gain on sale of assets of $188 million, partially offset by $138 million
of expense relating to the impairment in carrying value of Knox Energy LLC and Coalfield Pipeline Company (collectively, "Knox
Energy"). See Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8
of this Form 10-K for additional information. Included in the 2016 net loss from continuing operations before income tax was an
unrealized loss on commodity derivative instruments of $386 million, partially offset by a gain on sale of assets of $14 million.
Natural gas, NGLs, and oil revenue was $1,125 million for the year ended December 31, 2017 compared to $793 million
for the year ended December 31, 2016. The increase was primarily due to the 3.2% increase in total sales volumes.
Sales volumes, average sales price (including the effects of derivative instruments), and average costs for active operations
in the period-to-period comparison were as follows:
Sales Volume (Bcfe)
Average Sales Price (per Mcfe)
Lease Operating Expense
Production, Ad Valorem, and Other Fees
Transportation, Gathering and Compression
Depreciation, Depletion and Amortization (DD&A)
Average Costs (per Mcfe)
Average Margin
For the Years Ended December 31,
2017
2016
407.2
394.4
Variance
12.8
$
$
$
2.66
0.22
0.07
0.94
1.00
2.23
0.43
$
$
$
2.63
0.24
0.08
0.95
1.05
2.32
0.31
$
$
$
0.03
(0.02)
(0.01)
(0.01)
(0.05)
(0.09)
0.12
Percent
Change
3.2 %
1.1 %
(8.3)%
(12.5)%
(1.1)%
(4.8)%
(3.9)%
38.7 %
The increase in average sales price was primarily the result of the $0.67 per Mcf increase in general natural gas market prices
in the Appalachian basin during the 2017 period and the $0.08 per Mcfe increase in the uplift from NGLs and condensate sales
volumes when excluding the impact of hedging, partially offset by the $0.81 per Mcf decrease in the realized (loss) gain on
commodity derivative instruments related to the Company's hedging program.
54
Changes in the average costs per Mcfe were primarily related to the following items:
• Depreciation, depletion, and amortization decreased on a per-unit basis primarily due to a reduction in Marcellus rates
as a result of an increase in the Company's Marcellus reserves. See Note 10 - Property, Plant, and Equipment in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details.
• Lease operating expense decreased on a per unit basis due to a decrease in well tending costs and salt water disposal
costs, as well as a decrease in both Company operated and joint venture operated repairs and maintenance costs.
The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the
Company’s natural gas production and sales portfolio.
in thousands (unless noted)
LIQUIDS
NGLs:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Oil:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
Condensate:
Sales Volume (MMcfe)
Sales Volume (Mbbls)
Gross Price ($/Bbl)
Gross Revenue
GAS
Sales Volume (MMcf)
Sales Price ($/Mcf)
Gross Revenue
For the Years Ended December 31,
2017
2016
Variance
Percent
Change
38,736
6,456
24.18
$
$ 156,132
$
$
40,260
6,710
14.52
97,580
$
$
(1,524)
(254)
9.66
58,552
421
70
410
68
45.36
3,179
$
$
36.90
2,521
$
$
11
2
8.46
658
(3.8)%
(3.8)%
66.5 %
60.0 %
2.7 %
2.9 %
22.9 %
26.1 %
3,116
519
39.54
20,531
$
$
4,964
828
27.48
22,748
$
$
(1,848)
(309)
12.06
(2,217)
(37.2)%
(37.3)%
43.9 %
(9.7)%
364,893
348,753
16,140
$
2.59
$
1.92
$
0.67
$ 945,382
$ 670,823
$ 274,559
4.6 %
34.9 %
40.9 %
$
$
$
$
Hedging Impact ($/Mcf)
$
(0.11) $
0.70
$
(0.81)
(115.7)%
(Loss) Gain on Commodity Derivative Instruments - Cash
Settlement
$ (41,174) $ 245,212
$ (286,386)
(116.8)%
Selling, General and Administrative
SG&A costs include costs such as overhead, including employee wages and benefit costs, short-term incentive compensation,
costs of maintaining our headquarters, audit and other professional fees, and legal compliance expenses. SG&A costs also includes
noncash equity-based compensation expense.
SG&A costs were $93 million for the year ended December 31, 2017, compared to $105 million for the year ended
December 31, 2016. SG&A costs decreased due to a decrease in employee wages and benefit costs in 2017 related to a reduction
in headcount as well as a decrease in equity-based compensation expense.
55
Unallocated Expense
Certain costs and expenses such as other expense, gain on sale of assets related to non-core assets, loss on debt extinguishment
and income taxes are unallocated expenses and therefore are excluded from the per unit costs above as well as segment reporting.
Below is a summary of these costs and expenses:
Other Expense
(in millions)
Other Income
Right of Way Sales
Royalty Income
Interest Income
Other
Total Other Income
Other Expense
Professional Services
Bank Fees
Other Land Rental Expense
Other Corporate Expense
Total Other Expense
Total Other Expense
Gain on Sale of Assets
For the Years Ended December 31,
2017
2016
Variance
$
$
$
$
$
$
2
10
9
6
27
$
6
13
6
6
31
4
$
$
$
15
10
—
4
29
7
13
5
9
34
5
$
$
$
$
$
Percent
Change
(86.7)%
— %
100.0 %
50.0 %
(6.9)%
(14.3)%
— %
20.0 %
(33.3)%
(8.8)%
(13)
—
9
2
(2)
(1)
—
1
(3)
(3)
(1)
(20.0)%
CNX recognized a gain on sale of assets of $188 million in the year ended December 31, 2017 compared to a gain of $14
million in the year ended December 31, 2016. The $174 million increase was primarily due to sale of approximately 22,000 acres
of surface land in Colorado, the sale of approximately 7,500 net undeveloped acres of the Marcellus Shale in Pennsylvania, the
sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale in Pennsylvania, and the sale of approximately
6,300 net undeveloped acres of the Utica-Point Pleasant Shale in Ohio in the year ended December 31, 2017. No individually
significant transactions occurred in the year ended December 31, 2016. See Note 6 - Acquisitions and Dispositions in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Loss on Debt Extinguishment
Loss on debt extinguishment of $2 million was recognized in the year ended December 31, 2017 due to the purchase of a
portion of the 5.875% senior notes due in April 2022 at an average price equal to 99.5% of the principal amount, the redemption
of the 8.25% senior notes due in April 2020 at a call price equal to 101.375% of the principal amount, and the redemption of the
6.375% senior notes due in March 2021 at a call price equal to 102.125% of the principal amount. See Note 14 - Long-Term Debt
in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Income Taxes
The effective income tax rate for continuing operations was (148.9)% for the year ended December 31, 2017, compared to
6.0 % for the year ended December 31, 2016. During the year ended December 31, 2016, CNX settled a Federal audit of the years
2010-2013 and received a favorable private letter ruling from the IRS related to bonus depreciation. Overall, the Company received
approximately $21 million in refunds during 2016. Some of the factors contributing to the refunds received during 2016 put
pressure on deferred tax assets related to alternative minimum tax credits. As management could not demonstrate sufficient positive
evidence to ensure realizability of these assets, the Company recorded a valuation allowance of $167 million at December 31,
2016 on alternative minimum tax credits as well as an additional $38 million valuation allowance was recorded at December 31,
2016 against state deferred tax assets, as well as federal charitable contributions and foreign tax credit carry-forwards.
56
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the "Act") which, among other things, lowered
the U.S. Federal tax rate from 35% to 21%, repealed the corporate alternative minimum tax, and provided for a refund of previously
accrued alternative minimum tax credits. The Company recorded a net tax benefit to reflect the impact of the Act as of December 31,
2017, as it is required to reflect the change in the period in which the law is enacted. Largely, the benefits recorded in the 2017
period related to tax reform are in recognition of the revaluation of deferred tax assets and liabilities, a benefit of $115 million,
and the benefit for reversal of valuation allowance previously recorded against alternative minimum tax credits which are now
refundable, a benefit of $154 million.
See Note 8 - Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for
additional information.
Total Company Earnings (Loss) Before Income Tax
Income Tax Benefit
Effective Income Tax Rate
For the Years Ended December 31,
2017
2016
$
$
119
(176)
(148.9)%
$
$
$
$
(585)
(34)
6.0%
Variance
704
(142)
(154.9)%
Percent
Change
(120.3)%
417.6 %
57
TOTAL E&P DIVISION ANALYSIS for the year ended December 31, 2017 compared to the year ended December 31, 2016:
The E&P division had a loss from continuing operations before income tax of $63 million for the year ended December 31,
2017 compared to a loss from continuing operations before income tax of $594 million for the year ended December 31, 2016.
Variances by individual operating segment are discussed below.
(in millions)
Marcellus
Utica
CBM
Other
Gas
Total
Marcellus
Utica
CBM
Other
Gas
Total
For the Year Ended
December 31, 2017
Difference to Year Ended
December 31, 2016
$
646
$
217
$
209
$
53
$ 1,125
$
231
$
54
$
34
$
13
$
332
Natural Gas, NGLs and Oil
Revenue
(Loss) Gain on Commodity
Derivative Instruments
Purchased Gas Revenue
Other Operating Income
Total Revenue and Other
Operating Income
Lease Operating Expense
Production, Ad Valorem,
and Other Fees
Transportation, Gathering
and Compression
Depreciation, Depletion
and Amortization
Impairment of Exploration
and Production Properties
Exploration and
Production Related Other
Costs
Purchased Gas Costs
Other Operating Expense
Selling, General and
Administrative Costs
Total Operating Costs and
Expenses
Interest Expense
Total E&P Division Costs
Earnings (Loss) from
Continuing Operations Before
Income Tax
$
$
(177)
(28)
(62)
(30)
—
—
616
32
15
256
222
—
—
—
—
—
1
—
—
218
19
5
45
84
—
—
—
—
—
(10)
—
—
199
25
7
64
83
—
—
—
—
—
525
—
153
—
179
—
525
$
153
$
179
$
246
54
69
422
13
2
18
23
138
48
53
112
93
500
161
661
207
54
69
1,455
89
29
383
412
138
48
53
112
93
1,357
161
$ 1,518
$
—
—
54
(2)
(2)
28
11
—
—
—
—
—
35
—
35
—
—
26
(3)
—
(6)
(2)
—
—
—
—
—
—
—
(28)
—
1
(8)
(3)
—
—
—
—
—
615
11
4
643
(2)
(1)
(5)
(14)
348
11
4
695
(7)
(2)
9
(8)
138
138
33
10
23
33
10
23
(11)
(11)
(11)
—
(10)
—
171
(21)
185
(21)
$
(11) $
(10) $
150
$
164
91
$
65
$
20
$ (239) $
(63) $
19
$
37
$
(18) $
493
$
531
58
MARCELLUS SEGMENT
The Marcellus segment had earnings from continuing operations before income tax of $91 million for the year ended
December 31, 2017 compared to earnings from continuing operations before income tax of $72 million for the year ended
December 31, 2016.
Marcellus Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Marcellus Sales Volumes (Bcfe)*
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas
(per Mcf)
Average Sales Price - NGLs (per Mcfe)*
Average Sales Price - Condensate (per Mcfe)*
Total Average Marcellus Sales Price (per Mcfe)
Average Marcellus Lease Operating Expenses (per Mcfe)
Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)
Average Marcellus Transportation, Gathering and Compression Costs (per
Mcfe)
Average Marcellus Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Marcellus Costs (per Mcfe)
Average Margin for Marcellus (per Mcfe)
For the Years Ended December 31,
2017
209.7
27.6
2.1
239.4
2016
186.8
23.5
2.2
212.5
Variance
22.9
4.1
(0.1)
26.9
Percent
Change
12.3 %
17.4 %
(4.5)%
12.7 %
$
$
$
$
$
$
$
2.50
$
1.87
(0.14) $
$
3.96
$
6.44
2.57
0.13
0.07
1.07
0.92
2.19
0.38
$
$
$
0.79
2.38
4.32
2.64
0.16
0.08
1.07
0.99
2.30
0.34
$
$
$
$
$
$
$
0.63
33.7 %
(0.93)
1.58
2.12
(117.7)%
66.4 %
49.1 %
(0.07)
(0.03)
(0.01)
—
(0.07)
(0.11)
0.04
(2.7)%
(18.8)%
(12.5)%
— %
(7.1)%
(4.8)%
11.8 %
* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Marcellus segment had natural gas, NGLs and oil revenue of $646 million for the year ended December 31,
2017compared to $415 million for the year ended December 31, 2016. The $231 million increase was primarily due to the 33.7%
increase in the average gas sales price as well as the 12.7% increase in total Marcellus sales volumes in the period-to-period
comparison. The increase in sales volumes was primarily due to the termination of the Marcellus joint venture with Noble Energy
in the fourth quarter of 2016, which resulted in each party owning and operating a 100% interest in certain wells in two separate
operating areas (See Note 10 - Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements in
Item 8 of this Form 10-K for additional details) as well as additional wells being turned in line in the 2017 period.
The decrease in the total average Marcellus sales price was primarily the result of changes in the fair value of commodity
derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial
hedges represented approximately 177.6 Bcf of the Company's produced Marcellus gas sales volumes for the year ended
December 31, 2017 at an average loss of $0.17 per Mcf. For the year ended December 31, 2016, these financial hedges represented
approximately 160.8 Bcf at an average gain of $0.92 per Mcf. The $0.93 per Mcf change in the fair value of the commodity
derivative instruments was offset, in part, by the $0.63 per Mcf increase in gas market prices, along with a $0.12 per Mcfe increase
in the uplift from NGLs and condensate sales volumes, when excluding the impact of hedging.
Total operating costs and expenses for the Marcellus segment were $525 million for the year ended December 31, 2017
compared to $490 million for the year ended December 31, 2016. The increase in total dollars and decrease in unit costs for the
Marcellus segment were due to the following items:
• Marcellus lease operating expense was $32 million for the year ended December 31, 2017 compared to $34 million for
the year ended December 31, 2016. The decrease in total dollars was primarily due to a reduction in salt water disposal costs and
equipment rental expense in the 2017 period. The decrease in unit costs was primarily due to the 12.7% increase in total Marcellus
sales volumes, along with the decrease in total dollars described above.
59
• Marcellus production, ad valorem, and other fees were $15 million for the year ended December 31, 2017 compared to
$17 million for the year ended December 31, 2016. The decrease in total dollars was primarily due to a change in production mix
by state as a result of the termination of the Marcellus joint venture with Noble Energy, offset, in part, by the increase in average
gas sales price. The decrease in unit costs was due to the decrease in total dollars described above, as well as the 12.7% increase
in total Marcellus sales volumes.
• Marcellus transportation, gathering and compression costs were $256 million for the year ended December 31, 2017
compared to $228 million for the year ended December 31, 2016. The $28 million increase in total dollars was primarily related
to an increase in the CNXM gathering fee due to the increase in total Marcellus sales volumes (See Note 25 - Related Party
Transactions of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information),
and an increase in processing fees associated with NGLs primarily due to the 17.4% increase in NGL sales volumes.
• Depreciation, depletion and amortization costs attributable to the Marcellus segment were $222 million for the year ended
December 31, 2017 compared to $211 million for the year ended December 31, 2016. These amounts included depletion on a unit
of production basis of $0.91 per Mcf and $0.98 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
UTICA SEGMENT
The Utica segment had earnings from continuing operations before income tax of $65 million for the year ended December 31,
2017 compared to earnings from continuing operations before income tax of $28 million for the year ended December 31, 2016.
Utica Gas Sales Volumes (Bcf)
NGLs Sales Volumes (Bcfe)*
Oil Sales Volumes (Bcfe)*
Condensate Sales Volumes (Bcfe)*
Total Utica Sales Volumes (Bcfe)*
Average Sales Price - Gas (per Mcf)
Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)
Average Sales Price - NGLs (per Mcfe)*
Average Sales Price - Oil (per Mcfe)*
Average Sales Price - Condensate (per Mcfe)*
Total Average Utica Sales Price (per Mcfe)
Average Utica Lease Operating Expenses (per Mcfe)
Average Utica Production, Ad Valorem, and Other Fees (per Mcfe)
Average Utica Transportation, Gathering and Compression Costs (per Mcfe)
Average Utica Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Utica Costs (per Mcfe)
Average Margin for Utica (per Mcfe)
For the Years Ended December 31,
2017
2016
70.7
11.1
0.2
1.0
83.0
2.29
0.02
4.20
7.31
6.88
2.63
0.23
0.06
0.54
1.02
1.85
0.78
$
$
$
$
$
$
$
$
71.3
16.7
—
2.8
90.8
1.52
0.41
2.49
—
4.78
2.12
0.25
0.05
0.57
0.94
1.81
0.31
$
$
$
$
$
$
$
$
Variance
(0.6)
(5.6)
0.2
(1.8)
(7.8)
0.77
(0.39)
1.71
7.31
2.10
0.51
(0.02)
0.01
(0.03)
0.08
0.04
0.47
Percent
Change
(0.8)%
(33.5)%
100.0 %
(64.3)%
(8.6)%
50.7 %
(95.1)%
68.7 %
100.0 %
43.9 %
24.1 %
(8.0)%
20.0 %
(5.3)%
8.5 %
2.2 %
151.6 %
*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content
of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
The Utica segment had natural gas, NGLs and oil revenue of $217 million for the year ended December 31, 2017 compared
to $163 million for the year ended December 31, 2016. The $54 million increase was primarily due to the 50.7% increase in
average gas sales price, offset, in part, by the 8.6% decrease in total Utica sales volumes. The 7.8 Bcfe decrease in total Utica sales
volumes primarily related to normal well declines in the wet gas joint venture production areas offset in part by increased production
in the 100% CNX controlled dry Utica production areas resulting from the Company's 2017 capital investment.
60
The increase in the total average Utica sales price was primarily due to a $0.77 increase in average gas sales price, offset,
in part, by the $0.39 per Mcf decrease in the gain on commodity derivative instruments in 2017. The notional amounts associated
with these financial hedges represents approximately 39.8 Bcf of the Company's produced Utica gas sales volumes for the year
ended December 31, 2017 at an average gain of $0.04 per Mcf. For the year ended December 31, 2016, these financial hedges
represented approximately 31.6 Bcf at an average gain of $0.93 per Mcf.
Total operating costs and expenses for the Utica segment were $153 million for the year ended December 31, 2017 compared
to $164 million for the year ended December 31, 2016. The decrease in total dollars and increase in unit costs for the Utica segment
were due to the following items:
• Utica lease operating expense decreased to $19 million for the year ended December 31, 2017, compared to $22 million
for the year ended December 31, 2016. The decrease in total dollars was due to a reduction in repairs and maintenance costs and
lower production volumes. The decrease in unit costs was due to the decrease in repairs and maintenance cost and a shift in
production mix to lower cost dry Utica production.
• Utica production, ad valorem, and other fees were $5 million for each of the years ended December 31, 2017 and
December 31, 2016. The increase in unit costs was also due to the decrease in total Utica sales volumes.
• Utica transportation, gathering and compression costs were $45 million for the year ended December 31, 2017 compared
to $51 million for the year ended December 31, 2016. The $6 million decrease in total dollars was primarily related to decreased
gathering and processing fees associated with the decreased Utica NGLs and gas sales volumes. The decrease in unit costs was
due to the decrease in total Utica sales volumes, predominantly in the wet areas that require additional processing offset, in part,
by the increase in the lower cost dry Utica production.
• Depreciation, depletion and amortization costs attributable to the Utica segment were $84 million for the year ended
December 31, 2017 compared to $86 million for the year ended December 31, 2016. These amounts included depletion on a unit
of production basis of $1.01 per Mcf and $0.93 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings from continuing operations before income tax of $20 million for the year ended December 31,
2017 compared to earnings from continuing operations before income tax of $38 million for the year ended December 31, 2016.
CBM Gas Sales Volumes (Bcf)
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas
(per Mcf)
Total Average CBM Sales Price (per Mcf)
Average CBM Lease Operating Expenses (per Mcf)
Average CBM Production, Ad Valorem, and Other Fees (per Mcf)
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
Total Average CBM Costs (per Mcf)
Average Margin for CBM (per Mcf)
For the Years Ended December 31,
2017
2016
Variance
Percent
Change
65.4
69.0
(3.6)
(5.2)%
$
$
$
$
$
3.19
$
2.53
(0.15) $
0.76
3.05
0.39
0.11
0.98
1.26
2.74
0.31
$
$
$
3.29
0.36
0.09
1.04
1.25
2.74
0.55
$
$
$
$
$
0.66
26.1 %
(0.91)
(119.7)%
(0.24)
0.03
0.02
(0.06)
0.01
—
(0.24)
(7.3)%
8.3 %
22.2 %
(5.8)%
0.8 %
— %
(43.6)%
The CBM segment had natural gas sales of $209 million for the year ended December 31, 2017 compared to $175 million
for the year ended December 31, 2016. The $34 million increase was due to a 26.1% increase in the average gas sales price, offset
in part, by the 5.2% decrease in CBM gas sales volumes. The decrease in CBM sales volumes was primarily due to normal well
declines and less drilling activity.
61
The total average CBM sales price decreased $0.24 per Mcf due primarily to changes in fair value of the commodity derivative
instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges
represented approximately 56.3 Bcf of the Company's produced CBM sales volumes for the year ended December 31, 2017 at an
average loss of $0.17 per Mcf. For the year ended December 31, 2016, these financial hedges represented approximately 55.0 Bcf
at an average gain of $0.95 per Mcf. The $0.91 per Mcf change in fair value of the commodity derivative instruments was offset,
in part, by a $0.66 per Mcf increase in market prices.
Total operating costs and expenses for the CBM segment were $179 million for the year ended December 31, 2017 compared
to $189 million for the year ended December 31, 2016. The decrease in total dollars was due to the following items:
• CBM lease operating expense remained consistent at $25 million for the years ended December 31, 2017 and December 31,
2016. The increase in unit costs was due to the decrease in CBM gas sales volumes.
• CBM production, ad valorem, and other fees were $7 million for the year ended December 31, 2017 compared to $6
million for the year ended December 31, 2016. The $1 million increase was due to an increase in severance tax expense resulting
from the increase in the average gas sales price, partially offset by the decrease in production volumes. Unit costs were negatively
impacted by the increase in total average gas sales price which was offset, in part, by the decrease in CBM gas sales volumes.
• CBM transportation, gathering and compression costs were $64 million for the year ended December 31, 2017 compared
to $72 million for the year ended December 31, 2016. The $8 million decrease was primarily related to a decrease in repairs and
maintenance expense and power fees resulting from cost cutting measures implemented by management as well as a decrease in
utilized firm transportation expense resulting from a decrease in CBM gas sales volumes. Unit costs were also positively impacted
by the decrease in total dollars which was offset, in part, by the decrease in CBM gas sales volumes.
• Depreciation, depletion and amortization costs attributable to the CBM segment were $83 million for the year ended
December 31, 2017 compared to $86 million for the year ended December 31, 2016. These amounts included depletion on a unit
of production basis of $0.78 per Mcf and $0.82 per Mcf, respectively. The remaining depreciation, depletion and amortization
costs were either recorded on a straight-line basis or related to gas well closing.
62
OTHER GAS SEGMENT
The Other Gas segment had a loss from continuing operations before income tax of $239 million for the year ended
December 31, 2017 compared to a loss from continuing operations before income tax of $732 million for the year ended
December 31, 2016.
For the Years Ended December 31,
Other Gas Sales Volumes (Bcf)
Oil Sales Volumes (Bcfe)*
Total Other Sales Volumes (Bcfe)*
2017
2016
19.2
0.2
19.4
21.7
0.4
22.1
Variance
(2.5)
(0.2)
(2.7)
Average Sales Price - Gas (per Mcf)
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement- Gas (per
Mcf)
Average Sales Price - Oil (per Mcfe)*
$
2.69
$
1.79
$ 0.90
$ (0.14) $
$
7.75
$
0.75
6.23
$ (0.89)
$ 1.52
Total Average Other Sales Price (per Mcfe)
Average Other Lease Operating Expenses (per Mcfe)
Average Other Production, Ad Valorem, and Other Fees (per Mcfe)
Average Other Transportation, Gathering and Compression Costs (per Mcfe)
Average Other Depreciation, Depletion and Amortization Costs (per Mcfe)
Total Average Other Costs (per Mcfe)
Average Margin for Other (per Mcfe)
$
$
0.12
0.12
2.62
2.61
0.69
0.63
$ 0.01
(0.06)
—
(0.17)
(0.44)
$ (0.67)
$
$ (0.08) $ (0.76) $ 0.68
1.49
1.05
2.70
3.37
0.90
1.07
$
Percent
Change
(11.5)%
(50.0)%
(12.2)%
50.3 %
(118.
7)%
24.4 %
0.4 %
(8.7)%
— %
(15.9)%
(29.5)%
(19.9)%
89.5 %
*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of oil and natural gas prices.
The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes
purchased gas activity, unrealized gain or loss on commodity derivative instruments, exploration and production related other
costs, impairment of exploration and production properties and other operational activity not assigned to a specific segment.
Other Gas sales volumes are primarily related to shallow oil and gas production. Although not discussed in this section,
CNX sold substantially all its Other Gas assets in the 2018 period. Natural gas, NGLs and oil revenue related to the Other Gas
segment were $53 million for the year ended December 31, 2017 compared to $40 million for the year ended December 31, 2016.
The increase in natural gas and oil revenue resulted from the $0.90 per Mcf increase in average gas sales price. Total exploration
and production costs related to these other sales were $56 million for the year ended December 31, 2017 compared to $78 million
for the year ended December 31, 2016. The decrease was primarily due to a decrease in depreciation, depletion and amortization
costs as a result of certain assets becoming fully depreciated in 2017 as well as the sale of Knox Energy in the second quarter of
2017 (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this
Form 10-K for additional information).
The Other Gas segment recognized an unrealized gain on commodity derivative instruments of $248 million as well as cash
settlements paid of $2 million for the year ended December 31, 2017. For the year ended December 31, 2016, the Company
recognized an unrealized loss on commodity derivative instruments of $386 million as well as cash settlements received of $17
million. The unrealized gain/loss on commodity derivative instruments represented changes in the fair value of all of the Company's
existing commodity hedges on a mark-to-market basis.
Purchased gas volumes represent volumes of gas purchased at market prices from third-parties and then resold in order to
fulfill contracts with certain customers. Purchased gas revenue was $54 million for the year ended December 31, 2017 compared
to $43 million for the year ended December 31, 2016. Purchased gas costs were $53 million for the year ended December 31,
2017 compared to $43 million for the year ended December 31, 2016. The period-to-period increase in purchased gas revenue
was primarily due to the increase market prices, as well as the increase in purchased gas sales volumes.
63
Purchased Gas Sales Volumes (in billion cubic feet)
Average Sales Price (per Mcf)
Average Cost (per Mcf)
For the Years Ended December 31,
2017
2016
Variance
22.0
2.44
2.39
$
$
21.7
1.99
1.97
$
$
0.3
0.45
0.42
$
$
Percent
Change
1.4%
22.6%
21.3%
Other operating income was $69 million for each of the years ended December 31, 2017 compared to $65 million for the
year ended December 31, 2016. The $4 million increase was primarily due to the following items:
(in millions)
Water Income
Gathering Income
Equity in Earnings of Affiliates
Other
Total Other Operating Income
For the Years Ended December 31,
2017
2016
Variance
$
$
5
11
50
3
69
$
$
1
11
53
—
65
$
$
Percent
Change
400.0 %
— %
(5.7)%
100.0 %
6.2 %
4
—
(3)
3
4
• Water Income increased $4 million due to increased sales of freshwater to third-parties for hydraulic fracturing.
• Equity in Earnings of Affiliates decreased $3 million primarily due to a decrease in earnings from Buchanan Generation,
LLC.
Impairment of Exploration and Production Properties of $138 million for the year ended December 31, 2017 related to an
impairment in the carrying value of Knox Energy in the first quarter of 2017. See Note 1 - Significant Accounting Policies in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. No such impairments
occurred in 2016.
Exploration and production related other costs were $48 million for the year ended December 31, 2017 compared to $15
million for the year ended December 31, 2016. The $33 million increase is due to the following items:
(in millions)
Lease Expiration Costs
Land Rentals
Permitting Expense
Other
Total Exploration and Production Related Other Costs
For the Years Ended December 31,
2017
2015
Variance
$
$
40
4
1
3
48
$
$
7
4
2
2
15
$
$
Percent
Change
471.4 %
100.0 %
(50.0)%
50.0 %
220.0 %
33
—
(1)
1
33
• Lease Expiration Costs relate to leases where the primary term expired or will expire within the next 12 months. The $33
million increase in the period-to-period comparison is due to an increase in the number of leases that were allowed to
expire in the year ended December 31, 2017, or would expire within the next 12 months thereafter, because they were
no longer in the Company's future drilling plan. Additionally, approximately $10 million of the $33 million increase was
associated with leases which have ceased production.
64
Other operating expense was $112 million for the year ended December 31, 2017 compared to $89 million for the year
ended December 31, 2016. The $23 million increase in the period-to-period comparison was made up of the following items:
(in millions)
Idle Rig Expense
Unutilized Firm Transportation and Processing Fees
Litigation Settlements
Severance Expense
Insurance Expense
Other
Total Other Operating Expense
For the Years Ended December 31,
2017
2016
Variance
$
$
41
50
3
1
3
14
112
$
$
33
37
1
1
3
14
89
$
$
8
13
2
—
—
—
23
Percent
Change
24.2%
35.1%
200.0%
—%
—%
—%
25.8%
•
Idle Rig Expense increased $8 million due to the temporary idling of some of the Company's natural gas rigs. Additionally,
the total idle rig expense increased in the period-to-period comparison due to a settlement that was reached with a former
joint-venture partner that resulted in CNX recording additional expense.
• Unutilized Firm Transportation and Processing Fees represent pipeline transportation capacity obtained to enable gas
production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The
increase in the period-to-period comparison was primarily due to the decrease in the utilization of capacity. The Company
attempts to minimize this expense by releasing (selling) unutilized firm transportation capacity to other parties when
possible and when beneficial. The revenue received when this capacity is released (sold) is included in Gathering Income
in other operating income above.
Selling, General and Administrative
SG&A costs represent direct charges for the management and operation of CNX's E&P division. SG&A costs were $93
million for the year ended December 31, 2017 compared to $104 million for the year ended December 31, 2016. Refer to the
discussion of total company SG&A costs contained in the section "Net Income (Loss)" of this Form 10-K for a detailed cost
explanation.
Interest Expense
Interest expense of $161 million was recognized in the year ended December 31, 2017 compared to $182 million in the year
ended December 31, 2016. The $21 million decrease was primarily due to the redemption of each of the 8.25% senior notes due
in April 2020 and the 6.375% senior notes due in March 2021 and the purchase of a portion of the 5.875% senior notes due in
April 2022 in the year ended December 31, 2017. See Note 14 - Long-Term Debt in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information.
65
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities,
revenues and expenses, and related disclosure of contingent assets and liabilities in the Consolidated Financial Statements and at
the date of the financial statements. See Note 1-Significant Accounting Policies in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for further discussion. We base our estimates on historical experience and on various other
assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments
about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates on
an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management
believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments,
assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Asset Retirement Obligations
Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset
retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate
to the closure of gas wells and the reclamation of land upon exhaustion of gas reserves. Changes in the variables used to calculate
the liabilities can have a significant effect on the gas well closing liability. The amounts of assets and liabilities recorded are
dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions
involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.
The Company believes that the accounting estimates related to asset retirement obligations are “critical accounting estimates”
because the Company must assess the expected amount and timing of asset retirement obligations. In addition, the Company must
determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period
could be materially affected by changes in the Company’s assumptions.
Income Taxes
Deferred tax assets and liabilities are recognized using enacted tax rates for the estimated future tax effects of temporary
differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation
allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. All available evidence, both
positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2018, CNX had
deferred tax liabilities in excess of deferred tax assets of approximately $304 million. At December 31, 2018, CNX had a valuation
allowance of $94 million on deferred tax assets.
CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not
to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine
the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate
settlement is determined. A previously recognized tax position is reversed when it is subsequently determined that a tax position
no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the
probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that
we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources,
form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution
of identified matters. CNX has $32 million of uncertain tax liabilities at December 31, 2018. See Note 8 - Income Taxes in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the
Company’s uncertain tax liabilities.
The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the
Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise judgment
regarding the amount of financial statement benefit to record for uncertain tax positions. When evaluating whether or not a valuation
allowance must be established on deferred tax assets, the Company exercises judgment in determining whether it is more likely
than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized. The Company
considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation
allowance is needed, including carrybacks, tax planning strategies and reversal of deferred tax assets and liabilities. In making the
determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could
be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the
reporting date to establish the appropriate amount of financial statement benefit. To the extent that an uncertain tax position or
66
valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit
within tax expense in the income statement. Future results of operations for any particular quarterly or annual period could be
materially affected by changes in the Company’s assumptions.
Stock-Based Compensation
The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of the Company's
stock on the date of the grant. The fair value of each performance share unit is determined by a Monte Carlo simulation method.
The fair value of each stock option is determined using the Black-Scholes option pricing model. All outstanding performance
stock options are fully vested.
The Company believes that the accounting estimates related to share-based compensation are “critical accounting estimates”
because they may change from period-to-period based on changes in assumptions about factors affecting the ultimate payout of
awards, including the number of awards to ultimately vest and the market price and volatility of the Company’s common stock.
Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s
assumptions. See Note 17 - Stock-Based Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8
of this Form 10-K for additional information regarding the Company’s share-based compensation.
Contingencies
CNX is currently involved in certain legal proceedings. The Company has accrued our estimate of the probable costs for the
resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these
matters and is based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar
matters, and management's intended response. Future results of operations for any particular quarter or annual period could be
materially affected by changes in our assumptions or the outcome of these proceedings. Legal fees associated with defending these
various lawsuits and claims are expensed when incurred.
The Company believes that the accounting estimates related to contingencies are “critical accounting estimates” because the
Company must assess the probability of loss related to contingencies. In addition, the Company must determine the estimated
present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially
affected by changes in the Company’s assumptions. 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 more information.
Derivative Instruments
CNX enters into financial derivative instruments to manage exposure to natural gas price volatility. We measure every
derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of
derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair
value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. Prior to
December 31, 2014, the effective portions of changes in fair value of derivatives designated as cash flow hedges were reported
in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction
affected earnings. The ineffective portions of hedges were recognized in earnings in the current year.
The Company believes that the accounting estimates related to derivative instruments are “critical accounting estimates”
because the Company’s financial condition and results of operations can be significantly impacted by changes in the market value
of the Company’s derivative instruments due to the volatility of natural gas prices. Future results of operations for any particular
quarterly or annual period could be materially affected by changes in the Company’s assumptions.
Natural Gas, NGL, Condensate and Oil Reserve ("Natural Gas Reserve") Values
Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and natural gas which,
by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a
given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations
prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable natural gas
reserves, including many factors beyond our control. As a result, estimates of economically recoverable natural gas reserves are
by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological
67
data assembled and analyzed by our staff. Our natural gas reserves are reviewed by independent experts each year. Some of the
factors and assumptions which impact economically recoverable reserve estimates include:
•
•
•
•
•
geological conditions;
historical production from the area compared with production from other producing areas;
the assumed effects of regulations and taxes by governmental agencies;
assumptions governing future prices; and
future operating costs.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons,
estimates of the economically recoverable quantities of gas attributable to a particular group of properties, and classifications of
these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues
and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. See "Risk
Factors" in Item 1A of this Form 10-K for a discussion of the uncertainties in estimating our reserves.
The Company believes that the accounting estimate related to oil and gas reserves is a “critical accounting estimate” because
the Company must periodically reevaluate proved reserves along with estimates of future production rates, production costs and
the estimated timing of development expenditures. Future results of operations and strength of the balance sheet for any particular
quarterly or annual period could be materially affected by changes in the Company’s assumptions. See "Impairment of Long-lived
Assets" below for additional information regarding the Company’s oil and gas reserves.
Impairment of Long-lived Assets
The carrying values of the Company's proved oil and gas properties are reviewed for impairment whenever events or changes
in circumstances indicate that a property’s carrying amount may not be recoverable. Impairment tests require that the Company
first compare future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds
the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated
fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average
cost of capital.
In February 2017, the Company approved a plan to sell subsidiaries Knox Energy LLC and Coalfield Pipeline Company
(collectively, Knox). As part of the required evaluation under the held for sale guidance, Knox's book value was evaluated, and it
was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold.
The resulting impairment of $137,865 was included in Impairment of Exploration and Production Properties in the Consolidated
Statements of Income. See Note 1 - Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements
in Item 8 of this Form 10-K for more information.
There were no other impairments related to proved properties in the years ended December 31, 2018, 2017 or 2016.
CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators of potential
impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that
the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. There were
no impairments related to unproved properties in the years ended December 31, 2018, 2017 or 2016.
The Company believes that the accounting estimates related to the impairment of long-lived assets are “critical accounting
estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to
changes in assumptions impacting management’s estimates of future financial results. In addition, the Company must determine
the estimated undiscounted future cash flows. The Company believes the estimates and assumptions used in estimating the fair
value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair
value and the resulting determinations about the impairment of long-lived assets which could materially impact the Company’s
results of operations and financial position. Additionally, future estimates may differ materially from current estimates and
assumptions.
Impairment of Goodwill
Goodwill is not amortized, but rather it is evaluated for impairment annually during the fourth quarter, or more frequently
if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its
carrying value. This determination includes estimating the fair value using both income and market approaches. The income
approach requires management to estimate a number of factors for a reporting unit, including projected future operating results,
68
economic projections, anticipated future cash flows and discount rates. The market approach estimates fair value using comparable
marketplace fair value data from within a comparable industry grouping. CNX goodwill is allocated to one reporting unit within
the Midstream segment.
The determination of the fair value requires us to make significant estimates and assumptions. These estimates and
assumptions primarily include but are not limited to: the selection of appropriate peer group companies; control premiums
appropriate for acquisitions in the industries in which we compete; discount rates; terminal growth rates; and forecasts of revenue,
operating income, depreciation and amortization and capital expenditures. Although we believe our estimates of fair value are
reasonable, actual financial results could differ from those estimates due to the inherent uncertainty involved in making such
estimates. Changes in assumptions concerning future financial results or other underlying assumptions could have a significant
impact on either the fair value of the reporting unit, the amount of any goodwill impairment charge, or both.
The Company performed its annual goodwill impairment test during the fourth quarter of 2018 and concluded that goodwill
was not impaired.
The Company believes that the accounting estimates related to goodwill are “critical accounting estimates” because the fair
value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions
impacting management’s estimates of future financial results. The fair value estimation process requires considerable judgment
and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results
as well as other assumptions such as movement in the Company's stock price, weighted-average cost of capital, terminal growth
rates, changes in the business climate, unanticipated changes in the competitive environment, adverse legal or regulatory actions
or developments, changes in capital structure, cost of debt, interest rates, capital expenditure levels, operating cash flows, or market
capitalization and industry multiples. The Company believes the estimates and assumptions used in estimating the fair value are
reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and
the resulting determinations about goodwill impairment which could materially impact the Company’s results of operations and
financial position. Additionally, future estimates may differ materially from current estimates and assumptions.
Impairment of Definite-lived Intangible Assets
Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed
for impairment when indicators of impairment are present. Impairment tests require that the Company first compare future
undiscounted cash flows to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future
cash flows, a reduction of the carrying amount of the asset to its estimated fair value is required.
In May 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were
acquired in connection with the Midstream acquisition exceeded their fair value in conjunction with the Asset Exchange Agreement
with HG Energy II Appalachia, LLC (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). CNX recognized an impairment on this intangible asset of $18,650,
which is included in Impairment of Other Intangible Assets in the Consolidated Statements of Income.
The Company believes that the accounting estimates related to the impairment of definite-lived intangible assets are “critical
accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is
sensitive to changes in assumptions impacting management’s estimates of future financial results. The Company believes the
estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and
estimates could materially impact the calculated fair value and the resulting determinations about the impairment of definite-lived
intangible assets which could materially impact the Company’s results of operations and financial position. Additionally, future
estimates may differ materially from current estimates and assumptions.
Business Combinations
Accounting for the acquisition of a business requires the identifiable assets and liabilities acquired to be recorded at fair
value. The most significant assumptions in a business combination include those used to estimate the fair value of the oil and gas
properties acquired. The fair value of proved natural gas properties is determined using a risk-adjusted after-tax discounted cash
flow analysis based upon significant assumptions including commodity prices; projections of estimated quantities of reserves;
projections of future rates of production; timing and amount of future development and operating costs; projected reserve recovery
factors; and a weighted average cost of capital.
69
The Company utilizes the guideline transaction method to estimate the fair value of unproved properties acquired in a business
combination which requires the Company to use judgment in considering the value per undeveloped acre in recent comparable
transactions to estimate the value of unproved properties.
The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression
stations, is estimated using the cost approach, which incorporates assumptions about the replacement costs for similar assets, the
relative age of assets and any potential economic or functional obsolescence.
The fair values of the intangible assets are estimated using the multi-period excess earnings model which estimates revenues
and cash flows derived from the intangible asset and then deducts portions of the cash flow that can be attributed to supporting
assets otherwise recognized. The Company’s intangible assets are comprised of customer relationships.
The Company believes that the accounting estimates related to business combinations are “critical accounting estimates”
because the Company must, in determining the fair value of assets acquired, make assumptions about future commodity prices;
projections of estimated quantities of reserves; projections of future rates of production; projections regarding the timing and
amount of future development and operating costs; and projections of reserve recovery factors, per acre values of undeveloped
property, replacement cost of and future cash flows from midstream assets, cash flow from customer relationships and non-compete
agreements and the pre and post modification value of stock based awards. Different assumptions may result in materially different
values for these assets which would impact the Company’s financial position and future results of operations.
Liquidity and Capital Resources
CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations
with cash generated from operations and proceeds from borrowings. On March 8, 2018, CNX amended and restated its senior
secured revolving credit facility (the Credit Facility), which increased lenders' commitments from $1.5 billion to $2.1 billion with
an accordion feature that allows the Company to increase the commitments to $3.0 billion. The initial borrowing base increased
from $2.0 billion to $2.5 billion, and the letters of credit aggregate sub-limit remained unchanged at $650 million. Effective August
20, 2018, as part of the semi-annual redetermination, the borrowing base was reduced to $2.1 billion primarily based on the sale
of substantially all of CNX's Ohio Utica Joint Venture Assets and shallow oil and gas assets (See Note 6 - Acquisitions and
Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information).
There was no change to the commitments amount. The Credit Facility matures on March 8, 2023, provided that if the aggregate
principal amount of our existing 5.875% Senior Notes due in April 2022 and certain other publicly traded debt securities outstanding
91 days prior to the earliest maturity of such debt (such date, the "Springing Maturity Date") is greater than $500 million, then
the Credit Facility will mature on the Springing Maturity Date.
The Credit Facility is secured by substantially all of the assets of CNX and certain of its subsidiaries, excluding CNXM.
Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the Credit
Facility is limited to a borrowing base, which is determined by the lenders' syndication agent and approved by the required number
of lenders in good faith by calculating a value of CNX's proved natural gas reserves.
The Credit Facility contains a number of affirmative and negative covenants that include, among others, covenants that,
except in certain circumstances, limit the Company and the subsidiary guarantors' ability to create, incur, assume or suffer to exist
indebtedness, create or permit to exist liens on properties, dispose of assets, make investments, purchase or redeem CNX common
stock, pay dividends, merge with another corporation and amend the senior unsecured notes. The Company must also mortgage
80% of the value of its proved reserves and 80% of the value of its proved developed producing reserves, in each case, which are
included in the borrowing base, maintain applicable deposit, securities and commodities accounts with the lenders or affiliates
thereof, and enter into control agreements with respect to such applicable accounts.
The Credit Facility also requires that CNX maintain a maximum net leverage ratio of no greater than 4.00 to 1.00, which is
calculated as the ratio of debt less cash on hand to consolidated EBITDA, measured quarterly. CNX must also maintain a minimum
current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current
liabilities, excluding short-term borrowings under the revolver, measured quarterly. The calculation of all of the ratios exclude
CNXM. CNX was in compliance of all financial covenants as of December 31, 2018.
At December 31, 2018, the Credit Facility had $612 million of borrowings outstanding and $198 million of letters of credit
outstanding, leaving $1,290 million of unused capacity. From time to time, CNX is required to post financial assurances to satisfy
contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply
with federal, state or other government agencies' statutes and regulations. CNX sometimes uses letters of credit to satisfy these
requirements and these letters of credit reduce the Company's borrowing facility capacity.
70
Uncertainty in the financial markets brings additional potential risks to CNX. These risks include declines in the Company's
stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures.
Financial market disruptions may impact the Company's collection of trade receivables. As a result, CNX regularly monitors the
creditworthiness of its customers and counterparties and manages credit exposure through payment terms, credit limits, prepayments
and security. CNX believes that its current group of customers is financially sound and represents no abnormal business risk.
CNX believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to
meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled
debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CNX to satisfy
its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will
depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry
and other financial and business factors, some of which are beyond CNX's control.
In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical
natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX has also entered into
various natural gas and NGL swap and option transactions, which exist parallel to the underlying physical transactions. The fair
value of these contracts was a net asset of $99 million at December 31, 2018 and a net asset of $60 million at December 31, 2017.
The Company has not experienced any issues of non-performance by derivative counterparties.
CNX frequently evaluates potential acquisitions. CNX has funded acquisitions with cash generated from operations and a
variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance
that additional capital resources, including debt and equity financing, will be available to CNX on terms which CNX finds
acceptable, or at all.
Cash Flows (in millions)
Cash provided by operating activities
Cash used in investing activities
Cash (used in) provided by financing activities
For the Years Ended December 31,
2018
2017
Change
$
$
$
886
$
(895) $
(483) $
649
$
(222) $
$
36
237
(673)
(519)
Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:
• Net income increased $502 million in the period-to-period comparison.
• Adjustments to reconcile net income to cash provided by operating activities primarily consisted of a $624 million
gain on previously held equity interest, a $488 million change in deferred income taxes, a $138 million decrease in
impairment of exploration and production properties, a $130 million change in discontinued operations (See Note 5 -
Discontinued Operations in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form
10-K for more information), a $208 million net change in commodity derivative instruments, and a $52 million increase
in the loss on debt extinguishment.
Cash used in investing activities changed in the period-to-period comparison primarily due to the following items:
•
• Capital expenditures increased $483 million in the period-to-period comparison primarily due to increased expenditures
in both the Marcellus and Utica Shale plays resulting from increased drilling and completions activity. Also contributing
to the increase is CNXM's capital expenditures which were not included in 2017 due to the consolidation that occurred
in 2018. See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in
Item 8 of this Form 10-K for additional information.
In January 2018, CNX acquired Noble Energy's interest in CNX Gathering for a net payment of $299 million. See
Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this
Form 10-K for additional information.
Proceeds from the sale of assets increased $98 million primarily due to the 2018 sale of substantially all of the Ohio
Utica Joint Venture Assets in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble counties along
with the 2018 sale of substantially all of CNX's shallow oil and gas assets and certain CBM assets in Pennsylvania and
West Virginia. This was partially offset by the 2017 sales of approximately 32,900 net undeveloped acres in Ohio,
Pennsylvania, and West Virginia.
•
71
Cash (used in) provided by financing activities changed in the period-to-period comparison primarily due to the following
items:
•
•
•
•
•
•
•
•
In the year ended December 31,2018, there were $612 million of borrowings on the CNX credit facility.
In the year ended December 31, 2018, CNX paid $955 million to repurchase all of the remaining 8.00% senior notes
due April 2023 and $411 million of the 5.75% senior notes due in April 2022. CNXM also received proceeds of $394
million from long-term borrowings. In the year ended December 31, 2017, CNX paid $240 million to repurchase $144
million of the 5.75% senior notes due in April 2022 and the remaining 8.25% senior notes due in April 2020 and the
6.375% senior notes due in March 2021. See Note 14 - Long-Term Debt in the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K for additional information.
In the years ended December 31, 2018 and 2017, CNX repurchased $382 million and $103 million, respectively, of its
common stock on the open market.
In the year ended December 31,2018, there were $66 million of net payments on the CNXM credit facility.
In the year ended December 31,2018, there were $55 million in distributions to CNXM noncontrolling interest holders.
In the year ended December 31, 2017, CNX received proceeds of $425 million related to the 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
Form 10-K for additional information.
In the year ended December 31, 2018, there were $21 million in debt issuance and financing fees. These fees were
nominal in the twelve months ended December 31, 2017.
Financing activities of discontinued operations changed $32 million. See Note 5 - Discontinued Operations in the Notes
to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for more information.
72
The following is a summary of the Company's significant contractual obligations at December 31, 2018 (in thousands):
Less Than
1 Year
1-3 Years
3-5 Years
More Than
5 Years
Total
Payments due by Year
Purchase Order Firm Commitments
Gas Firm Transportation and Processing
Long-Term Debt
Interest on Long-Term Debt
Capital (Finance) Lease Obligations
Interest on Capital (Finance) Lease Obligations
Operating Lease Obligations
Long-Term Liabilities—Employee Related (a)
Other Long-Term Liabilities (b)
Total Contractual Obligations (c)
$
$
22,036
198,352
—
133,124
6,997
1,252
70,590
1,857
244,087
678,295
$
$
1,155
406,924
—
266,248
13,299
989
128,405
4,012
27,421
848,453
$
— $
— $
358,820
1,992,376
129,454
—
—
24,665
4,303
2,364
$ 2,511,982
1,034,145
394,625
65,000
—
—
36,256
25,508
32,877
$ 1,588,411
23,191
1,998,241
2,387,001
593,826
20,296
2,241
259,916
35,680
306,749
$ 5,627,141
_________________________
(a)
(b)
(c)
Employee related long-term liabilities include salaried retirement contributions and work-related injuries and illnesses.
Other long-term liabilities include royalties and other long-term liability costs.
The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the
ultimate settlement of amounts and timing of these obligations.
Debt
At December 31, 2018, CNX had total long-term debt and capital lease obligations of $2,407 million outstanding, including
the current portion of long-term debt of $7 million. This long-term debt consisted of:
• An aggregate principal amount of $1,294 million of 5.875% Senior Notes due in April 2022 plus $2 million of unamortized
bond premium. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest
on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM.
• An aggregate principal amount of $612 million in outstanding borrowings under the CNX revolver.
• An aggregate principal amount of $400 million of 6.50% Senior Notes due in March 2026 issued by CNXM, less $5
million of unamortized bond discount. Interest on the notes is payable March 15 and September 15 of each year. Payment
on the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of
these notes.
• An aggregate principal amount of $84 million in outstanding borrowings under the CNXM revolver. CNX is not a
guarantor of CNXM's revolving credit facility.
• An aggregate principal amount of $20 million of capital leases with a weighted average interest rate of 7.18% per annum.
73
Total Equity and Dividends
CNX had total equity of $5,082 million at December 31, 2018 compared to $3,900 million at December 31, 2017. See the
Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.
The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance
can be given that CNX will pay dividends in the future. CNX's Board of Directors determines whether dividends will be paid
quarterly. CNX suspended its quarterly dividend in March 2016 to further reflect the Company's increased emphasis on growth.
The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's
financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX,
and such other factors as the Board of Directors deems relevant. The Company's Credit Facility limits CNX's ability to pay dividends
in excess of an annual rate of $0.10 per share when the Company's leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate
amount up to a cumulative credit calculation set forth in the Credit Facility. The total leverage ratio was 2.26 to 1.00 at December 31,
2018. The credit facility does not permit dividend payments in the event of default. The indentures to the 5.75% notes due in
August 2022 notes limit dividends to $0.50 per share annually unless several conditions are met. These conditions include no
defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the year
ended December 31, 2018.
On January 16, 2019, the Board of Directors of CNX Midstream GP LLC, the general partner of CNX Midstream Partners
LP, announced the declaration of a cash distribution of $0.3603 per unit with respect to the fourth quarter of 2018. The distribution
will be made on February 13, 2019 to unitholders of record as of the close of business on February 5, 2019. The distribution, which
equates to an annual rate of $1.4412 per unit, represents an increase of 3.6% over the prior quarter, and an increase of 15% over
the distribution paid with respect to the fourth quarter of 2017.
Off-Balance Sheet Transactions
CNX does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated
entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, changes
in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are
not disclosed in the Notes to the Audited Consolidated Financial Statements. CNX uses a combination of surety bonds, corporate
guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance
and various other items which are not reflected on the Consolidated Balance Sheet at December 31, 2018. Management believes
these items will expire without being funded. 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 additional details of the various financial guarantees that have
been issued by CNX.
Recent Accounting Pronouncements
In October 2018, the Financial Accounting Standards Board (FASB) issued Update 2018-17 - Consolidation - Targeted
Improvements to Related Party Guidance for Variable Interest Entities ("VIE") (Topic 810). This Update states that indirect interests
held through related parties in common control arrangements should be considered on a proportional basis for determining whether
fees paid to decision makers and service providers are variable interests. This is consistent with how indirect interests held through
related parties under common control are considered for determining whether a reporting entity must consolidate a VIE. Entities
are required to apply the amendments retrospectively. The amendments in this Update are effective for fiscal years beginning after
December 15, 2019, and early adoption is permitted. The adoption of this guidance is not expected to have a material impact on
the Company's financial statements.
In August 2018, the FASB issued Update 2018-14 - Compensation - Retirement Benefits - Defined Benefit Plans - General
(Subtopic 715-20), which modifies the disclosure requirements for employers that sponsor defined benefit pension or other
postretirement plans. This Update removes the requirement to disclose the amounts in accumulated other comprehensive income
expected to be recognized as components of net periodic benefit cost over the next fiscal year and adds a requirement to disclose
an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. For public
business entities, the amendments in this Update are effective for fiscal years ending after December 15, 2020, and early adoption
is permitted. Entities should apply these amendments retrospectively. The adoption of this guidance is not expected to have a
material impact on the Company's financial statements.
In August 2018, the FASB issued Update 2018-13 - Fair Value Measurement (Topic 820), which modifies the disclosure
requirements in Topic 820. This Update removes the following disclosure requirements: the amount of and reasons for transfers
between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels, and the valuation
processes for Level 3 fair value measurements. The Update also makes the following additions: the changes in unrealized gains
74
and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end
of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value
measurements. This Update is effective for fiscal years beginning after December 15, 2019, including interim periods within those
fiscal years, and early adoption is permitted. Entities should apply the additions prospectively and all other amendments should
be applied retrospectively. The adoption of this guidance is not expected to have a material impact on the Company's financial
statements.
In February 2018, the FASB issued Update 2018-02 - Income Statement - Reporting Comprehensive Income (Topic 220),
which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting
from the Act. Consequently, the amendments eliminate the stranded tax effects resulting from the Act and will improve the
usefulness of information reported to financial statement users. However, because the amendments only relate to the reclassification
of the income tax effects of the Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included
in income from continuing operations is not affected. This Update also requires certain disclosures about stranded tax effects. The
amendments in this Update are effective for fiscal years beginning after December 15, 2018, and interim periods within those
fiscal years. Early adoption is permitted, and the amendments should be applied either in the period of adoption or retrospectively
to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Act is recognized.
The Company early adopted ASU 2018-02 which resulted in the reclassification of $1.1 million, related to stranded tax effects,
from accumulated other comprehensive income to retained earnings in the fourth quarter of 2018.
In January 2017, the FASB issued Update 2017-04 - Simplifying the Test of Goodwill Impairment. This Update simplifies
the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill
(Step 2 of the current goodwill impairment test). Instead a company would record an impairment charge based on the excess of a
reporting unit's carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This Update is
effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption
is permitted. Entities will apply the standard's provisions prospectively. The Company adopted Update 2017-04 on January 1,
2018 and determined that this standard will not have a material quantitative effect on the financial statements, unless an impairment
charge is necessary.
In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability
among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key
information about leasing arrangements. Update 2016-02 maintains a distinction between finance leases and operating leases,
which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the
previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash
flows arising from a lease to remain similar to the previous accounting treatment. A lessee is permitted to make an accounting
policy election by class of underlying asset to exclude from balance sheet recognition any lease assets and lease liabilities with a
term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing
and operating leases, the ROU asset and lease liability will be initially measured at the present value of the lease payments in the
statement of financial position. For public business entities, the amendments in this update are effective for fiscal years beginning
after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to
recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with the
option to adopt certain practical expedients. In July 2018, the FASB issued Update 2018-11 which provides entities with the option
to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance
of retained earnings in the period of adoption.
CNX has substantially completed an analysis of our leases and continues to assess the impact of Topic 842 on our internal
controls over financial reporting. The Company will adopt Topic 842 guidance as of January 1, 2019 using the transition method
that allows a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We have elected
the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all of our
leases that existed prior to the transition date. As a result, CNX will not reassess 1) whether existing or expired contracts contain
leases 2) lease classification for any existing or expired leases and 3) whether lease origination costs qualified as initial direct
costs. CNX will not elect the practical expedient to use hindsight in determining a lease term and impairment of ROU assets at
the adoption date. Additionally, the Company will elect the short-term practical expedient for all of our asset classes by establishing
an accounting policy to exclude leases with a term of 12 months or less. CNX will not separate lease components from non-lease
components for our specified asset classes. Lastly, CNX will adopt the easement practical expedient which allows the Company
to apply ASC 842 prospectively to land easements after the adoption date. Easements that existed or expired prior to the adoption
date that were not previously assessed under ASC 840 will not be reassessed. CNX has implemented a third-party supported lease
accounting system to account for the identified leases and is currently in the process of performing final testing of this system.
75
The adoption of Topic 842 will have a material impact on the Company’s Consolidated Balance Sheet due to the initial
recognition of ROU assets and lease liabilities. Upon adoption of Topic 842, the Company expects to recognize a ROU asset and
corresponding lease liability between $200 million to $225 million on its Consolidated Balance Sheet.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In addition to the risks inherent in operations, CNX is exposed to certain financial, market, political and economic risks.
The following discussion provides additional detail regarding CNX's exposure to the risks of changing commodity prices, interest
rates and foreign exchange rates.
CNX is exposed to market price risk in the normal course of selling natural gas. CNX uses fixed-price contracts, options
and derivative commodity instruments to minimize exposure to market price volatility in the sale of natural gas and NGLs. Under
our risk management policy, it is not our intent to engage in derivative activities for speculative purposes.
CNX has established risk management policies and procedures to strengthen the internal control environment of the marketing
of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held
for purposes other than trading. They are used primarily to mitigate uncertainty and volatility, and cover underlying exposures.
The Company's market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a
framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.
CNX believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates
our exposure to material risks. The use of derivative instruments without other risk assessment procedures could materially affect
the Company's results of operations depending on market prices; however, we believe that use of these instruments will not have
a material adverse effect on our financial position or liquidity due to our risk assessment procedures and internal controls.
For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
At December 31, 2018 and December 31, 2017, our open derivative instruments were in a net asset position with a fair value
of $99 million and $60 million, respectively. A sensitivity analysis has been performed to determine the incremental effect on
future earnings related to open derivative instruments at December 31, 2018 and December 31, 2017. A hypothetical 10 percent
increase in future natural gas prices would have decreased the fair value by $427 million and $323 million at December 31, 2018
and December 31, 2017, respectively. A hypothetical 10 percent decrease in future natural gas prices would have increased the
fair value by $453 million and $321 million at December 31, 2018 and December 31, 2017, respectively.
CNX's interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31,
2018 and December 31, 2017, CNX had $1,703 million and $2,214 million, respectively, aggregate principal amount of debt
outstanding under fixed-rate instruments, including unamortized debt issuance costs of $9 million and $18 million, respectively.
At December 31, 2018, CNX had $696 million of debt outstanding under variable-rate instruments, and had no debt outstanding
under variable-rate instruments at December 31, 2017. CNX’s primary exposure to market risk for changes in interest rates relates
to our revolving credit facility, under which there were $612 million of borrowings at December 31, 2018 and no borrowings at
December 31, 2017, and CNXM's revolving credit facility, under which there were $84 million of borrowings at December 31,
2018. A hypothetical 100 basis-point increase in the average rate for CNX's and CNXM's revolving credit facilities would decrease
pre-tax future earnings by $7 million at December 31, 2018. There would be no impact on pre-tax future earnings at December 31,
2017.
All of CNX's transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency
exchange-rate risks.
76
Natural Gas Hedging Volumes
As of January 18, 2019, the Company's hedged volumes for the periods indicated are as follows:
For the Three Months Ended
March 31,
June 30,
September 30,
December 31,
Total Year
2019 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf
2020 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf
2021 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf
2022 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf
2023 Fixed Price Volumes
Hedged Bcf
Weighted Average Hedge Price per Mcf
$
$
$
$
$
88.7
2.79
108.1
2.58
101.2
2.44
68.2
2.48
31.3
2.35
$
$
$
$
$
96.8
2.67
120.7
2.54
102.3
2.44
69.0
2.48
31.7
2.35
$
$
$
$
$
97.9
2.67
122.0
2.54
103.4
2.44
69.7
2.48
32.0
2.35
$
$
$
$
$
95.7
2.72
122.0
2.54
103.4
2.44
69.7
2.48
32.0
2.35
$
$
$
$
$
376.0*
2.71
468.6*
2.55
410.3
2.44
276.6
2.48
127.0
2.35
*Quarterly volumes do not add to annual volumes in as much as a discrete condition in individual quarters, where basis hedge
volumes exceed NYMEX hedge volumes, does not exist for the year taken as a whole.
77
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017, 2016
Notes to the Audited Consolidated Financial Statements
Page
79
80
81
82
84
85
86
78
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of CNX Resources Corporation and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CNX Resources Corporation and Subsidiaries (the Company)
as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, stockholders'
equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and financial
statement schedule listed in the Index at Item 15 (a) (2) (collectively referred to as the “financial statements”). In our opinion, the
financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31,
2018 and 2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended
December 31, 2018, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework) and our report dated February 7, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error
or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether
due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Pittsburgh, Pennsylvania
February 7, 2019
79
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share data)
Revenue and Other Operating Income:
Natural Gas, NGLs and Oil Revenue
(Loss) Gain on Commodity Derivative Instruments
Purchased Gas Revenue
Midstream Revenue
Other Operating Income
Total Revenue and Other Operating Income
Costs and Expenses:
Operating Expense
Lease Operating Expense
Transportation, Gathering and Compression
Production, Ad Valorem, and Other Fees
Depreciation, Depletion and Amortization
Exploration and Production Related Other Costs
Purchased Gas Costs
Impairment of Exploration and Production Properties
Impairment of Other Intangible Assets
Selling, General and Administrative Costs
Other Operating Expense
Total Operating Expense
Other (Income) Expense
Other (Income) Expense
Gain on Sale of Assets
Gain on Previously Held Equity Interest
Loss on Debt Extinguishment
Interest Expense
Total Other (Income) Expense
Total Costs and Expenses
Earnings (Loss) from Continuing Operations Before Income Tax
Income Tax Expense (Benefit)
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations, net
Net Income (Loss)
Less: Net Income Attributable to Noncontrolling Interests
Net Income (Loss) Attributable to CNX Resources Shareholders
$
For the Years Ended December 31,
2018
2017
2016
$
$
1,577,937
(30,212)
65,986
89,781
26,942
1,730,434
$
1,125,224
206,930
53,795
—
69,182
1,455,131
793,248
(141,021)
43,256
—
64,485
759,968
96,434
374,350
31,049
419,939
14,522
42,717
—
—
104,843
88,754
1,172,608
4,783
(14,270)
—
—
182,195
172,708
1,345,316
(585,348)
(34,403)
(550,945)
(297,157)
(848,102)
—
(848,102)
95,139
302,933
32,750
493,423
12,033
64,817
—
18,650
134,806
72,412
1,226,963
(14,571)
(157,015)
(623,663)
54,118
145,934
(595,197)
631,766
1,098,668
215,557
883,111
—
883,111
86,578
796,533
$
88,932
382,865
29,267
412,036
48,074
52,597
137,865
—
93,211
112,369
1,357,216
3,825
(188,063)
—
2,129
161,443
(20,666)
1,336,550
118,581
(176,458)
295,039
85,708
380,747
—
380,747
$
The accompanying notes are an integral part of these financial statements.
80
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(CONTINUED)
(Dollars in thousands, except per share data)
Earnings (Loss) Per Share
Basic
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations
Total Basic Earnings (Loss) Per Share
Diluted
Income (Loss) from Continuing Operations
Income (Loss) from Discontinued Operations
Total Diluted Earnings (Loss) Per Share
Dividends Declared Per Share
For the Years Ended December 31,
2018
2017
2016
$
$
$
$
$
3.75
—
3.75
3.71
—
3.71
$
$
$
$
1.29
0.37
1.66
1.28
0.37
1.65
$
$
$
$
(2.40)
(1.30)
(3.70)
(2.40)
(1.30)
(3.70)
— $
— $
0.01
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
Net Income (Loss)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments (Net
of tax: ($792), ($7,365), 16,281)
Reclassification of Cash Flow Hedges from Other
Comprehensive Income to Earnings (Net of tax: $-, $-,
$25,011)
Other Comprehensive Income (Loss)
For the Years Ended December 31,
2018
2017
2016
$
883,111
$
380,747
$
(848,102)
1,672
—
1,672
12,228
(33,226)
—
(43,470)
12,228
(76,696)
Comprehensive Income (Loss)
$
884,783
$
392,975
$
(924,798)
Less: Comprehensive Income Attributable to Noncontrolling
Interests
86,578
—
—
Comprehensive Income (Loss) Attributable to CNX Resources
Shareholders
$
798,205
$
392,975
$
(924,798)
The accompanying notes are an integral part of these financial statements.
81
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
Current Assets:
Cash and Cash Equivalents
Accounts and Notes Receivable:
Trade
Other Receivables
Supplies Inventories
Recoverable Income Taxes
Prepaid Expenses
Total Current Assets
Property, Plant and Equipment (Note 10):
Property, Plant and Equipment
Less—Accumulated Depreciation, Depletion and Amortization
Total Property, Plant and Equipment—Net
Other Assets:
Investment in Affiliates
Goodwill
Other Intangible Assets
Other
Total Other Assets
TOTAL ASSETS
December 31,
2018
December 31,
2017
$
17,198
$
509,167
252,424
11,077
9,715
149,481
61,791
501,686
156,817
48,908
10,742
31,523
95,347
852,504
9,567,428
2,624,984
6,942,444
9,316,495
3,526,742
5,789,753
18,663
796,359
103,200
229,818
1,148,040
$ 8,592,170
197,921
—
—
91,735
289,656
$ 6,931,913
The accompanying notes are an integral part of these financial statements.
82
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share data)
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable
Current Portion of Long-Term Debt (Note 14 and Note 15)
Other Accrued Liabilities (Note 13)
Total Current Liabilities
Long-Term Debt:
Long-Term Debt (Note 14)
Capital Lease Obligations (Note 15)
Total Long-Term Debt
Deferred Credits and Other Liabilities:
Deferred Income Taxes (Note 8)
Asset Retirement Obligations (Note 9)
Other
Total Deferred Credits and Other Liabilities
TOTAL LIABILITIES
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 500,000,000 Shares Authorized, 198,663,342 Issued and
Outstanding at December 31, 2018; 223,743,322 Issued and Outstanding at December 31,
2017
Capital in Excess of Par Value
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding
Retained Earnings
Accumulated Other Comprehensive Loss
Total CNX Resources Stockholders’ Equity
Noncontrolling Interest
TOTAL STOCKHOLDERS' EQUITY
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
December 31,
2018
December 31,
2017
$
$
229,806
6,997
286,172
522,975
211,161
7,111
223,407
441,679
2,378,205
13,299
2,391,504
398,682
37,479
159,787
595,948
3,510,427
2,187,026
20,347
2,207,373
44,373
198,768
139,821
382,962
3,032,014
1,990
2,264,063
—
2,071,809
(7,904)
4,329,958
751,785
5,081,743
$ 8,592,170
2,241
2,450,323
—
1,455,811
(8,476)
3,899,899
—
3,899,899
$ 6,931,913
The accompanying notes are an integral part of these financial statements.
83
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Dollars in thousands, except per share data)
December 31, 2015
Net (Loss) Income
Gas Cash Flow Hedge (Net of $25,011
Tax)
Actuarially Determined Long-Term
Liability Adjustments (Net of $16,281
Tax)
Comprehensive (Loss) Income
Shares Withheld for Taxes
Issuance of Common Stock
Tax Cost from Stock-Based
Compensation
Amortization of Stock-Based
Compensation Awards
Distributions to Noncontrolling Interests
Dividends ($0.145 per share)
December 31, 2016
Net Income
Actuarially Determined Long-Term
Liability Adjustments (Net of ($7,365)
Tax)
Comprehensive Income
Issuance of Common Stock
Retirement of Common Stock (6,410,900
shares)
Distribution of CONSOL Energy, Inc.
Shares Withheld for Taxes
Amortization of Stock-Based
Compensation Awards
December 31, 2017
Net Income
Actuarially Determined Long-Term
Liability Adjustments (Net of ($792)
Tax)
Comprehensive Income
Issuance of Common Stock
Purchase and Retirement of Common
Stock (25,894,324 shares)
Shares Withheld for Taxes
Acquisition of CNX Gathering, LLC
Amortization of Stock-Based
Compensation Awards
Distributions to CNXM Noncontrolling
Interest Holders
ASU 2018-02 Reclassification
December 31, 2018
Common
Stock
Capital in
Excess
of Par
Value
Retained
Earnings
(Deficit)
Accumulated
Other
Comprehensive
Income
(Loss)
Total
CNX
Resources
Stockholders’
Equity
Non-
Controlling
Interest
Total
Equity
$
2,294
$ 2,435,497
$
2,579,834
$
(315,598) $
4,702,027
$
153,749
$
4,855,776
—
—
—
—
—
4
—
—
—
—
—
—
—
—
—
—
(4,931)
30,298
—
—
(848,102)
—
(848,102)
8,954
(839,148)
—
—
(848,102)
(1,649)
—
—
—
—
(2,294)
(43,470)
(43,470)
—
(43,470)
(33,488)
(76,958)
—
—
—
—
—
—
(33,488)
(925,060)
(1,649)
4
(4,931)
262
9,216
—
—
—
30,298
1,185
—
(21,657)
(2,294)
—
(33,226)
(915,844)
(1,649)
4
(4,931)
31,483
(21,657)
(2,294)
$
2,298
$ 2,460,864
$
1,727,789
$
(392,556) $
3,798,395
$
142,493
$
3,940,888
380,747
—
380,747
$
2,241
$ 2,450,323
$
1,455,811
$
(8,476) $
3,899,899
$
— $
3,899,899
796,533
—
796,533
86,578
883,111
—
—
—
7
(64)
—
—
—
—
—
—
1,002
(51,223)
22,697
—
16,983
—
—
—
8
—
—
—
1,705
—
380,747
—
(51,922)
(594,122)
(6,681)
—
—
796,533
—
(259)
(206,895)
(176,598)
—
—
—
—
—
—
18,930
—
(5,037)
—
—
—
—
—
—
—
—
12,228
12,228
—
—
12,228
392,975
1,009
(103,209)
371,852
(199,573)
(142,493)
—
—
(6,681)
16,983
—
—
380,747
12,228
392,975
1,009
(103,209)
(342,066)
(6,681)
16,983
1,672
1,672
—
—
—
—
—
—
1,672
798,205
1,713
(383,752)
(5,037)
—
86,578
—
—
(348)
1,672
884,783
1,713
(383,752)
(5,385)
—
718,577
718,577
18,930
2,411
21,341
—
(55,433)
—
751,785
(55,433)
—
5,081,743
$
—
1,990
—
$ 2,264,063
1,100
2,071,809
$
$
$
(1,100)
(7,904) $
—
4,329,958
$
The accompanying notes are an integral part of these financial statements.
84
CNX RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Cash Flows from Operating Activities:
Net Income (Loss)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Continuing Operating
Activities:
For the Years Ended December 31,
2018
2017
2016
$
883,111
$
380,747
$
(848,102)
Net (Income) Loss from Discontinued Operations
Depreciation, Depletion and Amortization
Amortization of Deferred Financing Costs
Impairment of Exploration and Production Properties
Impairment of Other Intangible Assets
Stock-Based Compensation
Gain on Sale of Assets
Gain on Previously Held Equity Interest
Loss on Debt Extinguishment
Loss (Gain) on Commodity Derivative Instruments
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments
Deferred Income Taxes
Return on Equity Investment
Equity in Earnings of Affiliates
Changes in Operating Assets:
Accounts and Notes Receivable
Supplies Inventories
Recoverable Income Tax
Prepaid Expenses
Changes in Other Assets
Changes in Operating Liabilities:
Accounts Payable
Accrued Interest
Other Operating Liabilities
Changes in Other Liabilities
Net Cash Provided by Continuing Operating Activities
Net Cash Provided by Discontinued Operating Activities
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities:
Capital Expenditures
CNX Gathering LLC Acquisition, Net of Cash Acquired
Proceeds from Noble Exchange Settlement
Proceeds from Asset Sales
Net Distributions from Equity Affiliates
Net Cash (Used in) Provided by Continuing Investing Activities
Net Cash (Used in) Provided by Discontinued Investing Activities
Net Cash (Used in) Provided by Investing Activities
Cash Flows from Financing Activities:
Proceeds from (Payments on) CNX Revolving Credit Facility
Payments on Miscellaneous Borrowings
Payments on Long-Term Notes
Proceeds from Issuance of CNXM Senior Notes
Net Payments on CNXM Revolving Credit Facility
Distributions to CNXM Noncontrolling Interest Holders
Proceeds from Spin-Off of CONSOL Energy Inc.
Dividends Paid
Proceeds from Issuance of Common Stock
Shares Withheld for Taxes
Purchases of Common Stock
Debt Issuance and Financing Fees
Net Cash (Used in) Provided by Continuing Financing Activities
Net Cash Used in Discontinued Financing Activities
Net Cash (Used in) Provided by Financing Activities
Net (Decrease) Increase in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
—
493,423
8,361
—
18,650
21,341
(157,015)
(623,663)
54,118
30,212
(69,720)
345,560
—
(5,363)
(57,734)
1,027
(118,498)
(1,391)
4,904
12,760
(5,839)
53,135
(1,556)
885,823
—
885,823
(1,116,397)
(299,272)
—
511,767
9,250
(894,652)
—
(894,652)
612,000
(7,165)
(955,019)
394,000
(65,500)
(55,433)
—
—
1,713
(5,385)
(381,752)
(20,599)
(483,140)
—
(483,140)
(491,969)
509,167
(85,708)
412,036
10,630
137,865
—
16,983
(188,063)
—
2,129
(206,930)
(41,174)
(142,829)
—
(49,830)
(32,792)
4,254
76,196
631
22,018
45,669
(2,955)
81,969
(7,778)
433,068
215,619
648,687
(632,846)
—
—
414,185
42,873
(175,788)
(46,133)
(221,921)
—
(8,037)
(239,716)
—
—
—
425,000
—
1,009
(6,681)
(103,209)
(361)
68,005
(31,903)
36,102
462,868
46,299
$
17,198
$
509,167
$
297,157
419,939
9,059
—
—
19,316
(14,270)
—
—
141,021
245,212
75,892
22,268
(53,078)
(46,434)
(1,486)
(91,313)
76,668
(2,473)
(17,227)
(1,144)
(41,913)
78,140
267,232
197,026
464,258
(172,739)
—
213,295
46,989
73,743
161,288
326,083
487,371
(952,000)
(7,802)
—
—
—
—
—
(2,294)
4
(1,649)
—
—
(963,741)
(6,663)
(970,404)
(18,775)
65,074
46,299
The accompanying notes are an integral part of these financial statements.
85
CNX RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:
A summary of the significant accounting policies of CNX Resources Corporation and subsidiaries ("CNX " or "the Company")
is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.
Basis of Consolidation:
The Consolidated Financial Statements include the accounts of CNX Resources Corporation, and its wholly-owned and
majority-owned and/or controlled subsidiaries, including certain variable interest entities that the Company is required to
consolidate pursuant to the Consolidation topic of the Financial Accounting Standards Board (FASB) Accounting Standards
Codification. The portion of these entities that is not owned by the Company is presented as non-controlling interest. Investments
in business entities in which CNX does not have control, but has the ability to exercise significant influence over the operating
and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have
been eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate
consolidation method.
Discontinued Operations:
Businesses divested are classified in the Consolidated Financial Statements as either discontinued operations or held for sale
when the provision of Accounting Standards Codification (ASC) Topic 205 or ASC Topic 360 are met. For businesses classified
as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation
to assets and liabilities of discontinued operations on the Consolidated Balance Sheets and to discontinued operations on the
Consolidated Statements of Income and Cash Flows for all periods presented. The gains or losses associated with these divested
businesses are recorded in discontinued operations on the Consolidated Statements of Income. The disclosures outside of Note 5-
Discontinued Operations, for all periods presented, in the accompanying notes generally do not include the assets, liabilities, or
operating results of businesses classified as discontinued operations.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates
included in, but not limited to, the preparation of the consolidated financial statements are related to salary retirement benefits,
fair value of derivative instruments, long-lived assets (including intangibles assets and goodwill), stock-based compensation, asset
retirement obligations, deferred income tax assets and liabilities, contingencies and the values of natural gas, NGLs, condensate
and oil (collectively "natural gas") reserves.
Cash and Cash Equivalents:
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term
securities with original maturities of three months or less.
Trade Accounts Receivable:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CNX reserves for specific accounts
receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies.
Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CNX regularly
reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account
balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is
considered remote. Reserves for uncollectable amounts were not material in the periods presented. In addition, there were no
material financing receivables with a contractual maturity greater than one year at December 31, 2018 or 2017.
86
Inventories:
Inventories are stated at the lower of cost or net realizable value. The cost of supplies inventory is determined by the average
cost method and includes operating and maintenance supplies to be used in the Company's operations.
Property, Plant and Equipment:
CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions,
successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation
provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells
are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient
quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests
are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are also amortized
on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or more frequently if
events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in
accounting estimates.
Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing
plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period.
Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.
Gas advance royalties are royalties that are paid in advance for the right to use an owner's land for the exploration and
production of oil, NGLs and natural gas. These advance royalties are evaluated periodically, or at a minimum once per year, for
impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any
revisions are accounted for prospectively as changes in accounting estimates.
Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms,
generally as follows:
Buildings and improvements
Machinery and equipment
Gathering and transmission
Leasehold improvements
Years
10 to 45
3 to 25
30 to 40
Life of Lease
Costs for purchased software are capitalized and amortized using the straight-line method over the estimated useful life
which does not exceed seven years.
Impairment of Long-lived Assets:
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows
estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced
to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity
investments is recorded when indicators of impairment are present, and the estimated fair value of the investment is less than the
assets' carrying value.
In February 2017, the Company approved a plan to sell its subsidiaries Knox Energy LLC and Coalfield Pipeline Company
(collectively, “Knox”). Knox met all of the criteria to be classified as held for sale in February 2017. As part of the required
evaluation under the held for sale guidance, during the first quarter, Knox’s book value was evaluated, and it was determined that
the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment
of $137,865 was included in Impairment of Exploration and Production Properties within the Consolidated Statements of Income
during the year ended December 31, 2017. The sale of Knox closed in the second quarter of 2017 (See Note 6 - Acquisitions and
Dispositions for more information). The disposal of Knox did not represent a strategic shift that would have had a major effect on
the Company’s operations and financial results and was, therefore, not classified as a discontinued operation in accordance with
Topic 205, Presentation of Financial Statements, and Topic 360, Property, Plant and Equipment.
87
Impairment of Proved Properties:
CNX performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's
carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods
and other assumptions consistent with historical periods. When indicators of impairment are present, tests require that the Company
first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount
exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their
estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted
average cost of capital. There were no impairments related to proved properties in the years ended December 31, 2018, 2017 or
2016.
Impairment of Unproved Properties:
CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators of potential
impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that
the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. There were
no impairments related to unproved properties in the years ended December 31, 2018, 2017 or 2016.
Exploration expense, which is associated primarily with lease expirations, was $12,033, $48,074 and $14,522 for the years
ended December 31, 2018, 2017 and 2016, respectively, and is included in Exploration and Production Related Other Costs in the
Consolidated Statements of Income.
Impairment of Goodwill:
Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is
not amortized, but rather it is evaluated for impairment annually during the fourth quarter, or more frequently if recent events or
prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. These
indicators include, but are not limited to, overall financial performance, industry and market considerations, anticipated future
cash flows and discount rates, changes in the stock price with regards to CNX or common unit price with regards to CNXM,
regulatory and legal developments, and other relevant factors. In connection with the Midstream Acquisition (See Note 6 -
Acquisition and Disposition for more information), CNX recorded $796,359 of goodwill through the application of purchase
accounting. The goodwill recorded was allocated to one reporting unit within the Midstream segment.
In connection with the annual evaluation of goodwill for impairment, CNX may first consider qualitative factors to assess
whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount.
To the extent that such indicators exist, a goodwill impairment test is completed. If the carrying value of the goodwill of a reporting
unit exceeds its implied fair value, the difference is recognized as an impairment charge. The Company uses a combination of the
income approach (generally a discounted cash flow method) and market approach (including the guideline public company method
and the guideline transaction method) to estimate the fair value of a reporting unit.
The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in
assumptions impacting management’s estimates of future financial results. Although CNX believes the estimates and assumptions
used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the
estimated fair value. Future results could differ from our current estimates and assumptions.
CNX performed its annual goodwill impairment test in the fourth quarter of 2018 and determined the estimated fair value
exceeded carrying value, and accordingly no adjustment to goodwill was necessary.
Impairment of Definite-Lived Intangible Assets
Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed
for impairment when indicators of impairment are present.
In connection with the Midstream Acquisition (See Note 6 - Acquisitions and Dispositions for more information), CNX
recorded $128,781 of other intangible assets, which are comprised of customer relationships, through the application of purchase
accounting.
In May 2018, CNX determined that the carrying value of a portion of the customer relationship intangible assets that were
acquired in connection with the Midstream acquisition exceeded their fair value in conjunction with the Asset Exchange Agreement
88
with HG Energy II Appalachia, LLC (See Note 6 - Acquisitions and Dispositions for more information). CNX recognized an
impairment on this intangible asset of $18,650, which is included in Impairment of Other Intangible Assets in the Consolidated
Statements of Income.
The customer relationships intangible asset will be amortized on a straight-line basis over approximately 17 years.
Income Taxes:
Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized
in the Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for
the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from
differences between the financial and tax bases of the Company's assets and liabilities and are adjusted for changes in tax rates
and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely
than not that a deferred tax benefit will not be realized.
CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not
to be sustained upon examination. For positions that do not meet the more likely than not to be sustained criteria, the Company
determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate
settlement. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets
the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount
that is more likely than not is based on judgment, historical experience and on various other assumptions that the Company believes
are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the
basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution
of identified matters.
Asset Retirement Obligations:
CNX accrues for dismantling and removing costs of gas-related facilities and related surface reclamation using the accounting
treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards
Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred
if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes
in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as
part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined
on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate
over the life of the producing asset, typically as production declines. Accretion is included in Depreciation, Depletion and
Amortization in the Consolidated Statements of Income.
Retirement Plan:
CNX had a non-contributory defined benefit retirement plan that was transferred to CONSOL Energy at the date of the spin-
off and as such CNX no longer maintains the plan. The benefits for this plan were based primarily on years of service and employees'
pay. The plan was accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB
Accounting Standards Codification.
Investment Plan:
CNX has an investment plan that is available to most employees. Throughout the years ended December 31, 2018, 2017 and
2016, the Company's matching contribution was 6% of eligible compensation contributed by eligible employees. The Company
may also make discretionary contributions to the Plan ranging from 1% to 6% of eligible compensation for eligible employees
(as defined by the Plan). Discretionary contributions made by the Company were $2,761 for the year ended December 31,
2016. There were no such discretionary contributions made by CNX for the years ended December 31, 2018 and 2017. Total
payments and costs were $3,205, $2,866 and $5,858 for the years ended December 31, 2018, 2017 and 2016, respectively, including
the discretionary contribution mentioned above.
Revenue Recognition:
Revenues are recognized when the recognition criteria of ASC 606 are met, which generally occurs at the point in which
title passes to the customers. For natural gas, NGL and oil revenue, this occurs at the contractual point of delivery. For midstream
revenue this occurs when obligations under the terms of the contract with the shipper are satisfied.
89
CNX sells natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price
and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right
of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting
under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within
the Consolidated Statements of Income in the Purchased Gas Revenue line.
CNX purchases natural gas produced by third-parties at market prices less a fee. The gas purchased from third-parties is
then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased
Gas Revenue and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas revenue is recognized
when title passes to the customer. Purchased gas costs are recognized when title passes to CNX from the third-party.
Contingencies:
From time to time, CNX, or its subsidiaries, are subject to various lawsuits and claims with respect to such matters as personal
injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental
remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of business.
Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the
nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's
intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties. Legal fees
associated with defending these various lawsuits and claims are expensed when incurred.
Stock-Based Compensation:
Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated
in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CNX
recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the
award's vesting term. See Note 17–Stock-Based Compensation for more information.
Accounting for Derivative Instruments:
CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. The derivatives are
accounted for as an asset or a liability in the accompanying Consolidated Balance Sheets at their fair value using Level 2 inputs,
which is further defined in Note 20 - Fair Value of Financial Instruments. Changes in the fair values of derivatives are recorded
in earnings unless special hedge accounting criteria are met.
CNX de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future natural gas
and NGL commodity hedges on a mark-to-market basis, and records changes in fair value in current period earnings. In connection
with this de-designation, CNX froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014
and reclassified balances to earnings as the underlying physical transactions occurred. As of December 31, 2016, all gains that
had been previously deferred in other comprehensive income ("OCI") were recognized in earnings.
All of the Company's derivative instruments are subject to master netting arrangements with its counterparties, none of which
currently require CNX to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if the
Company's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other
lenders under the credit facility, CNX would be required to post collateral for hedges that are in a liability position in excess of
defined thresholds. Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early
termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open
hedge positions.
CNX is exposed to credit risk in the event of non-performance by counterparties, whose creditworthiness is subject to
continuing review. Historically, CNX has not experienced any issues of non-performance by derivative counterparties.
Recent Accounting Pronouncements:
In October 2018, the FASB issued Update 2018-17 - Consolidation - Targeted Improvements to Related Party Guidance for
Variable Interest Entities (Topic 810). This Update states that indirect interests held through related parties in common control
arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service
providers are variable interests. This is consistent with how indirect interests held through related parties under common control
90
are considered for determining whether a reporting entity must consolidate a VIE. Entities are required to apply the amendments
retrospectively. The amendments in this Update are effective for fiscal years beginning after December 15, 2019, and early adoption
is permitted. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.
In August 2018, the FASB issued Update 2018-14 - Compensation - Retirement Benefits - Defined Benefit Plans - General
(Subtopic 715-20), which modifies the disclosure requirements for employers that sponsor defined benefit pension or other
postretirement plans. This Update removes the requirement to disclose the amounts in accumulated other comprehensive income
expected to be recognized as components of net periodic benefit cost over the next fiscal year and adds a requirement to disclose
an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. For public
business entities, the amendments in this Update are effective for fiscal years ending after December 15, 2020, and early adoption
is permitted. Entities should apply these amendments retrospectively. The adoption of this guidance is not expected to have a
material impact on the Company's financial statements.
In August 2018, the FASB issued Update 2018-13 - Fair Value Measurement (Topic 820), which modifies the disclosure
requirements in Topic 820. This Update removes the following disclosure requirements: the amount of and reasons for transfers
between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels, and the valuation
processes for Level 3 fair value measurements. The Update also makes the following additions: the changes in unrealized gains
and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end
of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value
measurements. This Update is effective for fiscal years beginning after December 15, 2019, including interim periods within those
fiscal years, and early adoption is permitted. Entities should apply the additions prospectively and all other amendments should
be applied retrospectively. The adoption of this guidance is not expected to have a material impact on the Company's financial
statements.
In February 2018, the FASB issued Update 2018-02 - Income Statement - Reporting Comprehensive Income (Topic 220),
which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting
from the Act. Consequently, the amendments eliminate the stranded tax effects resulting from the Act and will improve the
usefulness of information reported to financial statement users. However, because the amendments only relate to the reclassification
of the income tax effects of the Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included
in income from continuing operations is not affected. This Update also requires certain disclosures about stranded tax effects. The
amendments in this Update are effective for fiscal years beginning after December 15, 2018, and interim periods within those
fiscal years. Early adoption is permitted, and the amendments should be applied either in the period of adoption or retrospectively
to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Act is recognized.
The Company early adopted ASU 2018-02 which resulted in the reclassification of $1,100, related to stranded tax effects, from
accumulated other comprehensive income to retained earnings in the fourth quarter of 2018.
In January 2017, the FASB issued Update 2017-04 - Simplifying the Test of Goodwill Impairment. This Update simplifies
the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill
(Step 2 of the current goodwill impairment test). Instead a company would record an impairment charge based on the excess of a
reporting unit's carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This Update is
effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption
is permitted. Entities will apply the standard's provisions prospectively. The Company adopted Update 2017-04 on January 1,
2018 and determined that this standard will not have a material quantitative effect on the financial statements, unless an impairment
charge is necessary.
In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability
among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key
information about leasing arrangements. Update 2016-02 maintains a distinction between finance leases and operating leases,
which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the
previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash
flows arising from a lease to remain similar to the previous accounting treatment. A lessee is permitted to make an accounting
policy election by class of underlying asset to exclude from balance sheet recognition any lease assets and lease liabilities with a
term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing
and operating leases, the ROU asset and lease liability will be initially measured at the present value of the lease payments in the
statement of financial position. For public business entities, the amendments in this update are effective for fiscal years beginning
after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to
recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with the
option to adopt certain practical expedients. In July 2018, the FASB issued Update 2018-11 which provides entities with the option
91
to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance
of retained earnings in the period of adoption.
CNX has substantially completed an analysis of our leases and continues to assess the impact of Topic 842 on our internal
controls over financial reporting. The Company will adopt Topic 842 guidance as of January 1, 2019 using the transition method
that allows a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We have elected
the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all of our
leases that existed prior to the transition date. As a result, CNX will not reassess 1) whether existing or expired contracts contain
leases 2) lease classification for any existing or expired leases and 3) whether lease origination costs qualified as initial direct
costs. CNX will not elect the practical expedient to use hindsight in determining a lease term and impairment of ROU assets at
the adoption date. Additionally, the Company will elect the short-term practical expedient for all of our asset classes by establishing
an accounting policy to exclude leases with a term of 12 months or less. CNX will not separate lease components from non-lease
components for our specified asset classes. Lastly, CNX will adopt the easement practical expedient which allows the Company
to apply ASC 842 prospectively to land easements after the adoption date. Easements that existed or expired prior to the adoption
date that were not previously assessed under ASC 840 will not be reassessed. CNX has implemented a third-party supported lease
accounting system to account for the identified leases and is currently in the process of performing final testing of this system.
The adoption of Topic 842 will have a material impact on the Company’s Consolidated Balance Sheet due to the initial
recognition of ROU assets and lease liabilities. Upon adoption of Topic 842, the Company expects to recognize a ROU asset and
corresponding lease liability between $200,000 to $225,000 on its Consolidated Balance Sheet.
Reclassifications:
Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December
31, 2018, with no effect on previously reported net income, stockholders' equity, or statement of cash flows.
Subsequent Events:
The Company has evaluated all subsequent events through the date the financial statements were issued. No material
recognized, or non-recognizable subsequent events were identified other than disclosed in Note 26 - Subsequent Event.
NOTE 2—EARNINGS PER SHARE:
Basic earnings per share is computed by dividing net income attributable to CNX shareholders by the weighted average
shares outstanding during the reporting period. Diluted earnings per share is computed similarly to basic earnings per share, except
that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock
options, restricted stock units and performance share units, if dilutive. The number of additional shares is calculated by assuming
that outstanding stock options and performance share options were exercised, that outstanding restricted stock units and performance
share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average
market price during the reporting period. CNX Midstream Partners LP's ("CNXM") dilutive units did not have a material impact
on the Company's earnings per share calculations for the period from January 3, 2018 through December 31, 2018.
The table below sets forth the share-based awards that have been excluded from the computation of diluted earnings per
share because their effect would be antidilutive:
Anti-Dilutive Options
Anti-Dilutive Restricted Stock Units
Anti-Dilutive Performance Share Units
Anti-Dilutive Performance Share Options
For the Years Ended December 31,
2016
2017
2018
6,208,813
2,773,423
2,285,775
663,003
18,598
—
2,400,326
—
145,217
802,804
927,268
927,268
10,074,946
3,719,289
3,358,260
92
The computations for basic and diluted earnings per share are as follows:
$
$
$
$
$
$
$
Income (Loss) from Continuing Operations
Less: Net Income Attributable to Non-Controlling Interest
Net Income from Continuing Operations Attributable to CNX Resources
Shareholders
Income (Loss) from Discontinued Operations
Net Income (Loss) Attributable to CNX Resources Shareholders
Weighted-average shares of common stock outstanding
Effect of diluted shares
Weighted-average diluted shares of common stock outstanding
Earnings (Loss) Per Share:
Basic (Continuing Operations)
Basic (Discontinued Operations)
Total Basic
Diluted (Continuing Operations)
Diluted (Discontinued Operations)
Total Diluted
Shares of common stock outstanding were as follows:
Balance, Beginning of Year
Issuance Related to Stock-Based Compensation (1)
Retirement of Common Stock (2)
Balance, End of Year
For the Years Ended December 31,
2016
2017
2018
(550,945)
—
883,111
295,039
86,578
—
$
$
796,533
—
796,533
$
$
295,039
85,708
380,747
$
$
(550,945)
(297,157)
(848,102)
212,348,581
228,835,112
229,387,403
2,280,384
2,116,700
—
214,628,965
230,951,812
229,387,403
3.75
—
3.75
3.71
—
3.71
$
$
$
$
1.29
0.37
1.66
1.28
0.37
1.65
$
$
$
$
(2.40)
(1.30)
(3.70)
(2.40)
(1.30)
(3.70)
For the Years Ended December 31,
2016
2017
2018
229,054,236
229,443,008
223,743,322
814,344
(25,894,324)
198,663,342
711,214
(6,410,900)
223,743,322
388,772
—
229,443,008
(1) See Note 17 - Stock-Based Compensation for additional information.
(2) See Note 7 - Stock Repurchase for additional information.
NOTE 3—CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS:
Changes in Accumulated Other Comprehensive Loss related to pension obligations, net of tax, were as follows:
Balance at December 31, 2017
Other Comprehensive Income before Reclassifications
Amounts Reclassified from Accumulated Other Comprehensive Loss, net of tax
Current Period Other Comprehensive Income
ASU 2018-02 Reclassification
Balance at December 31, 2018
Amount
(8,476)
1,736
(64)
1,672
(1,100)
(7,904)
$
$
93
The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:
Derivative Instruments (Note 21)
Natural Gas Price Swaps and Options
Tax Expense
Net of Tax
Actuarially Determined Long-Term Liability Adjustments* (Note 16)
Amortization of Prior Service Costs
Recognized Net Actuarial Loss
Settlement Loss
Total
Less: Tax Benefit
Net of Tax
For the Years Ended December 31,
2018
2017
2016
$
$
$
$
— $
—
— $
(193) $
302
—
109
173
(64) $
— $
—
— $
(68,481)
25,011
(43,470)
(2,775) $
23,043
—
20,268
7,499
12,769
$
(590)
23,857
22,196
45,463
16,959
28,504
*Excludes amounts related to the remeasurement of the actuarially determined pension obligations for the years ended December
31, 2018, 2017 and 2016. The table above only shows the reclassifications out of Accumulated Other Comprehensive Loss that
relates to continuing operations.
NOTE 4—REVENUE FROM CONTRACTS WITH CUSTOMERS:
On January 1, 2018, the Company adopted Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with
Customers and all the related amendments (“new revenue standard”) using the modified retrospective method, which did not result
in any changes to previously reported financial information. The updates related to the new revenue standard were applied only
to contracts that were not complete as of January 1, 2018.
Revenue from Contracts with Customers
Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an
amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company
has elected to exclude all taxes from the measurement of transaction price.
Nature of Performance Obligations
At contract inception, the Company assesses the goods and services promised in its contracts with customers and identifies
a performance obligation for each promised good or service that is distinct. To identify the performance obligations, the Company
considers all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by
customary business practices.
For natural gas, NGLs and oil, and purchased gas revenue, the Company generally considers the delivery of each unit (MMBtu
or Bbl) to be a separate performance obligation that is satisfied upon delivery. Payment terms for these contracts typically require
payment within 25 days of the end of the calendar month in which the hydrocarbons are delivered. A significant number of these
contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations,
the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the
Company’s efforts to satisfy the performance obligations. A portion of the contracts contain fixed consideration (i.e. fixed price
contracts or contracts with a fixed differential to NYMEX or index prices). The fixed consideration is allocated to each performance
obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company
generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.
Revenue associated with natural gas, NGLs and oil as presented on the accompanying Consolidated Statement of Income represent
the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling natural gas,
NGLs and oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the
revenue on a net basis.
94
Midstream revenue consists of revenues generated from natural gas gathering activities. The gas gathering services are
interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system.
Volumetric based fees are based on actual volumes gathered. The Company generally considers the interruptible gathering of each
unit (MMBtu) of natural gas as a separate performance obligation. Payment terms for these contracts typically require payment
within 25 days of the end of the calendar month in which the hydrocarbons are gathered.
Transaction price allocated to remaining performance obligations
Accounting Standards Codification (ASC) 606 requires that the Company disclose the aggregate amount of transaction price
that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical
expedients that limit this requirement, including when variable consideration is allocated entirely to a wholly unsatisfied
performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a series.
A significant portion of our natural gas, NGLs and oil and purchased gas revenue is short-term in nature with a contract term
of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company
from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a
contract that has an original expected duration of one year or less.
For revenue associated with contract terms greater than one year, a significant portion of the consideration in those contracts
is variable in nature and the Company allocates the variable consideration in its contract entirely to each specific performance
obligation to which it relates. Therefore, any remaining variable consideration in the transaction price is allocated entirely to wholly
unsatisfied performance obligations. As such, the Company has not disclosed the value of unsatisfied performance obligations
pursuant to the practical expedient.
For revenue associated with contract terms greater than one year with a fixed price component, the aggregate amount of the
transaction price allocated to remaining performance obligations was $167,851 as of December 31, 2018. The Company expects
to recognize net revenue of $53,078 in the next 12 months and $38,071 over the following 12 months, with the remainder recognized
thereafter.
For revenue associated with our midstream contracts, which also have terms greater than one year, we have utilized the
practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining
performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under
our midstream contracts, the interruptible gathering of each unit of natural gas represents a separate performance obligation;
therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance
obligations is not required.
Prior-period performance obligations
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural
gas and NGL revenue may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required
to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We
record the differences between our estimates and the actual amounts received in the month that payment is received from the
purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences
between our revenue estimates and actual revenue received historically have not been significant. For each of the years ended
December 31, 2018, 2017, and 2016, revenue recognized in the reporting period related to performance obligations satisfied in
prior reporting periods was not material.
95
Disaggregation of Revenue
The following table is a disaggregation of our revenue by major sources:
Revenue from Contracts with Customers
Natural Gas Revenue
NGLs Revenue
Condensate Revenue
Oil Revenue
Total Natural Gas, NGLs and Oil Revenue
Purchased Gas Revenue
Midstream Revenue
For the Years Ended December 31,
2016
2017
2018
$
$
$
1,391,459
165,883
17,559
3,036
1,577,937
945,382
156,132
20,531
3,179
1,125,224
65,986
89,781
53,795
—
670,399
97,580
22,748
2,521
793,248
43,256
—
Other Sources of Revenue and Other Operating Income
(Loss) Gain on Commodity Derivative Instruments
Other Operating Income
Total Revenue and Other Operating Income
(30,212)
26,942
1,730,434
$
206,930
69,182
1,455,131
$
$
(141,021)
64,485
759,968
The disaggregated revenue information corresponds with the Company’s segment reporting.
Contract balances
We invoice customers once our performance obligations have been satisfied, at which point payment is unconditional.
Accordingly, our contracts with customers do not give rise to contract assets or liabilities under ASC 606. The Company has no
contract assets recognized from the costs to obtain or fulfill a contract with a customer.
The opening and closing balances of the Company’s receivables related to contracts with customers were $156,817 and
$252,424, respectively. Included in the opening balance are receivables of $9,353 related to the January 3, 2018 acquisition by
CNX Gas of NBL Midstream's interests (See Note 6 - Acquisitions and Dispositions for more information).
NOTE 5—DISCONTINUED OPERATIONS:
On November 28, 2017, CNX announced that it had completed the tax-free spin-off of its coal business resulting in two
independent, publicly traded companies: (i) a coal company, CONSOL Energy, formerly known as CONSOL Mining Corporation
and (ii) CNX, a natural gas exploration and production company, formerly known as CONSOL Energy, Inc. Following the
separation, CONSOL Energy and its subsidiaries hold the coal assets previously held by CNX, including its Pennsylvania Mining
Complex, Baltimore Marine Terminal, its direct and indirect ownership interest in CONSOL Coal Resources LP, formerly known
as CNXC Coal Resources LP, and other related coal assets previously held by CNX. As of the close of business on November 28,
2017, CNX's shareholders received one share of CONSOL Energy common stock for every eight shares of CNX common stock
held as of November 15, 2017. The coal business has been reclassified to discontinued operations for all periods presented.
In August 2016, CNX completed the sale of the Miller Creek and Fola Mining Complexes. In the transaction, the buyer
acquired the Miller Creek and Fola assets and assumed the Miller Creek and Fola mine closing and reclamation liabilities. In order
to equalize the value exchange, CNX paid $28,271 of cash at closing, which included property taxes associated with the properties
sold and other closing costs. This amount was included in Net Cash (Used in) Provided by Discontinued Investing Activities in
the Consolidated Statements of Cash Flows for the year ended December 31, 2016. CNX will also pay a total of $12,291 in
remaining installments through January 2020. The net loss on the sale of $53,130, excluding the related impairment charge discussed
below, was included in Income (Loss) from Discontinued Operations, net in the Consolidated Statements of Income. Prior to the
closing, the Miller Creek and Fola Mining Complexes were classified as held for sale in discontinued operations and in accordance
with the accounting guidance for Property, Plant and Equipment, assets held for sale are required to be measured at the lower of
carrying value or fair value less costs to sell. Upon meeting the assets held for sale criteria, the Company determined the carrying
value of the Miller Creek and Fola Mining Complexes exceeded the fair value less costs to sell. As a result, an impairment charge
96
of $355,681 was recorded during the year ended December 31, 2016. This impairment was included in Income (Loss) from
Discontinued Operations, net in the Consolidated Statements of Income.
In March 2016, CNX completed the sale of its membership interests in CONSOL Buchanan Mining Company, LLC ("BMC"),
which owned and operated the Buchanan Mine located in Mavisdale, Virginia; various assets relating to the Amonate Mining
Complex located in Amonate, Virginia; Russell County, Virginia coal reserves and Pangburn Shaner Fallowfield coal reserves
located in Southwestern, Pennsylvania to Coronado IV LLC ("Coronado"). Various CNX assets were excluded from the sale
including coalbed methane, natural gas and minerals other than coal, current assets of BMC, certain coal seams and certain surface
rights and properties. Coronado assumed only specified liabilities and various CNX liabilities were excluded and not assumed.
The excluded liabilities included BMC’s indebtedness, trade payables and liabilities arising prior to closing, as well as the liabilities
of the subsidiaries other than BMC which were parties to the sale. In addition, the buyer agreed to pay CNX for Buchanan Mine
coal sold outside the U.S. and Canada during the five years following closing a royalty of 20% of any excess of the gross sales
price per ton over the following amounts: (1) year one, $75.00 per ton; (2) year two, $78.75 per ton; (3) year three, $82.69 per
ton; (4) year four, $86.82 per ton; (5) year five, $91.16 per ton. Total gross royalty income recognized under this agreement was
$16,244, $10,073 and $9,575 for the years ended December 31, 2018, 2017 and 2016, respectively. In connection with the separation
and distribution agreement with CONSOL Energy (See Note 25 - Related Party) the royalty related to Buchanan Mine was retained
by CNX and any related income is included in Other (Income) Expense in the Consolidated Statements of Income. Cash proceeds
of $402,799 were received at closing and are included in Net Cash (Used in) Provided by Discontinued Investing Activities on
the Consolidated Statements of Cash Flows for the year ended December 31, 2016. The net loss on the sale was $38,364 and was
included in Income (Loss) from Discontinued Operations, net in the Consolidated Statements of Income for the year ended
December 31, 2016.
For all periods presented in the accompanying Consolidated Statements of Income, BMC along with the various other assets
and the Miller Creek and Fola Mining Complexes are classified as discontinued operations.
The following table details selected financial information for the divested business included within discontinued operations:
For the Years Ended
December 31,
Coal Revenue
Other Outside Sales
Freight-Outside Coal
Miscellaneous Other Income
Gain on Sale of Assets
Total Revenue and Other Income
Total Costs
Income (Loss) From Operations Before Income Taxes
Impairment on Assets Held for Sale
Income Tax Expense (Benefit)
Less: Net Income Attributable to Noncontrolling interest
Income (Loss) From Discontinued Operations, net
NOTE 6—ACQUISITIONS AND DISPOSITIONS:
2017
$ 1,067,841
60,066
66,297
73,645
—
$ 1,267,849
1,147,254
120,595
—
23,984
10,903
85,708
$
$
2016
$ 1,168,486
31,464
47,790
74,382
269,124
$ 1,591,246
1,652,921
(61,675)
355,681
(129,153)
8,954
$ (297,157)
$
On December 14, 2017, CNX Gas entered into a purchase agreement with Noble, pursuant to which CNX Gas acquired
Noble’s 50% membership interest in CONE Gathering LLC ("CNX Gathering"), for a cash purchase price of $305,000 and the
mutual release of all outstanding claims (the "Midstream Acquisition"). CNX Gathering owns a 100% membership interest in
CONE Midstream GP LLC (the "general partner"), which is the general partner of CONE Midstream Partners LP ("CNXM" or
the "Partnership"), which is a publicly traded master limited partnership formed in May 2014 by CNX Gas and Noble. In conjunction
with the Midstream Acquisition, which closed on January 3, 2018, the general partner, CNXM and CONE Gathering LLC changed
their names to CNX Midstream GP LLC, CNX Midstream Partners LP, and CNX Gathering LLC, respectively.
Prior to the Midstream Acquisition, the Company accounted for its 50% interest in CNX Gathering LLC as an equity method
investment as the Company had the ability to exercise significant influence, but not control, over the operating and financial
policies of the midstream operations. In conjunction with the Midstream Acquisition, the Company obtained a controlling interest
in CNX Gathering LLC and, through CNX Gathering's ownership of the general partner, control over CNXM. Accordingly, the
Midstream Acquisition has been accounted for as a business combination using the acquisition method of accounting pursuant to
97
ASC Topic 805, Business Combinations, or ASC 805. ASC 805 requires that, in circumstances where a business combination is
achieved in stages (or step acquisition), previously held equity interests are remeasured at fair value and any difference between
the fair value and the carrying value of the equity interest held be recognized as a gain or loss on the statement of income.
The fair value assigned to the previously held equity interest in CNX Gathering and CNXM for purposes of calculating the
gain or loss was $799,033 and was determined using the income approach, based on a discounted cash flow methodology. The
resulting gain on remeasurement to fair value of the previously held equity interest in CNX Gathering and CNXM of $623,663 is
included in Gain on Previously Held Equity Interest in the Consolidated Statements of Income.
The fair value of the previously held equity interests was based on inputs that are not observable in the market and therefore
represent Level 3 inputs (See Note 20 - Fair Value of Financial Instruments). The fair value was measured using valuation techniques
that convert future cash flows into a single discounted amount. Significant inputs to the valuation included estimates of: (i) gathering
volumes; (ii) future operating costs; and (iii) a market-based weighted average cost of capital. These inputs required significant
judgments and estimates by management.
The fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations,
were estimated using the cost approach. Significant unobservable inputs in the valuation include management's assumptions about
the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence
associated with the acquired assets. As a result, the fair value estimates of the midstream facilities and equipment represents a
Level 3 fair value measurement.
As part of the purchase price allocation, the Company identified intangible assets for customer relationships with third-party
customers. The fair value of the identified intangible assets was determined using the income approach, which requires a forecast
of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant
unobservable inputs in the valuation include future revenue estimates, future cost assumptions, and estimated customer retention
rates. As a result, the fair value estimate of the identified intangible assets represents a Level 3 fair value measurement.
The noncontrolling interest in the acquired business is comprised of the limited partner units in CNXM, which were not
acquired by the Company. The CNXM limited partner units are actively traded on the New York Stock Exchange and were valued
based on observable market prices as of the transaction date and therefore represent a Level 1 fair value measurement.
Allocation of Purchase Price (Midstream Acquisition)
The following table summarizes the purchase price and the amounts of identified assets acquired and liabilities assumed
based on the fair value as of January 3, 2018, with any excess of the purchase price over the fair value of the identified net assets
acquired recorded as goodwill. The purchase price allocation has been finalized as of December 31, 2018.
Fair Value of Consideration Transferred:
Cash Consideration
CNX Gathering Cash on Hand at January 3, 2018 Distributed to Noble
Fair Value of Previously Held Equity Interest
Total Fair Value of Consideration Transferred
$
$
305,000
2,620
799,033
1,106,653
98
The following is a summary of the fair values of the net assets acquired:
Fair Value of Assets Acquired:
Cash and Cash Equivalents
Accounts and Notes Receivable
Prepaid Expense
Other Current Assets
Property, Plant and Equipment, Net
Intangible Assets
Other
Total Assets Acquired
Fair Value of Liabilities Assumed:
Accounts Payable
CNXM Revolving Credit Facility
Total Liabilities Assumed
Total Identifiable Net Assets
Fair Value of Noncontrolling Interest in CNXM
Goodwill
Net Assets Acquired
Post-Acquisition Operating Results (Midstream Acquisition)
$
8,348
21,199
2,006
163
1,043,340
128,781
593
1,204,430
26,059
149,500
175,559
1,028,871
(718,577)
796,359
1,106,653
$
The Midstream Acquisition contributed the following to the Company's Midstream segment for the year-ended December 31,
2018.
Midstream Revenue
Earnings from Continuing Operations Before Income Tax
Unaudited Pro Forma Information (Midstream Acquisition)
December 31, 2018
258,074
$
133,811
$
The following unaudited pro forma combined financial information presents the Company’s results as though the Midstream
Acquisition had been completed at January 1, 2016. The pro forma combined financial information has been included for
comparative purposes and is not necessarily indicative of the results that might have actually occurred had the acquisition been
completed at January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.
(in thousands, except per share data) (unaudited)
$
Pro Forma Total Revenue and Other Operating Income
$
Pro Forma Net Income from Continuing Operations
$
Less: Pro Forma Net income Attributable to Noncontrolling Interests
Pro Forma Net Income(Loss) from Continuing Operations Attributable to CNX $
$
Pro Forma Income(Loss) per Share from Continuing Operations (Basic)
$
Pro Forma Income(Loss) per Share from Continuing Operations (Diluted)
For the Year Ended December 31,
2017
1,553,078
427,381 $
74,251 $
353,130 $
1.33 $
1.33 $
2016
876,987
(422,284)
62,301
(484,585)
(2.11)
(2.11)
99
On August 31, 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets in the wet gas
Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties, which included approximately 26,000 net undeveloped
acres. The net cash proceeds of $381,124 are included in Proceeds from Asset Sales on the Consolidated Statements of Cash Flows
and the net gain on the transaction of $130,710 is included in Gain on Asset Sales in the Consolidated Statements of Income.
On May 2, 2018, CNX closed on an Asset Exchange Agreement (the “AEA”), with HG Energy II Appalachia, LLC (“HG
Energy”), pursuant to which, among other things, (i) HG Energy paid approximately $7,000 to CNX and assigned to CNX certain
undeveloped Marcellus and Utica acreage in Southwest Pennsylvania, and (ii) CNX assigned its interest in certain non-core
midstream assets and surface acreage to HG Energy and released certain HG Energy oil and gas acreage from dedication under a
gathering agreement that is partially held, indirectly, by CNX. In connection with the transaction, CNX also agreed to certain
transactions with CNXM, including the amendment of the existing gas gathering agreement between CNX and CNXM to increase
the existing well commitment by an additional forty wells. The net gain on the sale was $286 and is included in Gain on Asset
Sales in the Consolidated Statements of Income.
As a result of the AEA, CNX determined that the carrying value of a portion of the customer relationship intangible assets
that were acquired in connection with the Midstream Acquisition (see also Note 11 - Goodwill and Other Intangible Assets)
exceeded their fair value, and recognized an impairment of approximately $18,650, which is included in Impairment of Other
Intangible Assets in the Consolidated Statements of Income.
On March 30, 2018, CNX Gas completed the sale of substantially all of its shallow oil and gas assets and certain Coalbed
Methane (CBM) assets in Pennsylvania and West Virginia for $89,921 in cash consideration. In connection with the sale, the buyer
assumed approximately $196,514 of asset retirement obligations. The net gain on the sale was $4,227 and is included in Gain on
Asset Sales in the Consolidated Statements of Income.
In September 2017, CNX closed on the sale of approximately 22,000 acres of surface land in Colorado. CNX received
net cash proceeds of $23,703 which is included in cash flows from investing activities. The net gain on the sale was $18,758 and
was included in Gain on Sale of Assets in the Consolidated Statements of Income.
In a two-part closing in July and September 2017, CNX executed the sale of approximately 7,500 net undeveloped acres
of the Marcellus Shale in Allegheny and Westmoreland counties, Pennsylvania. CNX received total cash proceeds of $36,649
which is included in cash flows from investing activities. The net gain on the sale of these assets was $15,251 and was included
in Gain on Sale of Assets in the Consolidated Statements of Income.
In June 2017, CNX closed on the sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale
in Allegheny, Washington, and Westmoreland counties, Pennsylvania. CNX received total cash proceeds of $83,500 which is
included in cash flows from investing activities. The net gain on the sale of these assets was $58,541 and was included in Gain on
Sale of Assets in the Consolidated Statements of Income.
In June 2017, the Company finalized the sale of 12 producing wells, 15 drilled but uncompleted wells (DUCs), and
approximately 11,000 net developed and undeveloped Marcellus and Utica acres in Doddridge and Wetzel counties in West Virginia
that were previously classified as held for sale. CNX received total cash proceeds of $125,507 which is included in cash flows
from investing activities, as well as undeveloped acreage. The net loss on the sale was $9,430 and was included in Gain on Sale
of Assets in the Consolidated Statements of Income.
In May 2017, CNX finalized the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in
Jefferson, Belmont and Guernsey counties, Ohio that were previously classified as held for sale. CNX received total cash proceeds
of $76,585 which is included in cash flows from investing activities. The net gain on the sale of these assets was $72,346 and was
included in Gain on Sale of Assets in the Consolidated Statements of Income.
In April 2017, CNX finalized the sale of its Knox Energy LLC and Coalfield Pipeline Company subsidiaries that were
previously classified as held for sale. At closing, CNX received net cash proceeds of $19,055 which is included in cash flows from
investing activities. The net gain on the sale of these assets was $606 and was included in the Gain on Sale of Assets in the
Consolidated Statements of Income. In February 2017, Knox met all of the criteria to be classified as held for sale. As part of the
required evaluation under the held for sale guidance, during the first quarter, Knox’s book value was evaluated, and it was determined
that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The
resulting impairment of $137,865 was included in Impairment of Exploration and Production Properties in the Consolidated
Statements of Income during the year ended December 31, 2017.
100
NOTE 7— STOCK REPURCHASE:
In September 2017, CNX's Board of Directors approved a one-year stock repurchase program of up to $200,000. On October
30, 2017, the Board approved an increase to the aggregate amount of the repurchase plan to $450,000. On July 30, 2018, the Board
approved the extension of the stock repurchase program through December 31, 2018. On October 26, 2018, the Company's Board
of Directors approved an additional $300,000 share repurchase authorization, which is not subject to an expiration date. The
repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1
plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing
of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's
financial outlook, and alternative investment options. The stock repurchase program does not obligate the Company to repurchase
any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any
time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow
position, leverage ratio, and capital plans. During the year ended December 31, 2018, 25,894,324 shares were repurchased and
retired at an average price of $14.80 per share for a total cost of $383,752.
NOTE 8—INCOME TAXES:
Income tax expense (benefit) provided on earnings from continuing operations consisted of:
Current:
U.S. Federal
U.S. State
Deferred:
U.S. Federal
U.S. State
For the Years Ended December 31,
2016
2017
2018
$
(130,003) $
—
(130,003)
319,813
25,747
345,560
(31,791) $
(1,838)
(33,629)
(101,596)
(8,699)
(110,295)
(166,112)
23,283
(142,829)
80,207
(4,315)
75,892
Total Income Tax Expense (Benefit)
$
215,557
$
(176,458) $
(34,403)
101
The components of the net deferred taxes are as follows:
Deferred Tax Assets:
Alternative Minimum Tax
Net Operating Loss - Federal
Net Operating Loss - State
Foreign Tax Credit
Interest Limitation
Equity Compensation
Gas Well Closing
Salary Retirement
Capital Lease
Other
Total Deferred Tax Assets
Valuation Allowance
Net Deferred Tax Assets
Deferred Tax Liabilities:
Property, Plant and Equipment
Investment in Partnership
Gas Derivatives
Advance Gas Royalties
Other
Total Deferred Tax Liabilities
$
December 31,
2018
2017
$
102,482
124,341
110,339
43,194
32,147
13,096
10,140
9,434
1,624
13,714
460,511
(94,455)
366,056
(606,342)
(125,253)
(26,160)
(3,384)
(3,599)
(764,738)
188,080
99,524
107,756
44,402
—
21,866
55,486
9,404
2,020
11,831
540,369
(136,576)
403,793
(424,204)
(1,251)
(15,248)
(3,648)
(3,815)
(448,166)
Net Deferred Tax Liability
$
(398,682) $
(44,373)
Deferred taxes are recorded for certain tax benefits, including net operating losses and tax credit carry-forwards, if management
assesses the utilization of those assets to be more likely than not. A valuation allowance is required when it is not more likely than
not that all or a portion of a deferred tax asset will be realized. All available evidence, both positive and negative, must be considered
in determining the need for a valuation allowance. For the years ended December 31, 2018 and 2017, positive evidence considered
included financial earnings generated over the past three years for certain subsidiaries, reversals of financial to tax temporary
differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence includes financial
and tax losses generated in prior periods and the inability to achieve forecasted results for those periods.
As of December 31, 2018, the Company has a deferred tax asset related to federal net operating losses of $124,341, which
expire at various times between 2034 and 2037. However, because of the Tax Cuts and Jobs Act (the “Act”) enacted on December
22, 2017, the anticipated federal net operating loss generated in 2018 does not expire but may only offset 80% of taxable income
in any given year. In connection with the restructuring and separation of the Company's coal business in November 2017, certain
net operating loss (NOL) carry-forwards were required to be written off. As of December 31, 2017, the Company had written off
the deferred tax assets associated with these net operating losses of $24,942 (Gross NOL of $71,263 at 35%). The net limited
NOLs after carrybacks of 2016 and 2017 NOLs and return to provision adjustment is $6,714 (Gross NOL $31,969 at 21%).
The Act preserved the deductibility of intangible drilling costs for federal income tax purposes, which allows the Company
to deduct a portion of drilling costs in the year incurred and minimizes current year taxes payable in periods of taxable income.
The Act also repealed the corporate alternative minimum tax (AMT) for tax years beginning January 1, 2018 and provides that
existing AMT credits can be utilized to offset current federal taxes owed in tax years 2018 through 2020. In addition, 50% of any
unused AMT credits are refundable during these years with any remaining AMT credit carryforward being fully refunded in 2021.
It is now more likely than not that the benefit of CNX's AMT credits will be realized and as a result the Company has reclassified
$102,482 from Deferred Income Taxes to Recoverable Income Taxes on the Consolidated Balance Sheets in anticipation of the
AMT refund to be received in 2019. As of December 31, 2018, the Company has a deferred tax asset relating to federal AMT
credits of $102,482, a decrease of $85,598 from the prior year that resulted from the anticipated refund of the AMT credits, and
certain increases in the AMT due to positions taken on the 2017 federal income tax return and the carryback of prior year NOLS.
102
During 2018, the valuation allowance relating to federal AMT credits decreased by $12,413 as the Internal Revenue Service (IRS)
has announced that refunds of AMT credits are no longer subject to government sequestration.
A valuation allowance on foreign tax credits of $43,194 and $44,402 has also been recorded at December 31, 2018 and 2017,
respectively. The foreign tax credits expire at various times between 2021 and 2023. There was no valuation allowance on deferred
equity compensation for covered individuals as provided by Section 162(m) as of December 31, 2018. A valuation allowance on
deferred equity compensation of $5,957 was recorded as of December 31, 2017. A valuation allowance on charitable contribution
carry-forwards of $3,297 and $3,156 has been recorded as of December 31, 2018 and 2017, respectively. The Company's charitable
contributions carry-forwards expire at various times between 2019 and 2022.
CNX continues to report, on an after federal tax basis, a deferred tax asset related to state operating losses of $110,339 with
a related valuation allowance of $47,964 at December 31, 2018. The deferred tax asset related to state operating losses, on an after
tax adjusted basis, was $107,756 with a related valuation allowance of $61,560 at December 31, 2017. A review of positive and
negative evidence regarding these state tax benefits concluded that the valuation allowances for various CNX subsidiaries was
warranted. These NOLs expire at various times between 2019 and 2038.
The deferred tax assets attributable to the state tax effect of future deductible temporary differences for certain CNX
subsidiaries with histories of financial and tax losses were also reviewed for positive and negative evidence regarding the realization
of the associated deferred tax assets. There was no valuation allowance recorded at December 31, 2018. A valuation allowance of
$9,088 on an after federal tax adjusted basis was recorded at December 31, 2017.
Management will continue to assess the potential for realized deferred tax assets based upon income forecast data and the
feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future
periods, as appropriate, that could materially impact net income.
The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax
rate to CNX's effective tax rate:
2018
For the Years Ended December 31,
2017
2016
Statutory U.S. federal income tax rate
Net Effect of state income taxes
Non-controlling Interest
Uncertain tax positions
Effect of spin on Federal NOL's
Accrual to tax return reconciliation
IRS and state tax examination settlements
Effect of change in state valuation allowance
Effect of change in federal valuation allowance
Other deferred adjustments
Effect of federal and state rate reductions
Effect of federal tax credits
Other
Income Tax Expense (Benefit) / Effective Rate
Amount
$ 230,721
60,814
(18,181)
(4,265)
—
3,028
—
(22,684)
(18,110)
5,957
(27,429)
1,208
4,498
$ 215,557
Percent
Amount
41,503
21.0% $
5.6
(1.7)
(0.4)
—
15,538
—
27,359
0.3
24,942
(1,147)
—
—
(430)
(2.1)
(145,772)
(1.7)
7,616
0.6
(131,784)
(2.5)
(19,081)
0.1
0.4
4,798
19.6% $ (176,458)
Percent
Amount
Percent
35.0 % $ (204,872)
(20,954)
13.1
—
—
23.1
21.0
(1.0)
—
(0.4)
1,351
—
(4,564)
(13,463)
18,999
(122.9)
6.4
(111.1)
(16.1)
4.0
184,227
—
—
—
4,873
(148.9)% $ (34,403)
35.0%
3.6
—
(0.2)
—
0.8
2.3
(3.2)
(31.5)
—
—
—
(0.8)
6.0%
Under the provisions of Staff Accounting Bulletin 118 (SAB 118), as of December 31, 2017, we had not completed our
accounting for all of the enactment-date income tax effects of the Act under ASC 740, Income Taxes, for the remeasurement of
deferred tax assets and liabilities. As of December 31, 2018, we have now completed our accounting for all of the enactment-date
income tax effects of the Act.
As a result of the Midstream Acquisition on January 3, 2018 as discussed in Note 6 - Acquisitions and Dispositions, the
Company obtained a controlling interest in CNX Gathering LLC and, through CNX Gathering's ownership of the general partner,
control over CNXM. The financial results for 2018 reflect full consolidation of CNXM’s assets and liabilities. The effective tax
103
rate for the year ended December 31, 2018 reflects a $18,181 reduction in income tax expense due to the non-controlling interest
in CNXM’s earnings.
The Act, which, among other things, lowered the U.S. Federal corporate income tax rate from 35% to 21%, repealed the
corporate AMT for tax years beginning January 1, 2018, and provided for a refund of previously accrued AMT credits. As discussed
above, CNX has credits that are expected to be refunded between 2019 and 2021 because of the Act and monetization opportunities
under current law in 2018. The Company recorded a net tax benefit to reflect the impact of the Act as of December 31, 2017, as
it is required to reflect the change in the period in which the law is enacted. Largely, the benefits recorded in the period ending
December 31, 2017 related to the Act are in recognition of the revaluation of deferred tax assets and liabilities, a benefit of $115,291.
The Company's effective tax rate for 2018 and 2017 reflects the release of previously recorded valuation allowances against AMT
credit carry-forwards of $12,413 and $154,385, respectively, as those credits will now be able to be monetized under the Act and,
according to an IRS announcement, are no longer subject to government sequestration.
The effective tax rate for the year ended December 31, 2018 was lower than the U.S. federal statutory rate primarily due to
the effect of the filing of a Federal NOL carryback for 2017 and 2016 resulting in a financial statement benefit of $23,483 through
the realization of the Federal NOLs at a 35% tax rate as a carryback versus the current 21% tax rate as a carryforward, the reversal
of the AMT credit sequestration valuation allowance, and the release of certain state valuation allowances as a result of a corporate
reorganization during the year. The federal NOL carryback claims for 2016 and 2017 are under review by the IRS.
The Act is also a comprehensive tax reform bill containing a number of other provisions that either currently or in the future
could impact CNX. The effect of certain limitations effective for the tax year 2018 and forward, specifically related to the
deductibility of executive compensation, have been evaluated. The Company anticipates U.S. regulatory agencies will issue further
regulations which may alter this estimate. The IRS issued rules during the year pertaining to the application of limitations for
executive compensation related to contracts existing prior to November 2, 2017, and provisions in the Act addressing the
deductibility of interest expense after January 1, 2018. The Company will continue to refine its estimates to incorporate new or
better information as it comes available.
A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:
Balance at beginning of period
Increase in unrecognized tax benefits resulting from tax positions taken during current period
Increase in unrecognized tax benefits resulting from tax positions taken during prior periods
Reduction in unrecognized tax benefits because of the lapse of the applicable statute of limitations
Balance at end of period
For the Years Ended
December 31,
2018
37,813
—
2,140
(8,437)
31,516
2017
$
9,103
21,902
7,474
(666)
$ 37,813
$
$
If these unrecognized tax benefits were recognized, $31,516 and $29,376 would affect CNX's effective income tax rate for
2018 and 2017, respectively.
In 2018, CNX recognized an increase in unrecognized tax benefits of $2,140 for tax benefits resulting from a revision to our
tax position taken on our 2017 federal tax return for the marginal well credit. CNX recognized a reduction to unrecognized tax
benefits of $8,437 from a position taken on a state tax return.
CNX recognizes accrued interest related to unrecognized tax benefits in its interest expense. As of December 31, 2018, the
Company reported no accrued liability relating to uncertain tax positions in Other Liabilities on the Consolidated Balance Sheets.
As of December 31, 2017, the Company reported an accrued liability relating to uncertain tax positions of $644 in Other Liabilities
on the Consolidated Balance Sheets. The accrued interest liability includes interest income of $644 and interest expense of $337
recorded in the Company's Consolidated Statements of Income for the years ended December 31, 2018 and 2017, respectively.
During the years ended December 31, 2018 and 2017, CNX paid no interest related to income tax deficiencies.
CNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. CNX had no accrued liabilities
for tax penalties as of December 31, 2018 and 2017.
CNX and its subsidiaries file federal income tax returns with the United States and income tax returns within various states.
With few exceptions, the Company is no longer subject to United States federal, state, local or non-U.S. income tax examinations
104
by tax authorities for the years before 2016. The Joint Committee on Taxation concluded its review of the audit of tax year 2015
on March 21, 2018. The audit resulted in a $108,651 reduction to CNX’s NOL, primarily due to a reduction in the depreciation
as an offset to the bonus depreciation taken in the 2010-2013 IRS audit. There was no current cash tax impact from the audit.
NOTE 9—ASSET RETIREMENT OBLIGATIONS:
The reconciliation of changes in asset retirement obligations at December 31, 2018 and 2017 is as follows:
Balance at beginning of period
Obligations Divested (Note 6)
Accretion expense
Obligations Incurred
Obligations Settled
Revisions in estimated cash flows
Balance at end of period
NOTE 10—PROPERTY, PLANT AND EQUIPMENT:
Property, Plant and Equipment
Intangible Drilling Cost
Proved Gas Properties
Gas Gathering Equipment
Unproved Gas Properties
Gas Wells and Related Equipment
Surface Land and Other Equipment
Other Gas Assets
Total Property, Plant and Equipment
Less: Accumulated Depreciation, Depletion and Amortization
Total Property, Plant and Equipment - Net
$
As of December 31,
2017
2018
201,006
204,070
(1,960)
(196,643)
5,760
9,874
441
4,795
(6,875)
(5,323)
5,698
21,781
204,070
38,554
$
$
$
December 31,
2018
$ 4,120,283
1,135,411
2,126,895
927,667
856,973
308,297
91,902
$ 9,567,428
2,624,984
$ 6,942,444
2017
$ 3,849,689
1,999,891
1,182,234
919,733
834,120
309,602
221,226
$ 9,316,495
3,526,742
$ 5,789,753
Amounts below reflect properties where drilling operations have not yet commenced and therefore, are not being amortized
for the years ended December 31, 2018 and 2017, respectively. These assets will be amortized using the units-of-production method
and reclassified to proved gas properties when placed in service.
Unproved Gas Properties
Gas Advance Royalties
Total
December 31,
2018
2017
$
$
927,667
12,863
940,530
$
$
919,733
13,220
932,953
As of December 31, 2018 and 2017, property, plant and equipment includes a gross asset related to capital leases of $73,144
and $73,688, respectively. Included in Gas Gathering Equipment is a capital lease for the Jewell Ridge Pipeline of $66,919 at
December 31, 2018 and 2017. CNX also maintains a capital lease for vehicles of $6,225 and $6,769 at December 31, 2018 and
2017, respectively, which is included in Other Gas Assets. Accumulated amortization for capital leases was $59,517 and $54,431
at December 31, 2018 and 2017, respectively. Amortization expense for capital leases is included in Depreciation, Depletion and
Amortization in the Consolidated Statements of Income. See Note 15–Leases for further discussion of capital leases.
105
NOTE 11—GOODWILL AND OTHER INTANGIBLE ASSETS:
In connection with the Midstream Acquisition, which closed on January 3, 2018 (See Note 6 - Acquisitions and Dispositions
for more information), CNX recorded $796,359 of goodwill and $128,781 of other intangible assets which are comprised of
customer relationships.
All goodwill is attributed to the Midstream reportable segment. Changes in the carrying amount of goodwill consist of the
following activity:
December 31, 2017
Acquisitions
December 31, 2018
Amount
$
$
—
796,359
796,359
The carrying amount and accumulated amortization of other intangible assets consist of the following:
Other Intangible Assets
Customer Relationships
Less: Impairment of Other Intangible Assets
Less: Accumulated Amortization for Customer Relationships
Total Other Intangible Assets, net
December 31, 2018
$
$
128,781
(18,650)
(6,931)
103,200
In May 2018, as a result of the AEA with HG Energy (See Note 6 - Acquisition and Dispositions for more information) CNX
determined that the carrying value of a portion of the customer relationship intangible assets exceeded their fair value. Accordingly,
CNX recognized an impairment on this intangible asset of $18,650 which consisted of the entire amount that related to a component
of the Midstream business that was transferred to HG Energy, and the impairment is included in Impairment of Other Intangible
Assets in the Consolidated Statements of Income.
Amortization expense for other intangible assets was $6,931 for the year ended December 31, 2018. There was no such
expense for the years ended December 31, 2017 and December 31, 2016.
The customer relationship intangible asset is being amortized on a straight-line basis over approximately seventeen years.
The estimated annual amortization expense is expected to approximate $6,552 per year for the next five years.
NOTE 12—REVOLVING CREDIT FACILITIES:
CNX Resources Corporation (CNX)
On March 8, 2018, CNX amended and restated its senior secured revolving credit facility ("Credit Facility"), which expires
on March 8, 2023. The CNX Credit Facility increased lenders' commitments from $1,500,000 to $2,100,000 with an accordion
feature that allows the Company to increase the commitments to $3,000,000. The initial borrowing base increased from $2,000,000
to $2,500,000, and the letters of credit aggregate sub-limit remained unchanged at $650,000. Effective August 20, 2018, as part
of the semi-annual redetermination, the borrowing base was reduced to $2,100,000 primarily based on the sale of substantially
all of CNX's Ohio Utica Joint Venture Assets and shallow oil and gas assets (See Note 6 - Acquisitions and Dispositions for
additional information). The Credit Facility matures on March 8, 2023, provided that if the aggregate principal amount of our
existing 5.875% Senior Notes due in April 2022 and certain other publicly traded debt securities outstanding 91 days prior to the
earliest maturity of such debt (such date, the "Springing Maturity Date") is greater than $500,000, then the Credit Facility will
mature on the Springing Maturity Date.
The CNX Credit Facility is secured by substantially all of the assets of CNX and certain of its subsidiaries. Fees and interest
rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the Credit Facility is limited
to a borrowing base, which is determined by the lenders' syndication agent and approved by the required number of lenders in
good faith by calculating a value of CNX's proved natural gas reserves.
The CNX Credit Facility contains a number of affirmative and negative covenants that include, among others, covenants
that, except in certain circumstances, limit the Company and the subsidiary guarantors' ability to create, incur, assume or suffer
to exist indebtedness, create or permit to exist liens on properties, dispose of assets, make investments, purchase or redeem CNX
106
common stock, pay dividends, merge with another corporation and amend the senior unsecured notes. The Company must also
mortgage 80% of the value of its proved reserves and 80% of the value of its proved developed producing reserves, in each case,
which are included in the borrowing base, maintain applicable deposit, securities and commodities accounts with the lenders or
affiliates thereof, and enter into control agreements with respect to such applicable accounts.
The CNX credit facility contains customary events of default, including, but not limited to, a cross-default to certain other
debt, breaches of representations and warranties, change of control events and breaches of covenants.
The CNX Credit Facility also requires that CNX maintain a maximum net leverage ratio of no greater than 4.00 to 1.00,
which is calculated as the ratio of debt less cash on hand to consolidated EBITDA, measured quarterly. CNX must also maintain
a minimum current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability,
to current liabilities, excluding borrowings under the revolver, measured quarterly. The calculation of all of the ratios excludes
CNXM. CNX was in compliance with all financial covenants as of December 31, 2018.
At December 31, 2018, the CNX credit facility had $612,000 of borrowings outstanding and $198,396 of letters of credit
outstanding, leaving $1,289,604 of unused capacity. At December 31, 2017, the Credit Facility had no borrowings outstanding
and $239,072 letters of credit outstanding, leaving $1,260,928 of unused capacity.
CNX Midstream Partners LP (CNXM)
On March 8, 2018, CNXM entered into a new $600,000,000 senior secured revolving credit facility that matures on March
8, 2023. The CNXM credit facility replaced its prior $250,000,000 senior secured revolving credit facility.
Fees and interest rate spreads under the CNXM credit facility are based on the total leverage ratio, measured quarterly. The
CNXM credit facility includes the ability to issue letters of credit up to $100,000 in the aggregate.
The CNXM credit facility contains a number of affirmative and negative covenants that include, among others, covenants
that, except in certain circumstances, restrict the ability of CNXM, its subsidiary guarantors and certain of its non-guarantor, non-
wholly-owned subsidiaries, except in certain circumstances, to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create
or permit to exist liens on their properties; (iii) prepay certain indebtedness unless there is no default or event of default under the
facility; (iv) make or pay any dividends or distributions in excess of certain amounts; (v) merge with or into another person,
liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all
or a substantial portion of another person’s assets; (vi) make particular investments and loans; (vii) sell, transfer, convey, assign
or dispose of its assets or properties other than in the ordinary course of business and other select instances; (viii) deal with any
affiliate except in the ordinary course of business on terms no less favorable to CNXM than it would otherwise receive in an arm’s
length transaction; and (ix) amend in any material manner its certificate of incorporation, bylaws, or other organizational documents
without giving prior notice to the lenders and, in some cases, obtaining the consent of the lenders.
In addition, CNXM is obligated to maintain at the end of each fiscal quarter (x) a maximum total leverage ratio of no greater
than between 4.75 to 1.00 ranging to no greater than 5.50 to 1.00 in certain circumstances; (y) a maximum secured leverage ratio
of no greater than 3.50 to 1.00 and (z) a minimum interest coverage ratio of no less than 2.50 to 1.00. CNXM was in compliance
with all financial covenants as of December 31, 2018.
The CNXM credit facility also contains customary events of default, including, but not limited to, a cross-default to certain
other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under
the facility are secured by substantially all of the assets of CNXM and its wholly-owned subsidiaries. CNX is not a guarantor
under the facility.
At December 31, 2018, the CNXM credit facility had $84,000 of borrowings outstanding, and after giving effect to limitations
on available capacity per CNXM's revolving credit facility agreement, had borrowings available of $480,000. CNXM had
approximately $516,000 of unused capacity at December 31, 2018.
107
NOTE 13—OTHER ACCRUED LIABILITIES:
Royalties
Gas derivatives
Accrued interest
Short-term incentive compensation
Transportation charges
Deferred revenue
Accrued other taxes
Accrued payroll & benefits
Other
Current portion of long-term liabilities:
Salary retirement
Asset retirement obligations
Total Other Accrued Liabilities
NOTE 14—LONG-TERM DEBT:
Debt:
Senior Notes due April 2022 at 5.875% (Principal of $1,294,307 and $1,705,682 plus
Unamortized Premium of $2,069 and $3,544, respectively)
CNX Revolving Credit Facility
CNX Midstream Partners LP Senior Notes due March 2026 at 6.50% (Principal of
$400,000 less Unamortized Discount of $5,375 at December 31, 2018)
CNX Midstream Partners LP Revolving Credit Facility
Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount
of $4,751 at December 31, 2017)
Other Note Maturing in 2018 (Principal of $358 less Unamortized Discount of $8 at
December 31, 2017)
Less: Unamortized Debt Issuance Costs
Less: Amounts Due in One Year*
Long-Term Debt
$
December 31,
2018
2017
$
92,005
61,661
26,333
20,482
19,661
17,693
7,300
6,533
31,851
60,008
41,291
32,172
12,062
13,004
11,559
9,779
6,615
30,083
1,578
1,075
286,172
$
1,532
5,302
223,407
$
December 31,
2018
2017
$
1,296,376
$
1,709,226
612,000
394,625
84,000
—
—
8,796
2,378,205
—
2,378,205
$
$
—
—
—
495,249
350
17,536
2,187,289
263
2,187,026
*Excludes current portion of Capital Lease Obligations of $6,997 and $6,848 at December 31, 2018 and 2017, respectively.
Annual undiscounted maturities on long-term debt during the next five years and thereafter are as follows:
Year ended December 31,
2019
2020
2021
2022
2023
Thereafter
Total Long-Term Debt Maturities
Amount
—
—
—
1,294,307
696,000
400,000
2,390,307
$
$
During the year ended December 31, 2018, CNXM completed a private offering of $400,000 of 6.50% senior notes due in
March 2026 less $6,000 of unamortized bond discount. CNX is not a guarantor of CNXM's 6.50% senior notes due in March 2026
or CNXM's senior secured revolving credit facility.
108
During the year ended December 31, 2018, CNX purchased $411,375 of its outstanding 5.875% senior notes due in April
2022. As part of this transaction, a loss of $15,320 was included in Loss on Debt Extinguishment in the Consolidated Statements
of Income.
During the year ended December 31, 2018, CNX called the $500,000 balance on its 8.00% senior notes due in April 2023.
As part of this transaction, a loss of $38,798 was included in Loss on Debt Extinguishment in the Consolidated Statements of
Income.
During the year ended December 31, 2017, CNX purchased $144,318 of its outstanding 5.875% senior notes due in April
2022. As part of this transaction, a loss of $110 was included in Loss on Debt Extinguishment in the Consolidated Statements of
Income.
During the year ended December 31, 2017, CNX called the remaining $74,470 balance on its 8.25% senior notes due in
April 2020 and the remaining $20,611 balance on its 6.375% senior notes due in March 2021. As part of these transactions, a loss
of $2,019 was included in Loss on Debt Extinguishment in the Consolidated Statements of Income.
NOTE 15—LEASES:
CNX uses various leased facilities and equipment in its operations. Future minimum lease payments under capital and
operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2018 are as follows:
Year Ended December 31,
2019
2020
2021
2022
2023
Thereafter
Total minimum lease payments
Less amount representing interest (3.87% – 7.36%)
Present value of minimum lease payments
Less amount due in one year
Total long-term capital lease obligation
Capital
Leases
Operating
Leases
$
$
70,590
69,169
59,236
19,212
5,453
36,256
259,916
$
$
$
8,248
7,582
6,706
—
—
—
22,536
2,240
20,296
6,997
13,299
Rental expense under operating leases was $21,441, $16,797, and $20,772 for the years ended December 31, 2018, 2017
and 2016, respectively.
As discussed in Note 1 - Significant Accounting Policies, we have adopted the new lease accounting standard under Topic
842 on January 1, 2019. Upon adoption of this standard, our operating leases will result in ROU lease assets and corresponding
lease liabilities being recognized in the Consolidated Balance Sheet.
109
NOTE 16—PENSION:
The benefits for the Defined Contribution Restoration Plan were frozen effective July 1, 2018. Employees hired after this
date are not eligible for this benefit plan. In addition, current participants receive no further compensation credits after that date,
with the last award being 2017. Annual interest credits will continue to be made in accordance with the terms of the plan. The
freezing of the plan triggered a curtailment gain of $416.
The reconciliation of changes in the benefit obligation, plan assets and funded status of the pension benefits is as follows:
Change in benefit obligation:
Benefit obligation at beginning of period
Service cost
Interest cost
Actuarial (gain) loss
Plan curtailments
Benefits and other payments
Benefit obligation at end of period
Change in plan assets:
Fair value of plan assets at beginning of period
Company contributions
Benefits and other payments
Fair value of plan assets at end of period
Funded status:
Current liabilities
Noncurrent liabilities
Net obligation recognized
Amounts recognized in accumulated other comprehensive loss consist of:
Net actuarial loss
Prior service credit
Net amount recognized (before tax effect)
The components of the net periodic benefit cost are as follows:
December 31,
2018
2017
36,280
302
1,265
(2,645)
(126)
(1,507)
33,569
$
$
— $
1,507
(1,507)
— $
(1,578) $
(31,991)
(33,569) $
10,738
(17)
10,721
$
$
34,051
375
1,201
2,127
—
(1,474)
36,280
—
1,474
(1,474)
—
(1,532)
(34,748)
(36,280)
14,374
(626)
13,748
$
$
$
$
$
$
$
$
For the Years Ended December 31,
2017
2016
2018
Components of net periodic benefit cost:
Service cost
Interest cost
Amortization of prior service credits
Recognized net actuarial loss
Curtailment gain
Net periodic benefit cost
$
$
302
1,265
(193)
865
(416)
1,823
$
$
375
1,201
(362)
1,525
—
2,739
$
$
367
1,250
(362)
1,505
—
2,760
Amounts included in accumulated other comprehensive loss which are expected to be recognized in 2019 net periodic benefit
cost:
Prior service credit recognition
Actuarial loss recognition
Pension
Benefits
$
$
17
(239)
110
CNX utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the pension
plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO) or the
market-related value of plan assets are amortized over the expected remaining future lifetime of all plan participants for the pension
plan.
The following table provides information related to the pension plan with an accumulated benefit obligation in excess of
plan assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
Assumptions:
As of December 31,
2018
2017
$
$
$
33,569
33,169
$
$
— $
36,280
35,264
—
The weighted-average assumptions used to determine benefit obligations are as follows:
Discount rate
Rate of compensation increase
For the Year Ended
As of December 31,
2018
2017
4.37%
3.63%
3.70%
4.05%
The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance
of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to
determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as
of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the
bonds included in the models exceed the cash flows needed to satisfy the Company plans.
The weighted-average assumptions used to determine net periodic benefit cost are as follows:
Discount rate
Rate of compensation increase
Cash Flows:
For the Years ended December 31,
2018
2017
2016
4.28%
4.05%
4.26%
3.90%
4.55%
3.80%
CNX expects to pay benefits of $1,578 from the non-qualified pension plan in 2019.
The following benefit payments, which reflect expected future service, are expected to be paid:
Year ended December 31,
2019
2020
2021
2022
2023
Year 2024-2028
111
Pension
Benefits
1,578
1,669
1,749
1,838
1,927
10,813
$
$
$
$
$
$
NOTE 17—STOCK-BASED COMPENSATION:
CNX's Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors.
Amendments to the Equity Incentive Plan have been adopted and approved by the Board of Directors and the Company's
Shareholders since the commencement of the Equity Incentive Plan. Most recently, in May 2016, the Company's Shareholders
adopted and approved a 10,550,000 increase to the total number of shares available for issuance, which brought the total number
of shares of common stock that can be covered by grants in accordance with the terms of the Equity Incentive Plan, after adjustment
for the separation of the coal business from the gas business on November 28, 2017, to 48,915,944. At December 31, 2018,
6,461,878 shares of common stock remained available for grant under the plan. The Equity Incentive Plan provides that the
aggregate number of shares available for issuance will be reduced by one share for each share relating to stock options and by 2.0
and 1.62 for each share relating to Performance Share Units (PSUs) or Restricted Stock Units (RSUs), respectively. No award of
stock options may be exercised under the Equity Incentive Plan after the tenth anniversary of the grant date of the award.
For those shares expected to vest, CNX recognizes stock-based compensation costs on a straight-line basis over the requisite
service period of the award, which is generally the vesting term. Options and RSUs vest over a three-year term. PSUs granted in
2015 vested over a three-year term while PSUs granted in 2016-2018 vest over a five-year term at 20% per year subject to
performance conditions. If an employee leaves the Company, all unvested shares are forfeited. CNX recognizes forfeitures as they
occur. The vesting of all awards will accelerate in the event of death and disability and may accelerate upon a change in control
of CNX. The total stock-based compensation expense recognized relating to CNX shares during the years ended December 31,
2018, 2017 and 2016 was $18,930, $16,983 and $19,316, respectively. The related deferred tax benefit totaled $4,979, $6,114 and
$7,272, for the years ended December 31, 2018, 2017 and 2016, respectively.
As of December 31, 2018, CNX has $31,419 of unrecognized compensation cost related to all non-vested stock-based
compensation awards, which is expected to be recognized over a weighted-average period of 2.63 years. When stock options are
exercised, and restricted and performance stock unit awards become vested, the issuances are made from CNX's common stock
shares.
Pursuant to the terms of the CNX Equity Plan and the outstanding awards, in the event of certain changes in the outstanding
common stock of CNX or its capital structure, including by reason of a spin-off, the administrator of the CNX Equity Plan is
required to appropriately adjust the number, exercise price, kind of shares, performance goals or other terms and conditions of
Awards granted thereunder. In connection with the Separation, the Board of Directors of CNX has determined that it is appropriate
that the outstanding awards be equitably adjusted pursuant to the terms of the CNX Equity Plan and/or converted into awards
issued under the CONSOL Energy Inc. (CEIX) Equity Incentive Plan, such that the intrinsic value of the outstanding awards
immediately following the separation remains the same as the intrinsic value of such awards immediately prior to the Separation.
The separation resulted in a modification of the equity plans but did not have a material impact on the financial statements as of
the date of Separation (See Note 5 - Discontinued Operations for more information).
Stock Options:
CNX examined its historical pattern of option exercises in an effort to determine if there were any discernible activity patterns
based on certain employee populations. From this analysis, CNX identified two distinct employee populations and used the Black-
Scholes option pricing model to value the options for each of the employee populations. The expected term computation presented
in the table below is based upon a weighted average of the historical exercise patterns and post-vesting termination behavior of
the two populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated
yield on U.S. Treasury obligations for the expected term of the award. A combination of historical and implied volatility is used
to determine expected volatility and future stock price trends. The total fair value of options granted during the years ended
December 31, 2018 and 2017, and 2016 was $143, $353, and $19,305 respectively, based on the following assumptions and
weighted average fair values:
December 31, December 31, December 31,
2017
2018
2016
Weighted average fair value of grants
Risk-free interest rate
Expected dividend yield
Expected forfeiture rate
Expected volatility
Expected term in years
$
$
6.50
2.66%
—%
—%
52.68%
3.71
$
6.19
1.66%
—%
—%
50.85%
3.71
5.73
1.13%
0.27%
2.00%
61.09%
4.90
112
A summary of the status of stock options granted is presented below:
Outstanding at December 31, 2017
Granted
Exercised
Forfeited
Expired
Outstanding at December 31, 2018
Exercisable at December 31, 2018
Shares
6,192,315
21,924
(240,887)
(36,662)
(493,770)
5,442,920
4,529,180
Term (in
years)
Weighted
Average
Weighted Remaining Aggregate
Intrinsic
Average Contractual
Value (in
Exercise
Price
thousands)
$21.51
$15.55
$6.87
$6.87
$65.40
$18.74
$21.09
12,485
8,431
4.79
4.31
$
$
At December 31, 2018, there are 5,442,920 employee stock options outstanding under the Equity Incentive Plan. Non-
employee director stock options vest one year after the grant date. There are 457,481 stock options outstanding under these grants.
The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CNX's
closing stock price on the last trading day of the year ended December 31, 2018 and the option's exercise price, multiplied by the
number of in-the-money options) that would have been received by the option holders had all option holders exercised their options
on December 31, 2018. This amount varies based on the fair market value of CNX's stock. The total intrinsic value of options
exercised for the years ended December 31, 2018 and 2017 was $2,077 and $1,067, respectively. There were no options exercised
for the year ended December 31, 2016.
Cash received from option exercises for the years ended December 31, 2018 and 2017 was $1,714, $1,002, respectively.
There was no cash received from option exercises for the year-ended December 31, 2016. The tax impact from option exercises
totaled $569 and $205 for the years ended December 31, 2018 and 2017 respectively.
Restricted Stock Units:
Under the Equity Incentive Plan, CNX grants certain employees and non-employee directors RSU awards, which entitle the
holder to receive shares of common stock as the award vests. Non-employee director RSUs vest at the end of one year. Compensation
expense is recognized over the vesting period of the units, described above. The total fair value of RSUs granted during the years
ended December 31, 2018, 2017 and 2016 was $13,768, $14,328 and $493, respectively. The total fair value of restricted stock
units vested during the years ended December 31, 2018, 2017 and 2016 was $6,437, $12,805 and $19,095, respectively. The
following table represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share
price) at the date of grant:
Nonvested at December 31, 2017
Granted
Vested
Forfeited
Nonvested at December 31, 2018
Performance Share Units:
Number of Weighted Average
Shares
937,462
984,286
(446,759)
(47,838)
1,427,151
Grant Date Fair Value
$16.01
$13.99
$17.23
$14.31
$14.30
Under the Equity Incentive Plan, CNX grants certain employees performance share unit awards, which entitle the holder to
shares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized
over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the
FASB Accounting Standards Codification for awards with market and performance vesting conditions. The total fair value of
performance share units granted during the years ended December 31, 2018, 2017 and 2016 was $8,570, $9,789 and $24,283,
respectively. The total fair value of performance share units vested during the years ended December 31, 2018 and 2017 was
113
$7,547 and $17,646, respectively. There were no performance share units vested during the year ended December 31, 2016. The
following table represents the nonvested performance share units and their corresponding fair value (based upon the Monte Carlo
Methodology or the closing share price) on the date of grant:
Nonvested at December 31, 2017
Granted
PSUs issued as a result of 200% payout
Vested
Forfeited
Nonvested at December 31, 2018
Performance Options:
Number of Weighted Average
Shares
1,273,042
476,121
275,829
(551,657)
(128,350)
1,344,985
Grant Date Fair Value
$25.53
$18.00
$23.75
$23.75
$27.03
$19.93
Under the Equity Incentive Plan in 2010, CNX granted certain employees performance options, which entitled the holder
to shares of common stock subject to the achievement of certain performance goals. Compensation expense was recognized over
the vesting period of the options. The Black-Scholes option valuation model was used to value each tranche separately. There
have been no performance options granted since 2010. There were 927,268 performance options outstanding and exercisable at
a weighted average exercise price of $39.00 and a weighted average remaining contractual term of 1.42 years as of December 31,
2018.
NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CNX. For non-cash transactions
that relate to the separation, as well as, acquisitions and dispositions, see Note 5 - Discontinued Operations and Note - 6 Acquisitions
and Dispositions.
As of December 31, 2018, 2017 and 2016, CNX purchased goods and services related to capital projects in the amount of
$6,091, $2,379 and $5,501, respectively, which are included in accounts payable.
The following table shows cash paid (received) during the year for:
Interest (net of amounts capitalized)
Income taxes
$
$
For the Years Ended December 31,
2017
152,047
2018
$
144,756
(11,505) $ (121,773) $
2016
186,924
(18,032)
$
NOTE 19—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:
CNX markets natural gas primarily to gas wholesalers in the United States. Concentration of credit risk is summarized
below:
Gas Wholesalers
NGL, Condensate & Processing Facilities
Other
Total Accounts Receivable Trade
December 31,
2018
2017
$
$
232,638
12,595
7,191
252,424
$
$
126,387
29,841
589
156,817
As of December 31, 2018, receivables of $30,872 and $26,417 due from NJR Energy Services Company and Direct Energy
Business Marketing LLC, respectively, were included in the Gas Wholesalers balance above. As of December 31, 2017, receivables
of $19,219 due from NJR Energy Services Company were included. No other customers made up more than 10% of the total
balances.
During the year ended December 31, 2018 sales to NJR Energy Services Company were $219,472 and sales to Direct Energy
Business Marketing LLC were $184,668, each of which comprises over 10% of sales.
114
During the year ended December 31, 2017, sales to Direct Energy Business Marketing LLC were $153,565 and sales to
NJR Energy Services Company were $147,595, which comprised over 10% of the Company's revenues.
During the year ended December 31, 2016, sales to NJR Energy Services Company were $106,280, which comprised over
10% of the Company's revenues.
NOTE 20—FAIR VALUE OF FINANCIAL INSTRUMENTS:
CNX determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or
paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly
transaction between market participants. The fair values are based on assumptions that market participants would use when pricing
an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations.
The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs
reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based discount rates and basis
forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use.
The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:
Level One - Quoted prices for identical instruments in active markets.
Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach
models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward
curves.
Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity.
In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy,
the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value
hierarchy.
The financial instrument measured at fair value on a recurring basis is summarized below:
Description
Gas Derivatives
Put Option
Fair Value Measurements at
December 31, 2018
Level 2
Level 1
Level 3
Fair Value Measurements at
December 31, 2017
Level 2
Level 1
Level 3
$
$
— $
— $
99,456
$
— $
— $
— $
— $
— $
59,949
$
(3,500) $
—
—
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
Cash and Cash Equivalents
Long-Term Debt (Excluding Debt Issuance Costs)
December 31, 2018
December 31, 2017
Carrying
Amount
Fair
Value
Carrying
Amount
$
17,198
$ 2,387,001
$
17,198
$ 2,290,537
$
509,167
$ 2,204,825
Fair
Value
$
509,167
$ 2,281,282
Cash and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s
debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s
debt obligations that is not actively traded is valued through reference to the applicable underlying benchmark rate and, as a result,
constitute Level 2 fair value measurements.
115
NOTE 21—DERIVATIVE INSTRUMENTS:
CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. These natural gas
and NGL commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period
earnings.
CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties
is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.
None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions.
However, as stated in the counterparty master agreements, if CNX's obligations with one of its counterparties cease to be secured
on the same basis as similar obligations with the other lenders under the credit facility, CNX would have to post collateral for
instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master
netting arrangements with its counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at
fair value in the Consolidated Balance Sheets on a gross basis.
Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination
of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge
positions.
The total notional amounts of production of CNX's derivative instruments at December 31, 2018 and December 31, 2017
were as follows:
Natural Gas Commodity Swaps (Bcf)
Natural Gas Basis Swaps (Bcf)
December 31,
2018
2017
1,484.4
1,056.6
1,067.2
688.1
Forecasted to
Settle Through
2023
2023
The gross fair value of CNX's derivative instruments at December 31, 2018 and December 31, 2017 was as follows:
Asset Derivative Instruments
Liability Derivative Instruments
December 31,
2018
2017
Commodity Swaps:
Prepaid Expense
Other Assets
Total Asset
Basis Only Swaps:
Prepaid Expense
Other Assets
Total Asset
$
$
$
$
28,612
164,310
192,922
11,628
48,788
60,416
$
$
$
$
62,369 Other Accrued Liabilities
59,281 Other Liabilities
121,650 Total Liability
14,965 Other Accrued Liabilities
24,223 Other Liabilities
39,188 Total Liability
December 31,
2018
2017
$
$
$
$
34,640
52,011
86,651
27,021
40,210
67,231
$
$
$
$
5,985
42,419
48,404
35,306
17,179
52,485
116
The effect of derivative instruments on the Company's Consolidated Statements of Income was as follows:
Cash (Paid) Received in Settlement of Commodity Derivative Instruments:
Commodity Swaps:
Natural Gas
Propane
Natural Gas Basis Swaps
Total Cash (Paid) Received in Settlement of Commodity Derivative Instruments
$
(41,098) $
—
(28,622)
(69,720)
(34,928) $
(1,216)
(5,030)
(41,174)
225,797
(650)
20,065
245,212
For the Years Ended December 31,
2016
2017
2018
Unrealized Gain (Loss) on Commodity Derivative Instruments:
Commodity Swaps:
Natural Gas
Propane
Natural Gas Basis Swaps
Reclassified from Accumulated OCI
Total Unrealized Gain (Loss) on Commodity Derivative Instruments
(Loss) Gain on Commodity Derivative Instruments:
Commodity Swaps:
Natural Gas
Propane
Natural Gas Basis Swaps
Reclassified from Accumulated OCI
Total (Loss) Gain on Commodity Derivative Instruments
33,026
—
6,482
—
39,508
319,605
1,147
(72,648)
—
248,104
(520,170)
(1,148)
66,604
68,481
(386,233)
$
$
(8,072) $
—
(22,140)
—
(30,212) $
284,677
(69)
(77,678)
—
206,930
$
$
(294,373)
(1,798)
86,669
68,481
(141,021)
Changes in Accumulated OCI, net of tax, attributable to cash flow hedges that were de-designated December 31, 2014
were as follows:
Beginning Balance – Accumulated OCI
Gain Reclassified from Accumulated OCI (Net of tax: $25,011)
Ending Balance – Accumulated OCI
For the Year Ended
December 31, 2016
43,470
$
(43,470)
—
$
The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These
physical commodity contracts qualify for the normal purchases and sales exception and are not subject to derivative instrument
accounting.
NOTE 22—COMMITMENTS AND CONTINGENT LIABILITIES:
CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, royalty
accounting, damage to property, climate change, governmental regulations including environmental violations and remediation,
employment and contract disputes and other claims and actions arising out of the normal course of business. CNX accrues the
estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated
accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of
operations or cash flows of CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could
ultimately be material to the financial position, results of operations or cash flows of CNX; however, such amounts cannot be
reasonably estimated.
At December 31, 2018, CNX has provided the following financial guarantees, unconditional purchase obligations, operating
lease obligations and letters of credit to certain third-parties as described by major category in the following tables. These amounts
represent the maximum potential of total future payments that the Company could be required to make under these instruments.
These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries
under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to
117
these unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management
believes that these commitments will expire without being funded, and therefore will not have a material adverse effect on financial
condition.
Letters of Credit:
Firm Transportation
Other
Total Letters of Credit
Surety Bonds:
Employee-Related
Environmental
Financial Guarantees
Other
Total Surety Bonds
Amount of Commitment Expiration Per Period
Total
Amounts
Committed
Less Than
1 Year
1-3 Years
3-5 Years
Beyond
5 Years
$
$
198,131
265
198,396
$
191,071
—
191,071
1,850
11,136
57,330
10,034
80,350
1,850
10,876
57,330
8,774
78,830
$
7,060
265
7,325
—
260
—
1,260
1,520
— $
—
—
—
—
—
—
—
Total Commitments
$
278,746
$
269,901
$
8,845
$
— $
—
—
—
—
—
—
—
—
—
Excluded from the above table are commitments and guarantees that relate to discontinued operations, entered into in
conjunction with the spin-off of the Company's coal business (See Note 5 - Discontinued Operations). Although CONSOL Energy
has agreed to indemnify us to the extent that we are called upon to pay any of these liabilities, there is no assurance that CONSOL
Energy will satisfy its obligations to indemnify us in these situations.
CNX uses various leased facilities and equipment in its operations. Future minimum lease payments under operating leases
at December 31, 2018 are as follows:
Operating Lease Obligations Due
Less than 1 year
1 - 3 years
3 - 5 years
More than 5 years
Total Operating Lease Obligations
Amount
70,590
128,405
24,665
36,256
259,916
$
$
CNX enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm
transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded in the
Consolidated Balance Sheets. As of December 31, 2018, the purchase obligations for each of the next five years and beyond were
as follows:
Obligations Due
Less than 1 year
1 - 3 years
3 - 5 years
More than 5 years
Total Purchase Obligations
Amount
220,388
408,079
358,820
1,034,145
2,021,432
$
$
NOTE 23—VARIABLE INTEREST ENTITIES:
The Company determined CNXM, of which the Company owns an approximately 34% limited partner interest, to be a
variable interest entity. Upon completion of the Midstream Acquisition (see Note 6 - Acquisitions and Dispositions), the Company
has the power through the Company's ownership and control of CNXM's general partner (CNX Midstream GP LLC) to direct the
activities that most significantly impact CNXM's economic performance. In addition, through its limited partner interest and
incentive distribution rights, or IDRs, in CNXM, the Company has the obligation to absorb the losses of CNXM and the right to
118
receive benefits in accordance with such interests. As the Company has a controlling financial interest and is the primary beneficiary
of CNXM, the Company consolidates CNXM commencing January 3, 2018.
The risks associated with the operations of CNXM are discussed in its Annual Report on Form 10-K for the year ended
December 31, 2017 filed with the SEC on February 7, 2018.
The following table presents amounts included in the Company's Consolidated Balance Sheet that were for the use or
obligation of CNXM as of December 31, 2018:
Assets:
Cash
Receivables - Related Party
Receivables - Third Party
Other Current Assets
Property, Plant and Equipment, net
Other Assets
Total Assets
Liabilities:
Accounts Payable
Accounts Payable - Related Party
Revolving Credit Facility
Long-Term Debt
Total Liabilities
December 31, 2018
$
$
$
$
3,966
17,073
7,028
2,383
891,775
3,203
925,428
43,919
4,980
84,000
393,215
526,114
The following table summarizes CNXM's Consolidated Statements of Operations and Cash Flows for the year ended
December 31, 2018, inclusive of affiliate amounts:
Revenue
Gathering Revenue - Related Party
Gathering Revenue - Third Party
Total Revenue
Expenses
Operating Expense - Related Party
Operating Expense - Third Party
General and Administrative Expense - Related Party
General and Administrative Expense - Third Party
Loss on Asset Sales
Depreciation Expense
Interest Expense
Total Expense
Net Income
Net Cash Provided by Operating Activities
Net Cash Used in Investing Activities
Net Cash Used in Financing Activities
For the Year Ended
December 31, 2018
$
$
$
$
$
167,048
89,620
256,668
19,814
27,343
13,867
8,595
2,501
21,939
23,614
117,673
138,995
180,115
(138,869)
(40,474)
Prior to the acquisition of Noble's interest on January 3, 2018, CNX accounted for its interests in CNX Gathering and CNXM
as an equity-method investment.
The following is a summary of the Company's Investment in Affiliates balances included within the Consolidated Balance
Sheets associated with CNX Gathering and CNXM, respectively:
119
Balance at December 31, 2016
Equity in Earnings
Distributions
Asset Transfer
Balance at December 31, 2017
CNX Gathering
CNXM
Total
$
$
151,075
9,823
(17,254)
(2,527)
141,117
$
$
18,133
38,523
(24,929)
2,527
34,254
$
$
169,208
48,346
(42,183)
—
175,371
The following transactions were included in Other Operating Income and Transportation, Gathering and Compression within
the Consolidated Statements of Income:
Other Operating Income:
Equity in Earnings of Affiliates - CNX Gathering
Equity in Earnings of Affiliates - CNXM
Transportation, Gathering and Compression:
Gathering Services - CNX Gathering
Gathering Services - CNXM
For the Year Ended For the Year Ended
December 31, 2017 December 31, 2016
$
$
$
$
9,823 $
38,523 $
17,112
31,148
914 $
136,068 $
706
122,256
At December 31, 2017, CNX had a net payable of $9,982 respectively due to CNX Gathering and CNXM, primarily
for accrued but unpaid gathering services.
NOTE 24—SEGMENT INFORMATION:
CNX consists of two principal business divisions: Exploration and Production (E&P) and Midstream. The principal activity
of the E&P Division, which includes four reportable segments, is to produce pipeline quality natural gas for sale primarily to gas
wholesalers. The E&P Division's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas. The
Other Gas Segment is primarily related to shallow oil and gas production which is no longer significant to the Company due to
CNX selling substantially all of these assets in the 2018 period (See Note 6 - Acquisitions and Dispositions for more information).
It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration
and production related other costs, impairment of exploration and production properties, as well as various other operating activities
assigned to the E&P Division but not allocated to each individual segment.
CNX's Midstream Division is the result of CNX's acquisition of Noble's Midstream, LLC's interest in CNX Gathering (See
Note 6 - Acquisitions and Dispositions). As part of the acquisition, CNX now has a controlling financial interest and is the primary
beneficiary of CNXM through its approximately 34% ownership of the outstanding limited partner interests (See Note 23 - Variable
Interest Entities for more information). The principal activity of the Midstream Division is the ownership, operation, development
and acquisition of natural gas gathering and other midstream energy assets, of CNX Gathering and CNXM, which provide natural
gas gathering services for the Company's produced gas, as well as for other independent third parties in the Marcellus Shale and
Utica Shale in Pennsylvania and West Virginia. Excluded from the Midstream Division are the gathering assets and operations of
CNX that have not been contributed to CNX Gathering and CNXM. Prior to acquisition, the Company accounted for its 50%
interest in CNX Gathering LLC as an equity method investment and was included in the E&P Division.
The Company's unallocated expenses include other expense, gain on asset sales related to non-core assets, gain on previously
held equity interest, loss on debt extinguishment, impairment of other intangible assets and income taxes.
In the preparation of the following information, intersegment sales have been recorded at amounts approximating market
prices. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are
reflected at the division level for E&P and are not allocated between each individual E&P segment. These assets are not allocated
to each individual segment due to the diverse asset base controlled by CNX, whereby each individual asset may service more than
one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by
segment basis.
120
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Reconciliation of Segment Information to Consolidated Amounts:
Revenue and Other Operating Income:
Total Segment Revenue from Contracts with External Customers
$
(Loss) Gain on Commodity Derivative Instruments
Other Operating Income
For the Years Ended December 31,
2018
1,733,704
(30,212)
26,942
2017
2016
$
1,179,019
$
206,930
69,182
836,504
(141,021)
64,485
Total Consolidated Revenue and Other Operating Income
$
1,730,434
$
1,455,131
$
759,968
For the Years Ended December 31,
2017
2016
2018
$
244,616
133,811
$
(63,527) $
—
(594,394)
—
378,427
(63,527)
(594,394)
14,571
154,775
623,663
(54,118)
(18,650)
1,098,668
(3,826)
188,063
—
(2,129)
—
118,581
$
(5,224)
14,270
—
—
—
(585,348)
December 31,
2018
2017
6,518,597
1,919,117
(12,223)
17,198
149,481
8,592,170
$
$
6,391,223
—
—
509,167
31,523
6,931,913
$
$
$
Income (Loss) From Continuing Operations Before Income Tax:
Segment Income (Loss) Before Income Taxes for Reportable Business
Segments:
Total E&P
Midstream
Total Segment Income (Loss) Before Income Taxes for Reportable
Business Segments
Unallocated Expenses:
Other Income (Expense)
Gain on Certain Asset Sales
Gain on Previously Held Equity Interest
Loss on Debt Extinguishment
Impairment of Other Intangible Assets
Income (Loss) From Continuing Operations Before Income Tax
$
Total Assets:
Segment Assets for Total Reportable Business Segments:
E&P
Midstream
Intercompany Eliminations
Items Excluded from Segment Assets:
Cash and Other Investments
Recoverable Income Taxes
Total Consolidated Assets
123
NOTE 25—RELATED PARTY TRANSACTIONS
CONSOL Energy Inc.
In connection with the spin-off of the coal business, as discussed in Note 5 - Discontinued Operations, CNX and CONSOL
Energy entered into several agreements that govern the relationship of the parties, including the following:
• Separation and Distribution Agreement;
• Transition Services Agreement;
• Tax Matters Agreement;
• Employee Matters Agreement;
•
• CNX Resources Corporation to CONSOL Energy Inc. Trademark License Agreement;
• CONSOL Energy Inc. to CNX Resources Corporation Trademark License Agreement; and
• First Amendment to Amended and Restated Omnibus Agreement (“Omnibus Amendment”).
Intellectual Property Matters Agreement;
There were also one-time transaction costs related to the spin-off of approximately $40,545 for the year ended December
31, 2017, that were split equally by the two companies per the Separation and Distribution agreement. These costs consisted of
consulting and professional fees associated with preparing for and executing the spin-off, as well as other items that were included
within total costs of discontinued operations.
As of December 31, 2018 and December 31, 2017, CNX had a receivable from CONSOL Energy of $235 and $12,540,
respectively, recorded in Total Current Assets on the Consolidated Balance Sheets. At December 31, 2018, CNX also had recorded
obligations to CONSOL Energy of $11,788, of which $5,500 was included in Total Current Liabilities and $6,288 was included
in Total Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. At December 31, 2017, CNX had recorded
obligations to CONSOL Energy of $15,415, of which $4,500 was recorded in Total Current Liabilities and $10,915 was included
in Total Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. These items relate to the reimbursement of the
one-time transaction costs as well as other reimbursements per the terms of the Separation and Distribution Agreement.
For the periods prior to the spin-off of the coal business, all significant intercompany transactions between CNX and CONSOL
Energy had been included in the Consolidated Financial Statements and are considered to have been effectively settled for cash
at the time the transaction was recorded. In the Consolidated Statement of Stockholders' Equity, the distribution of CONSOL
Energy Inc. is the net of the variety of intercompany transactions including, but not limited to, collection of trade receivables,
payment of trade payables and accrued liabilities, settlement of charges for allocated selling, general and administrative costs and
payment of taxes by CNX on CONSOL Energy's behalf.
NOTE 26—SUBSEQUENT EVENT
On January 25, 2019, the Company experienced a subsurface pressure anomaly during hydraulic fracturing operations on
its Shaw 1G Utica Shale well in Westmoreland County, Pennsylvania. The Company also observed pressure increases at several
nearby shallow oil and gas wells not owned by CNX. CNX immediately suspended hydraulic fracturing operations on the pad. On
February 5, 2019, CNX successfully remediated the Shaw 1G well to arrest the subsurface flow of gas. There were no injuries
and no impact to the environment. While the Company is continuing to evaluate the cause of this incident, it appears that the
pressure anomalies that the Company observed were caused by a casing integrity issue that occurred at a depth below approximately
5,200 feet, allowing gas traveling up the wellbore to escape into shallower formations. CNX believes this issue is isolated to this
well. All hydraulic fracturing operations on the 4-well Shaw pad remain suspended while the Company continues to assess this
incident. As a precaution, CNX will continue to monitor the Shaw 1G well and several nearby shallow oil and gas wells for a
period of time. CNX is working in close coordination with the Municipal Authority of Westmoreland County and all appropriate
state and local stakeholders to ensure the situation was and continues to be addressed in a safe and environmentally compliant
manner.
124
Supplemental Gas Data (unaudited):
The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03,
“Extractive Activities-Oil and Gas (Topic 932).” The supplementary information summarized below presents the results of natural
gas and oil activities for the E&P segment in accordance with the successful efforts method of accounting for production activities.
Capitalized Costs:
Intangible drilling costs
Proved gas properties
Gas gathering assets
Unproved gas properties
Gas wells and related equipment
Other gas assets
Total Property, Plant and Equipment
Accumulated Depreciation, Depletion and Amortization
Net Capitalized Costs
Costs incurred for property acquisition, exploration and development (*):
Property acquisitions
Proved properties
Unproved properties
Development
Exploration
Total
__________
(*)
Includes costs incurred whether capitalized or expensed.
Results of Operations for Producing Activities:
Natural Gas, NGLs and Oil Revenue
(Loss) Gain on Commodity Derivative Instruments
Purchased Gas Revenue
Total Revenue
Lease Operating Expense
Production, Ad Valorem, and Other Fees
Transportation, Gathering and Compression
Purchased Gas Costs
Impairment of Exploration and Production Properties
Exploration Costs
Depreciation, Depletion and Amortization
Total Costs
Pre-tax Operating Income (Loss)
Income Tax Expense (Benefit)
Results of Operations for Producing Activities excluding Corporate and
Interest Costs
125
As of December 31,
2018
2017
$
4,120,283
$
3,849,689
1,135,411
1,099,047
927,667
856,973
54,395
1,999,891
1,182,234
919,733
834,120
181,038
$
$
8,193,776
(2,475,917)
5,717,859
$
$
8,966,705
(3,408,606)
5,558,099
For the Years Ended December 31,
2018
2017
2016
$
38,621
$
15,850
$
36,248
844,081
61,604
32,038
544,809
48,020
—
1,537
138,813
32,259
$
980,554
$
640,717
$
172,609
$
$
$
2016
For the Years Ended December 31,
2017
1,125,224
206,930
53,795
1,385,949
88,932
29,267
382,865
52,597
137,865
48,074
412,036
1,151,636
234,313
(348,676)
2018
1,577,937
(30,212)
65,986
1,613,711
95,139
32,750
424,206
64,817
—
12,033
461,149
1,090,094
523,617
102,629
793,248
(141,021)
43,256
695,483
96,434
31,049
374,350
42,717
—
14,522
419,939
979,011
(283,528)
(69,929)
$
420,988
$
582,989
$
(213,599)
The following is production, average sales price and average production costs, excluding ad valorem and severance taxes,
per unit of production:
Production (MMcfe)
Total average sales price before effects of financial settlements (per Mcfe)
Average effects of financial settlements (per Mcfe)
Total average sales price including effects of financial settlements (per
Mcfe)
Average lifting costs, excluding ad valorem and severance taxes (per
Mcfe)
For the Years Ended December 31,
2016
2017
2018
507,104
407,166
394,387
$
$
$
$
$
3.12
(0.15) $
2.97
0.19
$
$
$
2.76
(0.10) $
2.66
0.22
$
$
2.01
0.62
2.63
0.24
During the years ended December 31, 2018, 2017 and 2016, the Company drilled 83.9, 90.0, and 36.0 net development
wells, respectively. There were no net dry development wells in 2018, 2017, or 2016.
During the year ended December 31, 2018 and 2016, the Company drilled no net exploratory wells. During the year ended
December 31, 2017 the Company drilled 4.0 net exploratory wells. There were no net dry exploratory wells in 2018, 2017, or
2016.
At December 31, 2018, there were 22.0 net development wells and no exploratory wells that are drilled but uncompleted.
Additionally, there are 8.0 net developmental wells that have been completed and are awaiting final tie-in to production.
CNX is committed to provide 741.5 Bcf of gas under existing sales contracts or agreements over the course of the next four
years. The Company expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.
Most of the Company's development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania.
Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling
commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2018, the number of
producing wells, developed acreage and undeveloped acreage:
Producing Gas Wells (including gob wells)
Producing Oil Wells
Acreage Position:
Proved Developed Acreage
Proved Undeveloped Acreage
Unproved Acreage
Total Acreage
Gross
Net(1)
6,453
149
4,623
1
289,602
33,370
4,940,180
5,263,152
289,602
33,370
3,960,428
4,283,400
____________
(1) Net acres include acreage attributable to the Company's working interests of the properties. Additional adjustments (either
increases or decreases) may be required as the Company further develops title to and further confirms its rights with respect
to its various properties in anticipation of development. The Company believes that its assumptions and methodology in
this regard are reasonable.
Proved Oil and Gas Reserves Quantities:
Annually, the preparation of natural gas reserves estimates is completed in accordance with CNX prescribed internal control
procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as
multi-functional management review. The input data verification includes reviews of the price and cost assumptions used in the
economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the
reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the
reserve estimates is a registered professional engineer in the state of West Virginia with over 15 years of experience in the oil and
gas industry. The Company's 2018 gas reserves results, which are reported in the Supplemental Gas Data year ended December
31, 2018 Form 10-K, were audited by Netherland, Sewell & Associates, Inc. The technical person primarily responsible for
overseeing the audit of the Company's reserves is a registered professional engineer in the state of Texas with over 15 years of
experience in the oil and gas industry. The gas reserves estimates are as follows:
126
Balance December 31, 2015 (a)
Revisions (b)
Price Changes
Extensions and Discoveries (c)
Production
Purchases of Reserves In-Place (d)
Sales of Reserves In-Place (d)
Balance December 31, 2016 (a)
Revisions (e)
Price Changes
Extensions and Discoveries (c)
Production
Sales of Reserves In-Place
Balance December 31, 2017 (a)
Revisions (f)
Price Changes
Extensions and Discoveries (c)
Production
Purchases of Reserves In-Place
Sales of Reserves In-Place (g)
Balance December 31, 2018 (a)
Proved developed resources:
Proved undeveloped resources:
Natural Gas
(MMcf)
5,060,215
11,559
(179,914)
643,688
(348,753)
1,352,759
(711,155)
5,828,399
(202,735)
173,738
1,769,029
(364,893)
(81,780)
7,121,758
313,091
28,100
839,268
(468,228)
317,437
(715,088)
7,436,338
NGLs
(Mbbls)
Condensate Consolidated
& Crude Oil Operations
(Mbbls)
(MMcfe)
86,212
(19,078)
(1,647)
10,960
(6,710)
13,177
(22,382)
60,532
1,162
1,188
17,887
(6,456)
(2,622)
71,691
441
32
16,247
(6,011)
756
(17,252)
65,904
10,916
510
(34)
1,783
(896)
1,970
(4,240)
10,009
(5,834)
(159)
1,800
(589)
(277)
4,950
865
4
4,010
(468)
—
(1,100)
8,261
5,642,989
(99,849)
(190,009)
720,146
(394,387)
1,443,642
(870,884)
6,251,648
(232,321)
181,470
1,887,153
(407,166)
(99,172)
7,581,612
320,925
28,315
960,808
(507,104)
321,975
(825,196)
7,881,335
December 31, 2016
December 31, 2017
December 31, 2018
3,478,464
4,051,526
4,242,579
30,666,000
56,022,000
40,180,000
3,474,000
3,567,000
1,870,000
3,683,302
4,409,065
4,494,878
December 31, 2016
December 31, 2017
December 31, 2018
2,349,934
3,070,232
3,193,759
29,866,000
15,669,000
25,724,000
6,536,000
1,383,000
6,391,000
2,568,346
3,172,547
3,386,457
__________
(a)
Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally,
these reserves would be commercially recovered under current economic conditions, operating methods and government
regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting
future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of
natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions and government regulations. Proved developed
reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods.
(b) The net downward revision of 99.8 Bcfe was the result of 255 Bcfe downward revision for wells that were removed from
both internal and JV partner development plans, 113 Bcfe downward revision related to economics for producing properties
offset by 268 Bcfe of improved analog performance.
(c) Extensions and Discoveries in 2016, 2017, and 2018 are due to the addition of wells on the Company's Marcellus and Utica
Shale acreage more than one offset location away with continued use of reliable technology.
(d) Purchases and Sales of Reserves In-Place in 2016 is the result of the Company's fourth quarter realignment of the Marcellus
Shale properties as part of dissolving our joint venture with Noble Energy.
(e) The downward revisions for 2017 is due to corporate planning changes by our JV partner in Ohio Utica which resulted in
all PUD's being removed, causing a 458 Bcfe downward revision, offset, in part by improved well performance due to the
enhanced RCS completions and improved operating costs.
(f) The upward revision for 2018 of 321 Bcfe is primarily due to a 472 Bcfe upward revision from increased performance
through our continued focus on optimization. This is partially offset by a 151 Bcfe downward revision due to plan changes.
127
(g) The sales of reserves in-place is related to the divestiture of our Utica JV assets and substantially all of our conventional
properties. Refer to Note 6 - Acquisitions and Dispositions for more information.
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves
Undeveloped reserves transferred to developed(a)
Disposition of reserves in place
Acquisition of reserves in place
Price Revisions
Revisions Due to Plan Changes (b)
Revisions Due to Changes Due to Well Performance (c)
Extension and discoveries (d)
Ending proved undeveloped reserves(e)
For the Year
Ended
December 31,
2018
3,172,547
(1,037,727)
(27,741)
321,975
(2,489)
(151,550)
189,954
921,488
3,386,457
_________
(a) During 2018, various exploration and development drilling and evaluations were completed. Approximately, $480,003 of
capital was spent in the year ended December 31, 2018 related to undeveloped reserves that were transferred to developed.
(b) The downward revisions for 2018 plan changes is due to removal of a portion of our CBM and Marcellus locations from
(c)
(d)
(e)
our proved undeveloped reserves.
The upward revisions due to well performance is due to results from Marcellus and Utica Shale production.
Extensions and discoveries are due mainly to the addition of wells or an extension to previously booked PUD's on our
Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.
Included in proved undeveloped reserves at December 31, 2018 are approximately 281,696 MMcfe of reserves that have
been reported for more than five years. These reserves specifically relate to GOB (a rubble zone formed in the cavity created
by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined
seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the
Buchanan Mine that was sold in March 2016 to Coronado IV LLC (See Note 5 - Discontinued Operations for more information)
with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the
mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons
constitute the specific circumstances that exist to continue recognizing these reserves for CNX.
At December 31, 2018 there were no wells pending the determination of proved reserves.
The following table represents the capitalized exploratory well cost activity as indicated:
Costs reclassified to wells, equipment and facilities based on the
determination of proved reserves
Costs expensed due to determination of dry hole or abandonment of
project
$
$
46,614
809
$
$
40,149
$
40,917
— $
—
CNX proved natural gas reserves are located in the United States.
December 31,
2018
2017
2016
128
Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards
Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the
standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year.
Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from
year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be
interpreted as representing current value to CNX. Material revisions to estimates of proved reserves may occur in the future;
development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary
significantly from those used; and actual costs may vary. CNX investment and operating decisions are not based on the information
presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and
cost assumptions.
The standardized measure is intended to provide a better means for comparing the value of CNX proved reserves at a given
time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
Future Cash Flows (a)
Revenues
Production costs
Development costs
Income tax expense
Future Net Cash Flows
Discounted to present value at a 10% annual rate
Total standardized measure of discounted net cash flows
December 31,
2018
2017
2016
$ 26,610,100
(7,730,451)
(1,600,128)
(4,147,075)
13,132,446
(8,476,989)
4,655,457
$
$ 19,261,578
(7,234,303)
(1,710,585)
(2,475,981)
7,840,709
(4,709,311)
3,131,398
$
$ 11,303,409
(5,850,941)
(1,550,294)
(1,482,826)
2,419,348
(1,464,231)
955,117
$
(a)
For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each
month during 2018, adjusted for energy content and a regional price differential. For 2018, this adjusted natural gas price
was $3.28 per Mcf, the adjusted oil price was $51.68 per barrel and the adjusted NGL price was $27.58 per barrel.
For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each
month during 2017, adjusted for energy content and a regional price differential. For 2017, this adjusted natural gas price
was $2.44 per Mcf, the adjusted oil price was $38.65 per barrel and the adjusted NGL price was $23.61 per barrel.
For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each
month during 2016, adjusted for energy content and a regional price differential. For 2016, this adjusted natural gas price
was $1.73 per Mcf, the adjusted oil price was $25.04 per barrel and the adjusted NGL price was $15.77 per barrel.
129
The following are the principal sources of change in the standardized measure of discounted future net cash flows for
consolidated operations during:
Balance at beginning of period
Net changes in sales prices and production costs
Sales net of production costs
Net change due to revisions in quantity estimates
Net change due to extensions, discoveries and improved recovery
Development costs incurred during the period
Difference in previously estimated development costs compared to actual
costs incurred during the period
Purchase of Reserves In-Place
Sales of Reserves In-Place
Changes in estimated future development costs
Net change in future income taxes
Timing and Other
Accretion
December 31,
2018
2017
$
3,131,398
$
955,117
$
1,732,229
(995,630)
307,030
534,052
844,081
(434,817)
209,630
(434,103)
(49,294)
(507,410)
(69,087)
387,378
1,983,475
(831,131)
(145,496)
588,574
544,809
(129,427)
—
(55,277)
(233,017)
(404,582)
712,764
145,589
Total discounted cash flow at end of period
$
4,655,457
$
3,131,398
$
2016
1,019,304
(172,812)
(150,819)
(35,502)
(54,628)
138,813
(39,821)
238,819
(137,998)
(158,000)
36,513
125,529
145,719
955,117
Supplemental Quarterly Information (unaudited):
(Dollars in thousands, except per share data)
Sales (A)
Costs and Expenses (B)
Income from Continuing Operations (C)
Income from Discontinued Operations
Net Income Attributable to CNX Resources
Shareholders
Earnings Per Share
Basic:
Income from Continuing Operations
Income from Discontinued Operations
Total Basic Earnings Per Share
Diluted:
Income from Continuing Operations
Income from Discontinued Operations
Total Diluted Earnings Per Share
$
$
$
$
$
$
$
$
$
$
$
Three Months Ended
March 31,
June 30,
September 30, December 31,
2018
2018
2018
2018
485,019
167,785
545,546
$
$
$
— $
393,590
140,040
61,394
$
$
$
— $
393,223
123,779
146,756
$
$
$
— $
431,660
148,480
129,415
—
527,563
$
42,014
$
125,029
$
101,927
0.19
$
— $
$
0.19
0.59
$
— $
$
0.59
0.19
$
— $
$
0.19
0.59
$
— $
$
0.59
0.51
—
0.51
0.50
—
0.50
2.38
$
— $
$
2.38
2.35
$
— $
$
2.35
130
Sales (A)
Costs and Expenses (B)
(Loss) Income from Continuing Operations (C)
Income (Loss) from Discontinued Operations
Net (Loss) Income
Earnings Per Share
Basic:
(Loss) Income from Continuing Operations
Income (Loss) from Discontinued Operations
Total Basic (Loss) Earnings Per Share
Diluted:
(Loss) Income from Continuing Operations
Income (Loss) from Discontinued Operations
Total Diluted (Loss) Earnings Per Share
Three Months Ended
March 31,
June 30,
September 30, December 31,
2017
2017
2017
2017
$
$
$
$
$
$
$
$
$
$
$
304,279
$
162,150
$
(91,007) $
52,041
$
(38,966) $
354,410
166,296
121,807
47,703
169,510
(0.40) $
0.23
$
(0.17) $
(0.40) $
$
0.23
(0.17) $
0.53
0.21
0.74
0.52
0.21
0.73
$
$
$
$
$
$
$
$
$
$
$
267,009
$
171,608
$
(21,796) $
(4,645) $
(26,441) $
460,251
214,050
286,035
(9,391)
276,644
(0.09) $
(0.02) $
(0.11) $
(0.09) $
(0.02) $
(0.11) $
1.27
(0.04)
1.23
1.26
(0.05)
1.21
(A) Includes natural gas, NGLs, and oil revenue; (loss) gain on commodity derivative instruments; and purchased gas revenue.
(B) Includes exploration and production costs and other operating expense; excludes DD&A, selling, general and administrative,
loss on debt extinguishment, interest expense and other expense.
(C) Includes an impairment of $18,650 that was recorded during the three months ended June 30, 2018 related to CNX's intangible
assets and $137,865 that was recorded during the three months ended March 31, 2017 related to CNX's exploration and production
properties. See Note 1 - Significant Accounting Policies in Item 8 of this Form 10-K for additional information.
131
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure controls and procedures. CNX, under the supervision and with the participation of its management, including
CNX’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls
and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”),
as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, CNX’s principal executive
officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of
December 31, 2018 to ensure that information required to be disclosed by CNX in reports that it files or submits under the Exchange
Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission
rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CNX in
such reports is accumulated and communicated to CNX’s management, including CNX’s principal executive officer and principal
financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Management's Annual Report on Internal Control Over Financial Reporting. CNX's management is responsible for
establishing and maintaining adequate internal control over financial reporting. CNX's internal control over financial reporting is
a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles.
CNX's internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances
that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management
and the directors of CNX; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of CNX's assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of CNX's internal control over financial reporting as of December 31, 2018. In
making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) (COSO) in Internal Control-Integrated Framework. Based on management's assessment and those
criteria, management has concluded that CNX maintained effective internal control over financial reporting as of December 31,
2018.
The effectiveness of CNX's internal control over financial reporting as of December 31, 2018 has been audited by Ernst &
Young, LLP, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent
Registered Public Accounting Firm in Part II, Item 9A of this Annual Report on Form 10-K.
Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over
financial reporting that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
132
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of CNX Resources Corporation and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited CNX Resources Corporation and Subsidiaries’ internal control over financial reporting as of December 31, 2018,
based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, CNX Resources Corporation and Subsidiaries
(the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,
based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of CNX Resources Corporation and Subsidiaries as of December 31, 2018 and 2017,
and the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the
three years in the period ended December 31, 2018 and the related notes and financial statement schedule listed in the Index at
Item 15 (a) (2) of the Company and our report dated February 7, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on
Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent
with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for
our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 7, 2019
133
ITEM 9B.
OTHER INFORMATION
On February 1, 2019, Stephen W. Johnson informed CNX of his decision, effective the same date, to step down from his
position as Executive Vice President and Chief Legal Officer of the Corporation and to assume the role of counsel to the Corporation.
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated herein by reference from the information under the captions
“PROPOSAL NO. 1-ELECTION OF DIRECTORS-Biographies of Nominees,” “BOARD OF DIRECTORS AND
COMPENSATION INFORMATION and “SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the
Proxy Statement for the annual meeting of shareholders to be held on May 29, 2019 (the “Proxy Statement”).
Executive Officers of CNX
The following is a list, as of February 1, 2019, of CNX executive officers, their ages and their positions and offices held
with CNX.
Name
Nicholas J. DeIuliis
Stephen W. Johnson
Donald W. Rush
Timothy C. Dugan
Age
50
60
36
57
Position
President and Chief Executive Officer
Executive Vice President and Chief Legal Officer
Executive Vice President and Chief Financial Officer
Executive Vice President and Chief Operating Officer
Nicholas J. DeIuliis is a Director and the President and Chief Executive Officer of CNX Resources Corporation. Prior to
the separation of CONSOL Energy Inc. into two separate companies, Mr. DeIuliis had more than 25 years of experience with the
Company and in that time has held the positions of Chief Executive Officer since May 7, 2015, President since February 23, 2011,
and previously served as the Chief Operating Officer, Senior Vice President - Strategic Planning, and earlier in his career various
engineering positions. On January 3, 2018, Mr. DeIuliis was appointed Chairman of the Board and Chief Executive Officer of the
general partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners, LP). He was a Director, President
and Chief Executive Officer of CNX Gas Corporation from its creation in 2005 through 2009. Mr. DeIuliis was a Director and
Chairman of the Board of the general partner of CONSOL Coal Resources LP (formerly known as CNX Coal Resources LP) from
March 16, 2015 until November 28, 2017. Mr. DeIuliis is a member of the Board of Directors of the University of Pittsburgh
Cancer Institute, the Center for Responsible Shale Development. Mr. DeIuliis is a registered engineer in the Commonwealth of
Pennsylvania and a member of the Pennsylvania bar.
Stephen W. Johnson serves as the Executive Vice President and Chief Legal Officer of CNX Resources Corporation. Mr.
Johnson served as the Executive Vice President and Chief Administrative Officer of the Company from the Company's separation
into two separate companies on November 28, 2017 until September 25, 2018. Between December 31, 2012 and January 1,2017 ,
Mr. Johnson served as Executive Vice President - Diversified Business Units and Chief Legal and Corporate Affairs Officer, and
as Senior Vice President and General Counsel of both the Company and CNX Gas Corporation. On May 30, 2014, Mr. Johnson
became a Director of the general partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners LP). Mr.
Johnson was a Director of the general partner of CONSOL Coal Resources LP (formerly known as CNX Coal Resources LP) from
March 16, 2015 until November 28, 2017. Mr. Johnson has spent numerous years in the natural resources industry, including 13
years with CNX Resources Corporation, the Company, and CNX Gas Corporation and a number of years prior to that representing
natural resources companies in private legal practice. Mr. Johnson is the Chairman of the Board of Concordia Lutheran Ministries,
a nonprofit continuing care retirement community, and the former Chairman of NEED, a nonprofit minority college access program.
Donald W. Rush has served as the Executive Vice President and Chief Financial Officer of CNX Resources Corporation
since July 11, 2017. He previously served as Vice President of Energy Marketing where he oversaw the Company's commercial
functions, including mergers and acquisitions, gas marketing and transportation, in addition to holding other strategy and planning,
business development and engineering positions during his 13 years with the Company. He successfully guided the Company
through every significant transaction during its transition into a pure play natural gas exploration and production company, including
the sale of the Company's five West Virginia coal mines in 2013 and the separation of the Company’s Marcellus Shale joint venture
with Noble Energy Inc. in 2016. On January 3, 2018, Mr. Rush was appointed as a Director and named Chief Financial Officer
134
of the general partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners, LP). Mr. Rush holds a B.S
in civil engineering from the University of Pittsburgh and an M.B.A from Carnegie Mellon University’s Tepper School of Business.
Timothy C. Dugan has served as an Executive Vice President since September 20, 2016, and Chief Operating Officer of
CNX Resources Corporation since January 28, 2014. Mr. Dugan also held the positions of President and Chief Operating Officer
of CNX Gas Corporation from May 2014 to December 2014 when he became President and Chief Executive Officer of CNX Gas
Corporation, a position he continues to hold. Mr. Dugan was appointed Director and named Chief Operating Officer of the general
partner of CNX Midstream Partners LP (formerly known as CONE Midstream Partners, LP) on January 3, 2018, and January 12,
2018, respectively. Prior to joining CNX, Mr. Dugan was Vice President - Appalachia South Business Unit at Chesapeake Energy
Corporation, a petroleum and natural gas exploration and production company. During his seven years with Chesapeake Energy,
he held several titles, including Senior Asset Manager and District Manager. Mr. Dugan began his petroleum and natural gas
engineering career in 1984 with Cabot Oil & Gas Corporation as a General Foreman and Field Consultant, and he held other
industry related positions with progressing responsibility at various oil and gas companies. Mr. Dugan is a member of the Society
of Petroleum Engineers.
CNX has a written Code of Employee Business Conduct and Ethics that applies to CNX's Chief Executive Officer (Principal
Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Employee Business Conduct
and Ethics is available on CNX's website at www.cnx.com. Any amendments to, or waivers from, a provision of our Code of
Employee Business Conduct and Ethics that applies to our Principal Executive Officer, our Principal Financial and Accounting
Officer and that relates to any element enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting
such information on our website at www.cnx.com.
By certification dated May 31, 2018, CNX's Chief Executive Officer certified to the New York Stock Exchange (NYSE)
that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the
required Sarbanes-Oxley Act, Section 302 certifications regarding the quality of our public disclosures were filed by CNX
Resources as exhibits to this Form 10-K.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the information under the captions “BOARD OF
DIRECTORS AND COMPENSATION INFORMATION and “EXECUTIVE COMPENSATION INFORMATION” (excluding
the Compensation Committee Report) in the Proxy Statement.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference from the information under the captions “BENEFICIAL
OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CNX EQUITY
COMPENSATION PLAN” in the Proxy Statement.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
The information requested by this Item is incorporated by reference from the information under the caption “PROPOSAL
NO. 1-ELECTION OF DIRECTORS - Related Party Policy and Procedures and PROPOSAL NO. 1 - ELECTION OF
DIRECTORS - Determination of Director Independence in the Proxy Statement.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference from the information under the caption “ACCOUNTANTS
AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.
135
ITEM 15.
EXHIBITS, FINANCIAL STATMENT SCHEDULES
PART IV
In reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that
such agreements are included to provide information regarding their terms. They are not intended to be a source of financial,
business or operational information about CNX or any of its subsidiaries or affiliates. The representations, warranties and covenants
contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the
benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating
the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of
establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from
those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties
and covenants or any description thereof as characterizations of the actual state of facts or condition of CNX or any of its subsidiaries
or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the
subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these
representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
(a)(1)
(a)(2)
(a)(3)
2.1
2.2
2.3
2.4
2.5
3.1
3.2
3.3
4.1
4.2
4.3
4.4
Financial Statements Contained in Item 8 hereof.
Financial Statement Schedule-Schedule II Valuation and Qualifying Accounts contained below, following the
signature page.
Exhibits and Exhibit Index.
Membership Interest and Asset Purchase Agreement dated February 26, 2016, among the Company, CONSOL Mining
Holding Company LLC, CONSOL Buchanan Mining Company LLC, CONSOL Amonate Mining Company LLC
CONSOL Mining Company LLC, CNX Land LLC, CNX Marine Terminals Inc., CNX RCPC LLC, CONSOL
Pennsylvania Coal Company LLC and CONSOL Amonate Facility LLC and Coronado IV LLC, incorporated by
reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on February 29, 2016.
Separation and Distribution Agreement, dated as of November 28, 2017, by and between the Company and CONSOL
Mining Corporation, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on December
4, 2017.
Tax Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining
Corporation, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
Employee Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining
Corporation, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
Intellectual Property Matters Agreement, dated as of November 28, 2017, by and between the Company and CONSOL
Mining Corporation, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on December
4, 2017.
Restated Certificate of Incorporation of the Company, incorporated by reference to Exhibit 3.1 to Form 8-K (file no.
001-14901) filed on May 8, 2006.
Certificate of Amendment to the Restated Certificate of Incorporation of the Company, incorporated by reference to
Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017.
Amended and Restated Bylaws of the Company, incorporated by reference to Exhibit 3.2 to Form 8-K (file no.
001-14901) filed on December 4, 2017.
Indenture, dated as of April 16, 2014, among the Company, the Subsidiary Guarantors named therein and Wells Fargo
Bank, National Association, a national banking association, as trustee, with respect to the 5.875% Senior Notes due
2022, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
Registration Rights Agreement, dated as of April 16, 2014, by and among the Company, the guarantors signatory
thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several
initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
Registration Rights Agreement, dated as of August 12, 2014, by and among the Company, the guarantors signatory
thereto and Goldman, Sachs & Co., as the initial purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K
(file no. 001-14901) filed on August 12, 2014.
Registration Rights Agreement, dated as of March 30, 2015, among the Company, the subsidiary guarantors party
thereto and Goldman, Sachs & Co. as the initial purchaser named therein, incorporated by reference to Exhibit 4.2
to Form 8-K (file no. 001-14901) filed on March 30, 2015.
136
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16*
10.17*
10.18*
Purchase and Sale Agreement, dated as of April 30, 2003, by and among the Company, CONSOL Sales Company,
CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek
Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four
Mining Company, CNX Gas Company LLC, CNX Marine Terminals Inc. and CNX Funding Corporation, incorporated
by reference to Exhibit 10.30 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2003, filed on
August 13, 2003.
Purchase and Sale Agreement dated July 19, 2016, among CONSOL of Kentucky Inc., Island Creek Coal Company,
Laurel Run Mining Company, and CNX Land LLC and Southeastern Land, LLC, incorporated by reference to Exhibit
2.1 to Form 8-K (file no. 001-14901) filed on July 25, 2016.
Contribution Agreement dated as of November 15, 2016, by and among CONE Gathering LLC, CONE Midstream
GP LLC, CONE Midstream Partners LP, CONE Midstream Operating Company LLC and certain other signatories
thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on November 16, 2016.
Amendment No. 3 and Borrowing Base Redetermination, dated as of October 25, 2017, to the Amended and Restated
Credit Agreement, dated as of June 18, 2014, by and among the Company, the subsidiary guarantors party thereto,
certain lenders and PNC Bank, National Association as administrative agent, incorporated by reference to Exhibit
10.1 to Form 8-K (file no. 001-14901) filed on October 31, 2017.
Amendment No. 4, dated as of November 27, 2017, to the Amended and Restated Credit Agreement, dated as of June
18, 2014, by and among the Company, the subsidiary guarantors party thereto, certain lenders and PNC Bank, National
Association as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed
on December 1, 2017.
Resignation, Consent and Appointment Agreement entered into as of September 12, 2016, by and among Bank of
America, N.A., as the resigning Syndication Agent under that certain Amended and Restated Credit Agreement, dated
as of June 18, 2014, JPMorgan Chase Bank, N.A., as the successor Syndication Agent, and the Company, a Delaware
corporation, as the Borrower, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the
quarter ended September 30, 2016, filed on November 1, 2016.
Second Amended and Restated Credit Agreement, dated as of March 8, 2018, among the Company, certain of its
subsidiaries, PNC Bank, National Association, as administrative agent and collateral agent, JPMorgan Chase Bank,
N.A., as syndication agent and the lender parties thereto, incorporated by reference to Exhibit 10.1 to Form 8-K (file
no. 001-14901) filed on March 12, 2018.
Stipulation and Agreement of Compromise and Settlement, dated May 8, 2013, between and among (i) plaintiffs
Harold L. Hurwitz and James R. Gummel, on their own behalf and on behalf of the Class (as defined therein) and
(ii) defendants CNX Gas Corporation, CONSOL Energy Inc. and certain individual defendants, incorporated by
reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2013, filed on August 5,
2013.
Purchase Agreement, dated as of April 10, 2014, among the Company, the subsidiary guarantors party thereto and
J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers
named therein, incorporated by reference to Exhibit 1.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.
Transition Services Agreement, dated as of November 28, 2017, by and between the Company and CONSOL Mining
Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 4, 2017
CNX Resources Corporation to CONSOL Energy Inc. Trademark License Agreement dated as of November 28,
2017, by and between the Company and CONSOL Energy Inc., incorporated by reference to Exhibit 10.2 to Form
8-K (file no. 001-14901) filed on December 4, 2017
CONSOL Energy Inc. to CNX Resources Corporation Trademark License Agreement, dated as of November 28,
2017, by and between the Company and CONSOL Energy Inc., incorporated by reference to Exhibit 10.3 to Form
8-K (file no. 001-14901) filed on December 4, 2017
Purchase Agreement, dated as of December 14 ,2017, by and among CNX Gas Company LLC, as Buyer, and NBL
Midstream, LLC, as Seller, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on
January 3, 2018.
Purchase and Sale Agreement, dated June 28, 2018, by and between CNX Gas Company LLC and Ascent Resources
- Utica, LLC, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 31, 2018.
First Amendment to Purchase and Sale Agreement, dated August 29, 2018, by and between CNX Gas Company LLC
and Ascent Resources - Utica, LLC, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed
on August 31, 2018.
Letter Agreement, dated August 24, 2007, by and between the Company and Nicholas J. DeIuliis, incorporated by
reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.
Change in Control Agreement, dated as of December 30, 2008, by and between the Company and Nicholas J. DeIuliis,
incorporated by reference to Exhibit 10.7 to Form 10-K (file no. 001-14901) for the year ended December 31, 2008,
filed on February 17, 2009.
Change in Control Agreement, dated as of December 30, 2008, by and among CNX Gas Corporation, the Company
and Stephen W. Johnson, incorporated by reference to Exhibit 10.4 to the CNX Gas Corporation Form 10-K (file no.
001-32723) for the year ended December 31, 2008, filed on February 17, 2009.
137
10.19*
10.20*
10.21*
10.22*
10.23*
10.24*
10.25*
10.26*
10.27*
10.28*
10.29*
10.30*
10.31*
10.32*
10.33*
10.34*
10.35*
10.36*
10.37*
10.38*
10.39*
10.40*
10.41*
10.42*
10.43*
10.44*
10.45*
10.46*
10.47*
Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between the Company
and Timothy Dugan, incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter
ended September 30, 2015, filed on November 3, 2015.
Change in Control Severance Agreement, dated August 24, 2015, between the Company and Donald W. Rush,
incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2018,
filed on May 3, 2018.
Form of Indemnification Agreement for Directors and Executive Officers of the Company, incorporated by reference
to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.
Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by
reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3,
2009.
CNX Resources Corporation Equity Incentive Plan, as amended and restated effective January 26, 2018, incorporated
by reference to Exhibit 10.48 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on
February 7, 2018.
Amended and Restated CNX Resources Corporation Executive Annual Incentive Plan, incorporated by reference to
Exhibit 10.49 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
Form of Non-Qualified Stock Option Award Agreement for Employees, incorporated by reference to Exhibit 10.26
to Form S-4 (file no. 333-149442) filed on February 28, 2008.
Form of Non-Qualified Stock Option Award Agreement for Employees (February 17, 2009 and through 2012),
incorporated by reference to Exhibit 10.28 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
Form of Non-Qualified Performance Stock Option Agreement for Employees, incorporated by reference to Exhibit
10.1 to Form 8-K (file no. 001-14901) filed on June 21, 2010.
Form of Non-Qualified Stock Option Award for Employees (January 27, 2016), incorporated by reference to Exhibit
10.72 to Form 10-K (file no. 001-14901) for the year ended December 31, 2015, filed on February 5, 2016.
Form of Employee Nonqualified Stock Option Agreement (May 26, 2016), incorporated by reference to Exhibit 10.4
to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2016, filed on July 29, 2016.
Form of Non-Qualified Stock Option Agreement for Directors, incorporated by reference to Exhibit 10.4 to Form
10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
Form of Restricted Stock Unit Award for Employees (February 17, 2009 through 2014), incorporated by reference
to Exhibit 10.31 to Amendment No. 1 to Form S-4 (file no. 333-157894) filed on June 26, 2009.
Form of 5-Year Restricted Stock Unit Award Agreement for Employees, incorporated by reference to Exhibit 10.4
to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.30 to Form
S-4 (file no. 333-149442) filed on February 28, 2008.
Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.5 to Form
10-Q (file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
Form of Restricted Stock Unit Award Agreement for Employees (for 2015 awards), incorporated by reference to
Exhibit 10.67 to Form 10-K (file no. 001-14901) for the year ended December 31, 2014, filed on February 6, 2015.
Form of Restricted Stock Unit Award Agreement for Employees (for 2017 awards), incorporated by reference to
Exhibit 10.59 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
Form of Restricted Stock Unit Award Agreement for CEO (for 2019 awards), filed herewith.
Form of Restricted Stock Unit Award Agreement for VP and Above (for 2019 awards), filed herewith.
Form of Restricted Stock Unit Award Agreement for Non-VP and Below (for 2019 awards), filed herewith.
Form of Performance Share Unit Award Agreement (for 2014 awards), incorporated by reference to Exhibit 10.3 to
Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
Form of Performance Share Unit Award Agreement (for 2015 awards), incorporated by reference to Exhibit 10.69
to Form 10-K (file no. 001-14901) for the year ended December 31, 2014, filed on February 6, 2015.
Form of Performance Share Unit Award Agreement (for 2016 awards), incorporated by reference to Exhibit 10.79
to Form 10-K (file no. 001-14901) for the year ended December 31, 2015, filed on February 5, 2016.
Form of Performance Share Unit Award Agreement (for 2017 awards), incorporated by reference to Exhibit 10.63
to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
Form of Performance Share Unit Award Agreement for CEO (for 2019 awards), filed herewith.
Form of Performance Share Unit Agreement for VP and Above (for 2019 awards), filed herewith.
Form of Performance Share Unit Agreement for Non-VP and Below (for 2019 awards), filed herewith.
Summary of Non-Employee Director Compensation, incorporated by reference to Exhibit 10.69 to Form 10-K (file
no. 001-14901) for the year ended December 31, 2013, filed on February 7, 2014.
138
10.48*
10.49*
10.50*
10.51*
10.52*
10.53*
10.54*
10.55*
10.56*
10.57*
10.58*
10.59*
10.60*
10.61*
21
23.1
23.2
31.1
31.2
32.1
32.2
99.1
101
Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no.
001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
Directors' Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference
to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.
Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by
reference to Exhibit 10.50 to Form 10-K (file no. 001-14901) for the year ended December 31, 2007, filed on
February 19, 2008.
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.3 to Form 10-Q
(file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to Form 8-K
(file no. 001-14901) filed on May 8, 2006.
Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.3 to Form 10-Q
(file no. 001-14901) for the quarter ended March 31, 2018, filed on May 3, 2018.
Trust Agreement (Amended and Restated on March 20, 2008) (1999 Directors Deferred Compensation Plan),
incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008,
filed on April 30, 2008.
Trust Agreement (Amended and Restated on March 20, 2008) (Directors' Deferred Fee Plan (2004 Plan)), incorporated
by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30,
2008.
Amended and Restated Retirement Restoration Plan of CNX Resources Corporation, as amended and restated effective
December 2, 2008, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.71
to Form 10-K (file no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
Amended and Restated Supplemental Retirement Plan of CNX Resources Corporation effective January 1, 2007, as
amended and restated effective November 28, 2017, incorporated by reference to Exhibit 10.72 to Form 10-K (file
no. 001-14901) for the year ended December 31, 2017, filed on February 7, 2018.
CNX Resources Corporation Defined Contribution Restoration Plan, effective January 1, 2012, as amended and
restated effective November 28, 2017, incorporated by reference to Exhibit 10.73 to Form 10-K (file no. 001-14901)
for the year ended December 31, 2017, filed on February 7, 2018.
Amendment, dated as of July 1, 2018, to the CNX Resources Corporation Defined Contribution Restoration Plan,
effective January 1, 2012, as amended and restated effective November 28, 2017, incorporated by reference to Exhibit
10.1 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2018, filed on August 2, 2018.
Executive Compensation Clawback Policy of the Company, dated as of January 28, 2014, incorporated by reference
to Exhibit 10.11 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2014, filed on May 6, 2014.
Purchase and Sale Agreement, dated as of February 7, 2018, by and among CNX Midstream Partners LP, CNX
Midstream DevCo I LP, CNX Midstream DevCo III LP, CNX Gathering LLC, and, for certain purposes, CNX
Midstream DevCo I GP LLC, CNX Midstream DevCo III GP LLC and CNX Midstream Operating Company LLC,
incorporated by reference to Exhibit 10.75 to Form 10-K (file no. 001-14901) for the year ended December 31, 2017,
filed on February 7, 2018.
Subsidiaries of CNX Resources Corporation.
Consent of Ernst & Young LLP
Consent of Netherland Sewell & Associates, Inc.
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
Engineers' Audit Letter
Interactive Data File (Form 10-K for the year ended December 31, 2018 furnished in XBRL).
* Denotes the management contracts and compensatory arrangements in which any director or any named executive officer
participates.
Supplemental Information
No annual report or proxy material has been sent to shareholders of CNX at the time of filing of this Form 10-K. An annual
report will be sent to shareholders and to the commission subsequent to the filing of this Form 10-K.
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
139
ITEM 16. FORM 10-K SUMMARY
NONE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 7th day of February, 2019.
CNX RESOURCES CORPORATION
By:
/s/ NICHOLAS J. DEIULIIS
Nicholas J. DeIuliis
Director, Chief Executive Officer and President
(Duly Authorized Officer and Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 7th day of February,
2019, by the following persons on behalf of the registrant in the capacities indicated:
Signature
Title
/s/ NICHOLAS J. DEIULIIS
Director, Chief Executive Officer and President
Nicholas J. DeIuliis
(Duly Authorized Officer and Principal Executive Officer)
/s/ DONALD W. RUSH
Chief Financial Officer and Executive Vice President
Donald W. Rush
(Duly Authorized Officer and Principal Financial Officer)
/s/ JASON L. MUMFORD
Chief Accounting Officer and Vice President
Jason L. Mumford
(Duly Authorized Officer and Principal Accounting Officer)
/s/ WILLIAM N. THORNDIKE JR.
Director and Chairman of the Board
William N. Thorndike Jr.
/s/ J. PALMER CLARKSON
Director
J. Palmer Clarkson
/s/ WILLIAM E. DAVIS
Director
William E. Davis
/s/ MAUREEN E. LALLY-GREEN
Director
Maureen E. Lally-Green
/s/ BERNARD LANIGAN JR.
Bernard Lanigan Jr.
Director
140
CNX RESOURCES CORPORATION AND SUBSIDIARIES
Valuation and Qualifying Accounts
(Dollars in thousands)
SCHEDULE II
Additions
Deductions
Balance at
Release of
Balance at
Beginning Charged to Valuation Charged to
End
of Period
Expense
Allowance
Expense
of Period
Year Ended December 31, 2018
State operating loss carry-forwards
$
61,560
$
— $
Deferred deductible temporary differences
Charitable Contributions
162(m) Officers Compensation
AMT Credit
Foreign Tax Credits
Total
Year Ended December 31, 2017
9,088
3,156
5,957
12,413
44,402
—
141
—
1,983
—
$ 136,576
$
2,124
$
State operating loss carry-forwards
$
60,488
$
— $
Deferred deductible temporary differences
Charitable Contributions
162(m) Officers Compensation
AMT Credit
Foreign Tax Credits
Total
Year Ended December 31, 2016
10,590
5,052
—
166,798
39,850
—
—
—
—
4,552
(13,596) $
(9,088)
—
(5,957)
(14,396)
(1,208)
(44,245) $
— $
47,964
—
—
—
—
—
—
3,297
—
—
43,194
— $
94,455
1,072
(1,502)
(1,896)
5,957
(154,385)
—
$
— $
61,560
—
—
—
—
—
9,088
3,156
5,957
12,413
44,402
$ 282,778
$
4,552
$ (150,754) $
— $ 136,576
State operating loss carry-forwards
$
42,983
$
17,505
$
— $
— $
60,488
Deferred deductible temporary differences
Charitable Contributions
AMT Credit
Foreign Tax Credits
Total
9,420
—
—
25,903
1,170
5,052
166,798
13,947
—
—
—
—
—
—
—
—
10,590
5,052
166,798
39,850
$
78,306
$
204,472
$
— $
— $ 282,778
141
[This page intentionally left blank]
Directors
J. Palmer Clarkson
William E. Davis
Nicholas J. DeIuliis
Maureen E. Lally-Green
Bernard Lanigan, Jr.
William N. Thorndike, Jr.
2018 Executive Officers
Nicholas J. DeIuliis
President and Chief Executive Officer
Donald W. Rush
Executive Vice President and Chief Financial Officer
Stephen W. Johnson
Executive Vice President and Chief Administrative Officer (retired from position effective 2/1/19)
Timothy C. Dugan
Executive Vice President and Chief Operating Officer
Biographical information regarding our executive officers and directors is contained under “Item 10. – Directors, Executive
Officers and Corporate Governance” in our Annual Report on Form 10-K on page 134 and “Proposal No. 1 – Election of
Directors – Biographies of Nominees” in our Proxy Statement for the annual meeting of shareholders to be held on May 29,
2019 on page 31, respectively, which information is included with this Annual Report.
About CNX Resources Corporation
CNX Resources Corporation (“CNX”) is one of the largest independent natural gas exploration, development and production
companies, with operations centered in the major shale formations of the Appalachian basin. The company deploys an
organic growth strategy focused on responsibly developing its resource base. As of December 31, 2018, CNX had 7.9 trillion
cubic feet equivalent of proved natural gas reserves. The company is a member of the Standard & Poor's Midcap 400 Index.
Additional information may be found at www.cnx.com.
Headquarters
CNX Resources Corporation
CNX Center
1000 CONSOL Energy Drive Suite 400
Canonsburg, PA 15317
Website
http://www.cnx.com
Transfer Agent and Registrar
Computershare
P.O. Box 505000
Louisville, KY 40233-5000
This Annual Report of CNX Resources Corporation is being delivered to the shareholders of CNX to comply with the annual
report delivery requirements of the New York Stock Exchange and Rule 14a-3 of the Securities Exchange Act of 1934, as
amended. All information required by those applicable rules is contained in this Annual Report, including certain information
contained in CNX’s Annual Report on Form 10-K included herein, which has previously been filed by CNX Resources with
the Securities and Exchange Commission.
CNX may also provide a summary annual report to its shareholders. Any such summary annual report is not meant to replace
this Annual Report or satisfy the applicable rules of the New York Stock Exchange or Securities and Exchange Commission,
but is meant only to provide shareholders with a summary of information concerning CNX that has been previously
disseminated to the public.
BR12653C-0419-10KW