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MarketScreener Homepage  >  Equities  >  Nyse  >  CNX Resources Corporation    CNX

CNX RESOURCES CORPORATION

(CNX)
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CNX RESOURCES : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

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02/10/2020 | 05:09pm EDT
The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with the consolidated financial
statements and related notes included elsewhere in this Form 10-K. The
information provided below supplements, but does not form part of, CNX's
financial statements. This discussion contains forward­looking statements that
are based on the views and beliefs of management, as well as assumptions and
estimates made by management. Actual results could differ materially from such
forward­looking statements as a result of various risk factors, including those
that may not be in the control of management. For further information on items
that could impact future operating performance or financial condition, please
see "Part I. Item 1A. Risk Factors" and the section entitled "Forward­Looking
Statements." CNX does not undertake any obligation to publicly update any
forward-looking statements except as otherwise required by applicable law.
The Company has applied the Fast Act Modernization and Simplification of
Regulation S-K, which limits the discussion to the two most recent fiscal years.
This section of this Form 10-K generally discusses 2019 and 2018 items and
year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and
year-to-year comparisons between 2018 and 2017 that are not included in this
Form 10-K can be found in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Part II. Item 7 of our Annual Report on
Form 10-K for the fiscal year ended December 31, 2018.

General

2019 Highlights:


• Record total gas production of 539.1 Bcfe in 2019, 6.3% higher than 2018.


•         Record Marcellus Shale production of 369.7 Bcfe in 2019, 28.3% higher
          than 2018.

• Increased proved reserves to 8.4 Tcfe, 6.9% higher than 2018.

• Repurchased $115 million of CNX common stock on the open market.

• Repurchased $400 million of 5.875% notes due in 2022.

2020 Outlook:

• Our 2020 annual gas production is expected to be approximately 525-555 Bcfe.

• Our 2020 E&P capital expenditures are expected to be approximately

           $530-$610 million.



Results of Operations: Year Ended December 31, 2019 Compared with the Year Ended
December 31, 2018
Net (Loss) Income Attributable to CNX Resources Shareholders
CNX reported a net loss attributable to CNX Resources shareholders of $81
million, or a loss per diluted share of $0.42, for the year ended December 31,
2019, compared to net income attributable to CNX Resources shareholders of $797
million, or earnings per diluted share of $3.71, for the year ended December 31,
2018.
                                                         For the Years Ended December 31,
(Dollars in thousands)                                   2019           2018         Variance
Net Income                                          $    31,948$ 883,111$ (851,163 )
Less: Net Income Attributable to Noncontrolling
Interests                                               112,678         86,578         26,100
Net (Loss) Income Attributable to CNX Resources
Shareholders                                        $   (80,730 )$ 796,533$ (877,263 )

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, Coalbed Methane and Other Gas.


CNX's E&P Division had a loss before income tax of $140 million for the year
ended December 31, 2019, compared to earnings before income tax of $245 million
for the year ended December 31, 2018. Included in the 2019 loss was a $327
million non-cash impairment charge related to exploration and production
properties and a $119 million non-cash impairment charge related to unproved
properties and expirations, both of which were associated with the Company's
Central Pennsylvania (CPA) acreage (See the Other Gas Segment for more
information). There were no such transactions in the 2018 period. Offsetting the
loss for the 2019 period was an unrealized gain on commodity derivative
instruments of $306 million compared to an unrealized gain of $40 million for
the year ended December 31, 2018.


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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.

As a result of 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 owns and controls 100%
of CNX Gathering, making CNXM a single-sponsor master limited partnership and
thus the Company began consolidating CNXM on January 3, 2018. The resulting gain
on remeasurement to fair value of the previously held equity interest in CNX
Gathering and CNXM of  $624 million was included in the Gain on Previously Held
Equity Interest line of the Consolidated Statements of Income in the 2018 period
and was part of CNX's unallocated expenses. No such transactions occurred in the
current period. Prior to the acquisition, CNX accounted for its interests in CNX
Gathering and CNXM as an equity-method investment.

CNX's Midstream Division had earnings before income tax of $167 million for the
year ended December 31, 2019, compared to earnings before income tax of $134
million for the period from January 3, 2018 through December 31, 2018.
E&P Division Summary
Sales volumes, average sales prices (including the effects of settled
derivatives instruments), and average costs for the E&P Division were as
follows:
                                                        For the Years Ended December 31,
                                                                                          Percent
                                                  2019           2018       Variance       Change
Sales Volume (Bcfe)                               539.1          507.1          32.0         6.3  %

Average Sales Price - Gas (per Mcf)           $    2.48$   2.97$   (0.49 )     (16.5 )%
Gain (Loss) on Commodity Derivative
Instruments - Cash Settlement- Gas (per Mcf)  $    0.14$  (0.15 )$    0.29       193.3  %
Average Sales Price - NGLs (per Mcfe)*        $    3.20$   4.55$   (1.35 )     (29.7 )%
Average Sales Price - Oil (per Mcfe)*         $    8.13$   9.89$   (1.76 )     (17.8 )%
Average Sales Price - Condensate (per Mcfe)*  $    7.47$   8.43$   (0.96 )     (11.4 )%

Average Sales Price (per Mcfe)                $    2.66$   2.97$   (0.31 )     (10.4 )%
Lease Operating Expense (per Mcfe)                 0.12           0.19         (0.07 )     (36.8 )%
Production, Ad Valorem, and Other Fees (per
Mcfe)                                              0.05           0.06         (0.01 )     (16.7 )%
Transportation, Gathering and Compression
(per Mcfe)                                         0.96           0.84          0.12        14.3  %
Depreciation, Depletion and Amortization
(DD&A) (per Mcfe)                                  0.87           0.89         (0.02 )      (2.2 )%
Average Costs (per Mcfe)                      $    2.00$   1.98$    0.02         1.0  %
Average Margin (per Mcfe)                     $    0.66$   0.99$   (0.33 )     (33.3 )%


* 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.

Excluding the effects of settled derivative instruments, natural gas, NGLs, and
oil revenue was $1,364 million for the year ended December 31, 2019, compared to
$1,578 million for the year ended December 31, 2018. The decrease was primarily
due to the 10.4% decrease in the average sales price driven by lower natural gas
and NGL prices offset in-part by the 6.3% increase in total sales volumes.

The 6.3% increase in total sales volumes was primarily due to additional natural
gas wells that were turned-in-line in the latter half of the 2018 period as well
as throughout the 2019 period.

The decrease in average sales price was primarily the result of a $0.49 per Mcf
decrease in general natural gas prices, when excluding the impact of hedging, in
the markets in which CNX sells its natural gas. There was also a $0.09 per Mcfe
decrease in the uplift from NGLs and condensate sales volumes when excluding the
impact of hedging. Both decreases were offset, in part,


                                       38
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by a $0.29 per Mcf increase in the realized gain (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:
•      Transportation, gathering and compression expense increased on a per unit
       basis primarily due to an increase in CNXM gathering fees related to an
       increase in our Marcellus production and an increase in firm
       transportation expense, primarily as a result of new contracts that give

CNX the ability to move and sell gas outside of the Appalachian basin. The

decrease in production from CNX's lower cost dry Utica volumes as well as

the third quarter 2018 sale of CNX's Ohio JV assets also contributed to

the increase on a per unit basis. 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.

• Lease operating expense decreased on a per unit basis primarily due to a

decrease in water disposal costs in the period-to-period comparison due to

an increase in the reuse of produced water in well completions in the

current period, and also due to the sale of the majority of CNX's shallow

       oil and gas assets and the sale of substantially all of CNX's Ohio Utica
       JV assets in 2018.


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.

                                                         For the Years Ended December 31,
                                                                                             Percent
 in thousands (unless noted)                     2019            2018          Variance       Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)                              32,571          36,489         (3,918 )     (10.7 )%
Sales Volume (Mbbls)                               5,428           6,081           (653 )     (10.7 )%
Gross Price ($/Bbl)                          $     19.20$     27.30$    (8.10 )     (29.7 )%
Gross Revenue                                $   104,139$   165,883$  (61,744 )     (37.2 )%

Oil:
Sales Volume (MMcfe)                                  52             307           (255 )     (83.1 )%
Sales Volume (Mbbls)                                   9              51            (42 )     (82.4 )%
Gross Price ($/Bbl)                          $     48.78$     59.34$   (10.56 )     (17.8 )%
Gross Revenue                                $       422$     3,036$   (2,614 )     (86.1 )%

Condensate:
Sales Volume (MMcfe)                               1,171           2,082           (911 )     (43.8 )%
Sales Volume (Mbbls)                                 195             347           (152 )     (43.8 )%
Gross Price ($/Bbl)                          $     44.82$     50.58$    (5.76 )     (11.4 )%
Gross Revenue                                $     8,751$    17,559$   (8,808 )     (50.2 )%

GAS
Sales Volume (MMcf)                              505,355         468,226         37,129         7.9  %
Sales Price ($/Mcf)                          $      2.48$      2.97$    (0.49 )     (16.5 )%
Gross Revenue                                $ 1,251,013$ 1,391,459$ (140,446 )     (10.1 )%

Hedging Impact ($/Mcf)                       $      0.14$     (0.15 )$     0.29       193.3  %
Gain (Loss) on Commodity Derivative
Instruments - Cash Settlement                $    69,780$   (69,720 )$  139,500       200.1  %


Selling, General and Administrative ("SG&A") - Total Company


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



                                       39
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                                                         For the Years Ended December 31,
                                                                                         Percent
 (in millions)                                      2019        2018       Variance      Change
SG&A
Long-Term Equity-Based Compensation (Non-Cash)   $     38$    21$     17        81.0  %
Salaries and Wages                                     40          40            -           -  %
Short-Term Incentive Compensation                      21          24           (3 )     (12.5 )%
Other                                                  45          50           (5 )     (10.0 )%
Total SG&A                                       $    144$   135$      9         6.7  %



•      Long-term equity-based compensation increased $17 million in the

period-to-period comparison due to the Company incurring an additional $20

million of long-term equity-based compensation (non-cash) expense during

the year ended December 31, 2019. The additional expense was a result of

the acceleration of vesting of certain pre-2019 restricted stock units and

performance share units held by certain employees related to the trigger

of a contractual change in control event. See Note 17 - Stock-Based

Compensation in the Notes to the Audited Consolidated Financial Statements

in Item 8 of this Form 10-K for additional information. The remaining

variance was due to various items that occurred throughout both periods,

none of which were individually material.

• Short-term incentive compensation decreased $3 million due to a reduction

in the number of employees and lower projected payouts in the current

       period.



Unallocated Expense

Certain costs and expenses, such as other expense (income), 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 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 (Income)
                                          For the Years Ended December 31,
                                                                           Percent
 (in millions)                         2019          2018      Variance     Change
Other Income
Royalty Income                   $    4$  15$    (11 )   (73.3 )%
Right of Way Sales                    9                14           (5 )   (35.7 )%
Interest Income                       2                 -            2     100.0  %
Other                                 4                 8           (4 )   (50.0 )%
Total Other Income               $   19$  37$    (18 )   (48.6 )%

Other Expense
Bank Fees                        $    9$  11$     (2 )   (18.2 )%
Professional Services                 4                 7           (3 )   (42.9 )%
Other Land Rental Expense             4                 4            -         -  %
Other Corporate Expense               3                 -            3     100.0  %
Total Other Expense              $   20$  22$     (2 )    (9.1 )%

    Total Other Expense (Income) $    1$ (15 )$     16

106.7 %




Also refer to Other Expense contained in the section "Total Midstream Division
Analysis" of this item of this Form 10-K for additional items that are not part
of Unallocated Expense.

Gain on Asset Sales and Abandonments, net


A gain on asset sales of $42 million related to non-core assets was recognized
in the year ended December 31, 2019 compared to a gain of $155 million in the
year ended December 31, 2018, primarily due to the $131 million gain that was
recognized related


                                       40
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to the sale of substantially all of CNX's Ohio Utica JV assets as well as the
sale of various other non-core assets in the 2018 period. See Note 6 -
Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for additional information.

Also refer to the discussion of Loss (Gain) on Asset Sales and Abandonments, net contained in the section "Total Midstream Division Analysis" below for additional items that are not part of Unallocated Expense.

Gain on Previously Held Equity Interest


CNX recognized a gain on previously held equity interest of $624 million in the
year ended December 31, 2018 due to the Midstream Acquisition that occurred in
January 2018. No such transactions occurred in the current period. 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 $8 million was recognized in the year ended
December 31, 2019 compared to a loss on debt extinguishment of $54 million in
the year ended December 31, 2018. During the year ended December 31, 2019, CNX
purchased $400 million of its 5.875% senior notes due in April 2022 at an
average price equal to 101.5% of the principal amount. During the year ended
December 31, 2018, CNX purchased $411 million of its 5.875% senior notes due in
April 2022 at an average price equal to 103.5% of the principal amount and
redeemed the $500 million 8.00% senior notes due in April 2023 at a call price
equal to 106.0% of the principal amount. See Note 14 - Long-Term Debt in the
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form
10-K for additional information.

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

In connection with the AEA with HG Energy (See Note 6 - Acquisitions and
Dispositions in the Notes to the Audited Consolidated Financial Statements in
Item 8 of this Form 10-K for additional information) that occurred during the
year ended December 31, 2018, CNX determined that the carrying value of the
other intangible asset - customer relationship exceeded its fair value, and an
impairment of $19 million was included in Impairment of Other Intangible Assets
in the Consolidated Statement of Income. No such transactions occurred in the
current period.

Income Taxes

The effective income tax rate was 46.5% for the year ended December 31, 2019,
compared to 19.6% for the year ended December 31, 2018. The effective rate for
the year ended December 31, 2019 differs from the U.S. federal statutory rate of
21% primarily due to state income taxes, equity compensation and state valuation
allowances partially offset by the benefit from non-controlling interest. During
the year ended December 31, 2018, CNX obtained a controlling interest in CNX
Gathering LLC and, through CNX Gathering's ownership of the general partner,
control over CNXM. All of CNXM's income is included in the Company's pre-tax
income. However, the Company is not required to record income tax expense with
respect to the portions of CNXM's income allocated to the noncontrolling public
limited partners of CNXM, which reduces the Company's effective tax rate in
periods when the Company has consolidated pre-tax income and increases the
Company's effective tax rate in periods when the Company has consolidated
pre-tax loss. The effective rate for the year ended December 31, 2018 differs
from the U.S. federal statutory 21% primarily due to a benefit from the filing
of a Federal 10-year net operating loss ("NOL") carryback which resulted in the
Company being able to utilize previously valued tax attributes at a tax rate
differential of 14%, noncontrolling interest, the reversal of the alternative
minimum tax ("AMT") credit sequestration valuation allowance, and the release of
certain state valuation allowances as a result of a corporate reorganization
during the year.

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

                                       41
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                                               For the Years Ended December 31,
                                                                              Percent
(in millions)                              2019        2018       Variance     Change

Total Company Earnings Before Income Tax $ 60$ 1,099$ (1,039 )

  (94.5 )%
Income Tax Expense                       $   28$   216$   (188 )   (87.0 )%
Effective Income Tax Rate                  46.5 %       19.6 %       26.9 %




                                       42
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TOTAL E&P DIVISION ANALYSIS for the year ended December 31, 2019 compared to the
year ended December 31, 2018:
The E&P division had a loss before income tax of $140 million for the year ended
December 31, 2019 compared to earnings before income tax of $245 million for the
year ended December 31, 2018. Variances by individual operating segment are
discussed below.
                                     For the Year Ended                                       Difference to Year Ended
                                      December 31, 2019December 31, 2018
                                                         Other                                                      Other

(in millions) Marcellus Utica CBM Gas Total

     Marcellus     Utica       CBM        Gas       Total
Natural Gas,
NGLs and Oil
Revenue          $       935$   264$  164$    1$ 1,364$      32$ (182 )$  (49 )$  (15 )$ (214 )
Gain on
Commodity
Derivative
Instruments               47          15          7        307         376            87         35         16        268        406
Purchased Gas
Revenue                    -           -          -         94          94             -          -          -         28         28
Other Operating
Income                     -           -          -         14          14             -          -          -        (13 )      (13 )
Total Revenue
and Other
Operating Income         982         279        171        416       1,848 

119 (147 ) (33 ) 268 207 Lease Operating Expense

                   33          16         16          -          65            (8 )      (14 )       (6 )       (2 )      (30 )
Production, Ad
Valorem, and
Other Fees                15           6          7         (1 )        27            (3 )       (1 )        -         (2 )       (6 )
Transportation,
Gathering and
Compression              444          33         40          -         517           124        (19 )       (8 )       (4 )       93
Depreciation,
Depletion and
Amortization             256         136         73          9         474            26         (7 )       (4 )       (2 )       13
Impairment of
Exploration and
Production
Properties                 -           -          -        327         327             -          -          -        327        327
Impairment of
Unproved
Properties and
Expirations                -           -          -        119         119             -          -          -        119        119
Exploration and
Production
Related Other
Costs                      -           -          -         44          44             -          -          -         32         32
Purchased Gas
Costs                      -           -          -         91          91             -          -          -         26         26
Other Operating
Expense                    -           -          -         79          79             -          -          -          7          7
Selling, General
and
Administrative
Costs                      -           -          -        124         124             -          -          -         12         12
Total Operating
Costs and
Expenses                 748         191        136        792       1,867  

139 (41 ) (18 ) 513 593 Interest Expense

           -           -          -        121         121             -          -          -         (1 )       (1 )
Total E&P
Division Costs           748         191        136        913       1,988           139        (41 )      (18 )      512        592
Earnings (Loss)
from Continuing
Operations
Before Income
Tax              $       234$    88$   35$ (497 )$  (140 )$     (20 )$ (106 )$  (15 )$ (244 )$ (385 )



Note: Included in the table above is a related party transportation, gathering
and compression charge of $233 million that is offset in the Midstream Division
in Midstream Revenue - Related Party. Of this charge, $227 million related to
Marcellus and $6 million related to Utica. See Note 24 - Segment Information in
the Notes to the Audited Consolidated Financial Statements in Item 8 of this
Form 10-K for additional information.



                                       43
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MARCELLUS SEGMENT
The Marcellus segment had earnings before income tax of $234 million for the
year ended December 31, 2019 compared to earnings before income tax of $254
million for the year ended December 31, 2018.
                                                            For the Years Ended December 31,
                                                                                             Percent
                                                        2019         2018       Variance     Change
Marcellus Gas Sales Volumes (Bcf)                      336.1         255.1         81.0       31.8  %
NGLs Sales Volumes (Bcfe)*                              32.5          31.4          1.1        3.5  %
Condensate Sales Volumes (Bcfe)*                         1.1           1.7         (0.6 )    (35.3 )%
Total Marcellus Sales Volumes (Bcfe)*                  369.7         288.2  

81.5 28.3 %


Average Sales Price - Gas (per Mcf)                 $   2.45$  2.93$  (0.48 )    (16.4 )%
Gain (Loss) on Commodity Derivative Instruments -
Cash Settlement- Gas (per Mcf)                      $   0.14$ (0.16 )$   0.30      187.5  %
Average Sales Price - NGLs (per Mcfe)*              $   3.20$  4.55$  (1.35 )    (29.7 )%
Average Sales Price - Condensate (per Mcfe)*        $   7.41$  8.32

$ (0.91 ) (10.9 )%

Total Average Marcellus Sales Price (per Mcfe) $ 2.66$ 2.99

    $  (0.33 )    (11.0 )%
Average Marcellus Lease Operating Expenses (per
Mcfe)                                                   0.09          0.14  

(0.05 ) (35.7 )% Average Marcellus Production, Ad Valorem, and Other Fees (per Mcfe)

                                         0.04          0.07        (0.03 )    (42.9 )%
Average Marcellus Transportation, Gathering and
Compression Costs (per Mcfe)                            1.20          1.11         0.09        8.1  %
Average Marcellus Depreciation, Depletion and
Amortization Costs (per Mcfe)                           0.70          0.79  

(0.09 ) (11.4 )%

Total Average Marcellus Costs (per Mcfe) $ 2.03$ 2.11

$ (0.08 ) (3.8 )%

  Average Margin for Marcellus (per Mcfe)           $   0.63$  0.88

$ (0.25 ) (28.4 )%



* 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 $935 million for
the year ended December 31, 2019 compared to $903 million for the year ended
December 31, 2018. The $32 million increase was due to a 28.3% increase in total
Marcellus sales volumes. The increase in sales volumes was primarily due to
additional wells being turned in-line throughout 2018 and 2019 as part of the
Company's ongoing drilling and completions program.

The decrease in the total average Marcellus sales price was primarily due to a
$0.48 per Mcf decrease in average sales price for natural gas and a $1.35 per
Mcfe decrease in the average NGL sales price, offset in part by a $0.30 per Mcf
increase in the realized gain (loss) on commodity derivative instruments
resulting from the Company's hedging program. The notional amounts associated
with these financial hedges represented approximately 264.8 Bcf of the Company's
produced Marcellus gas sales volumes for the year ended December 31, 2019 at an
average gain of $0.18 per Mcf. For the year ended December 31, 2018, these
financial hedges represented approximately 206.7 Bcf at an average loss of $0.20
per Mcf.

Total operating costs and expenses for the Marcellus segment were $748 million
for the year ended December 31, 2019 compared to $609 million for the year ended
December 31, 2018. The increase in total dollars and decrease in unit costs for
the Marcellus segment were due primarily to the following items:

•Marcellus lease operating expenses were $33 million for the year ended
December 31, 2019 compared to $41 million for the year ended December 31, 2018.
The decrease in total dollars was primarily due to a decrease in water disposal
costs in the current period due to an increase in the reuse of produced water in
well completions activity, as well as a reduction in employee costs. The
decrease in unit costs was driven by the decrease in total dollars, along with
the 28.3% increase in total Marcellus sales volumes.

•Marcellus production, ad valorem, and other fees were $15 million for the year
ended December 31, 2019 compared to $18 million for the year ended December 31,
2018. The decrease in total dollars was primarily related to a decrease in CNX's
severance tax liability due to the production mix by state and lower natural gas
prices. The decrease in unit costs was driven by the decreased total dollars,
along with the 28.3% increase in total Marcellus sales volumes.



                                       44
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•Marcellus transportation, gathering and compression costs were $444 million for
the year ended December 31, 2019 compared to $320 million for the year ended
December 31, 2018. The $124 million increase in total dollars was primarily
related to an increase in both CNX Midstream fees as well as an increase in
utilized firm transportation expense. The increase in firm transportation total
dollars was related to new contracts undertaken in 2019 that give CNX the
ability to move and sell natural gas outside of the Appalachian basin. The
increase in CNXM fees was due to annual rate escalation as well as additional
compression. These increases were offset by lower processing costs due to a
drier production mix. The increase in unit costs was driven by the increased
total dollars described above.

•Depreciation, depletion and amortization costs attributable to the Marcellus
segment were $256 million for the year ended December 31, 2019 compared to $230
million for the year ended December 31, 2018. These amounts included depletion
on a unit of production basis of $0.68 per Mcfe and $0.79 per Mcfe,
respectively. The decrease in units of production depreciation, depletion and
amortization rate is the result of positive reserve revisions within the
Company's core development area in the current year. The remaining depreciation,
depletion and amortization costs were either recorded on a straight-line basis
or related to asset retirement obligations.

UTICA SEGMENT


The Utica segment had earnings before income tax of $88 million for the year
ended December 31, 2019 compared to earnings before income tax of $194 million
for the year ended December 31, 2018.
                                                           For the Years Ended December 31,
                                                                                           Percent
                                                       2019        2018       Variance     Change
Utica Gas Sales Volumes (Bcf)                          113.7       148.1        (34.4 )    (23.2 )%
NGLs Sales Volumes (Bcfe)*                                 -         5.1         (5.1 )   (100.0 )%
Oil Sales Volumes (Bcfe)*                                  -         0.1         (0.1 )   (100.0 )%
Condensate Sales Volumes (Bcfe)*                         0.1         0.4         (0.3 )    (75.0 )%
Total Utica Sales Volumes (Bcfe)*                      113.8       153.7    

(39.9 ) (26.0 )%


Average Sales Price - Gas (per Mcf)                 $   2.32$  2.82$  (0.50 )    (17.7 )%
Gain (Loss) on Commodity Derivative Instruments -
Cash Settlement- Gas (per Mcf)                      $   0.13$ (0.13 )$   0.26      200.0  %
Average Sales Price - NGLs (per Mcfe)*              $      -     $  4.54$  (4.54 )   (100.0 )%
Average Sales Price - Oil (per Mcfe)*               $      -     $  9.46$  (9.46 )   (100.0 )%
Average Sales Price - Condensate (per Mcfe)*        $   8.80$  8.96

$ (0.16 ) (1.8 )%

Total Average Utica Sales Price (per Mcfe) $ 2.46$ 2.77

  $  (0.31 )    (11.2 )%
Average Utica Lease Operating Expenses (per Mcfe)       0.14        0.19        (0.05 )    (26.3 )%
Average Utica Production, Ad Valorem, and Other
Fees (per Mcfe)                                         0.05        0.05            -          -  %
Average Utica Transportation, Gathering and
Compression Costs (per Mcfe)                            0.29        0.34        (0.05 )    (14.7 )%
Average Utica Depreciation, Depletion and
Amortization Costs (per Mcfe)                           1.21        0.93    

0.28 30.1 %

  Total Average Utica Costs (per Mcfe)              $   1.69$  1.51

$ 0.18 11.9 %

  Average Margin for Utica (per Mcfe)               $   0.77$  1.26

$ (0.49 ) (38.9 )%



*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 $264 million for the
year ended December 31, 2019 compared to $446 million for the year ended
December 31, 2018. The $182 million decrease was due to the 26.0% decrease in
total Utica sales volumes and a 17.7% decrease in the average sales price for
natural gas. The decrease in total Utica sales volumes was primarily due to the
sale of substantially all of CNX's Ohio Utica JV assets in the third quarter of
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) as well as normal production declines in the remaining dry Utica
wells.

The decrease in total average Utica sales price was primarily due to a $0.50 per
Mcf decrease in average gas sales price. Additionally, there was a $0.07 per
Mcfe decrease in the uplift from NGLs and condensate sales volumes when
excluding the


                                       45
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impact of hedging due to the sale of the previously mentioned Ohio JV assets in
the third quarter of 2018, which consisted primarily of wet Utica production.
The decreases were partially offset by a $0.26 per Mcf increase in the realized
gain (loss) on commodity derivative instruments. The notional amounts associated
with these financial hedges represented approximately 83.3 Bcf of the Company's
produced Utica gas sales volumes for the year ended December 31, 2019 at an
average gain of $0.18 per Mcf. For the year ended December 31, 2018, these
financial hedges represented approximately 101.6 Bcf at an average loss of $0.20
per Mcf.

Total operating costs and expenses for the Utica segment were $191 million for
the year ended December 31, 2019 compared to $232 million for the year ended
December 31, 2018. The decrease in total dollars and increase in unit costs for
the Utica segment were due to the following items:

•Utica lease operating expenses were $16 million for the year ended December 31,
2019, compared to $30 million for the year ended December 31, 2018. The decrease
in total dollars was primarily due to a decrease in water disposal costs due to
lower production volumes, an increase in reuse of produced water in well
completions and a reduction in well operating costs due to the overall decrease
in Utica volumes described above. The decrease in unit costs was driven by the
decrease in total dollars.

•Utica transportation, gathering and compression costs were $33 million for the
year ended December 31, 2019 compared to $52 million for the year ended
December 31, 2018. The $19 million decrease in total dollars and $0.05 per Mcfe
decrease in unit costs were both due to the overall decrease in Utica volumes as
well as the shift to lower cost dry Utica production.

•Depreciation, depletion and amortization costs attributable to the Utica
segment were $136 million for the year ended December 31, 2019 compared to $143
million for the year ended December 31, 2018. These amounts included depletion
on a unit of production basis of $1.17 per Mcfe and $0.93 per Mcfe,
respectively. The increase in the units of production depreciation, depletion
and amortization rate was due to negative reserve revisions, an increase in
capital expenditures and a higher depreciation, depletion and amortization rate
on deep dry Utica wells compared to the lower capital cost Utica wells which
were part of the Ohio JV asset sale in 2018. The remaining depreciation,
depletion and amortization costs were either recorded on a straight-line basis
or related to asset retirement obligations.

COALBED METHANE (CBM) SEGMENT


The CBM segment had earnings before income tax of $35 million for the year ended
December 31, 2019 compared to earnings before income tax of $50 million for the
year ended December 31, 2018.
                                                            For the Years Ended December 31,
                                                                                             Percent
                                                        2019         2018       Variance     Change
CBM Gas Sales Volumes (Bcf)                             55.4          60.3         (4.9 )     (8.1 )%

Average Sales Price - Gas (per Mcf)                 $   2.96$  3.53$  (0.57 )    (16.1 )%
Gain (Loss) on Commodity Derivative Instruments -
Cash Settlement- Gas (per Mcf)                      $   0.13       $ (0.15 

) $ 0.28 186.7 %


Total Average CBM Sales Price (per Mcf)             $   3.09$  3.39$  (0.30 )     (8.8 )%
Average CBM Lease Operating Expenses (per Mcf)          0.29          0.37  

(0.08 ) (21.6 )% Average CBM Production, Ad Valorem, and Other Fees (per Mcf)

                                               0.12          0.12            -          -  %
Average CBM Transportation, Gathering and
Compression Costs (per Mcf)                             0.73          0.80        (0.07 )     (8.8 )%
Average CBM Depreciation, Depletion and
Amortization Costs (per Mcf)                            1.32          1.28         0.04        3.1  %
  Total Average CBM Costs (per Mcf)                 $   2.46$  2.57$  (0.11 )     (4.3 )%
  Average Margin for CBM (per Mcf)                  $   0.63$  0.82$  (0.19 )    (23.2 )%



The CBM segment had natural gas revenue of $164 million for the year ended
December 31, 2019 compared to $213 million for the year ended December 31, 2018.
The $49 million decrease was due to an 8.1% decrease in total CBM sales volumes
and the 16.1% decrease in the average gas sales price. The decrease in CBM sales
volumes was primarily due to normal well declines, as well as the sale of
certain CBM assets that were sold along with the majority of CNX's shallow oil
and gas assets in 2018 (See Note 6 - Acquisitions and Dispositions in the Notes
to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for
additional information).



                                       46
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The total average CBM sales price decreased $0.30 per Mcf due to a $0.57 per Mcf
decrease in average gas sales price, offset in part by a $0.28 per Mcf increase
in the gain (loss) on commodity derivative instruments resulting from the
Company's hedging program. The notional amounts associated with these financial
hedges represented approximately 40.9 Bcf of the Company's produced CBM sales
volumes for the year ended December 31, 2019 at an average gain of $0.18 per
Mcf. For the year ended December 31, 2018, these financial hedges represented
approximately 44.8 Bcf at an average loss of $0.20 per Mcf.

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

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

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

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

OTHER GAS SEGMENT
The Other Gas segment had a loss before income tax of $497 million for the year
ended December 31, 2019 compared to a loss before income tax of $253 million for
the year ended December 31, 2018.
                                          For the Years Ended December 31,
                                                                          Percent
                                        2019         2018    Variance     Change
Other Gas Sales Volumes (Bcf)       0.3               4.7       (4.4 )    (93.6 )%
Oil Sales Volumes (Bcfe)*             -               0.2       (0.2 )   (100.0 )%
Total Other Sales Volumes (Bcfe)*   0.3               4.9       (4.6 )    

(93.9 )%



*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 unrealized gain or loss on commodity
derivative instruments, purchased gas activity, exploration and production
related other costs, impairment of exploration and production properties,
impairment of unproved properties and expirations, and other operational
activity not assigned to a specific segment.

Other Gas sales volumes were primarily related to shallow oil and gas
production. CNX sold substantially all of these assets on March 30, 2018 (See
Note 6 - Acquisitions and Dispositions of the Notes to the Audited Consolidated
Financial Statements in Item 8 of this Form 10-K for additional information).
There was $1 million of natural gas and oil revenue related to the Other Gas
segment for the year ended December 31, 2019 compared to $16 million for the
year ended December 31, 2018. Total operating costs and expenses related to
these other gas sales volumes were $5 million for the year ended December 31,
2019 compared to $18 million for the year ended December 31, 2018. The decrease
in natural gas and oil revenue was due to the asset sale.

Unrealized Gain or Loss on Commodity Derivative Instruments


The Other Gas segment recognized an unrealized gain on commodity derivative
instruments of $306 million as well as cash settlements received of $1 million
for the year ended December 31, 2019. For the year ended December 31, 2018, the
Company recognized an unrealized gain on commodity derivative instruments of $40
million as well as cash settlements paid of $1 million. The unrealized gain or
loss on commodity derivative instruments represents changes in the fair value of
all the Company's existing commodity hedges on a mark-to-market basis.





                                       47
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Purchased Gas


Purchased gas volumes represent volumes of gas purchased at market prices from
third-parties and then resold in order to fulfill contracts with certain
customers and to balance supply. Purchased gas revenues were $94 million for the
year ended December 31, 2019 compared to $66 million for the year ended
December 31, 2018. Purchased gas costs were $91 million for the year ended
December 31, 2019 compared to $65 million for the year ended December 31, 2018.
The period-to-period increase in purchased gas revenue was due to an increase in
purchased gas sales volumes, offset in part by a decrease in average sales
price.
                                             For the Years Ended December 31,
                                                                             Percent
                                          2019         2018      Variance     Change
Purchased Gas Sales Volumes (in Bcf)     40.6           20.5        20.1      98.0  %
Average Sales Price (per Mcf)        $   2.32$ 3.23$  (0.91 )   (28.2 )%
Average Cost (per Mcf)               $   2.23$ 3.17$  (0.94 )   (29.7 )%



Other Operating Income

Other operating income was $14 million for the year ended December 31, 2019 compared to $27 million for the year ended December 31, 2018. The $13 million decrease was due to the following items:

                                          For the Years Ended December 31,
                                                                            Percent
(in millions)                          2019           2018     Variance     Change
Water Income                     $    2$  11$     (9 )    (81.8 )%
Equity in Earnings of Affiliates      2                  5          (3 )    (60.0 )%
Gathering Income                     10                 10           -          -  %
Other                                 -                  1          (1 )   (100.0 )%
Total Other Operating Income     $   14$  27$    (13 )    (48.1 )%


• Water income decreased $9 million due to nominal sales of freshwater to

third parties for hydraulic fracturing in 2019 compared to 2018.




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

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

For the year ended December 31, 2019, CNX recorded an impairment related to unproved properties of $119 million that was included in Impairment of Unproved Properties and Expirations in the Consolidated Statements of Income. These unproved

                                       48
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properties are within CNX's CPA operating region and east of the acreage associated with the proved property impairment described above.


Exploration and Production Related Other Costs
Exploration and production related other costs were $44 million for the year
ended December 31, 2019 compared to $12 million for the year ended December 31,
2018. The $32 million increase was due to the following items:
                                                      For the Years Ended December 31,
                                                                                           Percent
(in millions)                               2019            2018           Variance        Change
Lease Expiration Costs                  $        31     $         5     $        26         520.0  %
Seismic Activity                                  8               -               8         100.0  %
Land Rentals                                      3               4              (1 )       (25.0 )%
Other                                             2               3              (1 )       (33.3 )%
Total Exploration and Production
Related Other Costs                     $        44$        12$        32         266.7  %


• Lease Expiration Costs relate to leases where the primary term expired or

will expire within the next 12 months. The $26 million increase in the

period-to-period comparison is due to an increase in the number of leases

that were allowed to expire in the year ended December 31, 2019, or will

expire within the next 12 months, because they were no longer in the

Company's future drilling plan. Additionally, approximately $15 million of

       the $26 million increase is associated with leases which have ceased
       production.


•      Seismic activity increased in the period-to-period comparison due to

additional geophysical research in the current period related to the Utica

       segment.



Other Operating Expenses
Other operating expense was $79 million for the year ended December 31, 2019
compared to $72 million for the year ended December 31, 2018. The $7 million
increase was due to the following items:
                                                      For the Years Ended December 31,
                                                                                           Percent
                                            2019            2018           Variance        Change
Unutilized Firm Transportation and
Processing Fees                         $        55$        42$        13          31.0  %
Idle Equipment and Service Charges               12               5               7         140.0  %
Insurance Expense                                 4               3               1          33.3  %
Severance Expense                                 1               1               -             -  %
Litigation Expense                                -               4              (4 )      (100.0 )%
Water Expense                                     -               6              (6 )      (100.0 )%
Other                                             7              11              (4 )       (36.4 )%
Total Other Operating Expense           $        79$        72     $         7           9.7  %


• Unutilized Firm Transportation and Processing Fees represent pipeline

transportation capacity obtained to enable gas production to flow

uninterrupted as sales volumes increase, as well as additional processing

capacity for NGLs. The increase in the period-to-period comparison was

primarily due to previously-acquired capacity which was not utilized

during the current period to transport the Company's flowing production.

In some instances, the Company may have the opportunity to realize more

favorable net pricing by strategically choosing to sell natural gas into a

market or to a customer that does not require the use of the Company's own

firm transportation capacity. Such sales would increase unutilized firm

transportation expense. The Company attempts to minimize this expense by

       releasing (selling) unutilized firm transportation capacity to other
       parties when possible and when beneficial. The revenue received when this
       capacity is released (sold) is included in Gathering Income in Total Other
       Operating Income above. There were no unutilized fees related to the
       Midstream Division for 2018 or 2019.

• Idle Equipment and Service Charges primarily relate to the temporary

idling of some of the Company's natural gas drilling rigs as well as

related equipment and other services that may be needed in the natural gas

       drilling and completions process. The increase of $7 million in the
       period-to-period comparison was primarily the result CNX terminating one
       of its drilling




                                       49
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rig contracts early, as well as additional idle service expense related to the Shaw 1G Utica Shale well that occurred in the first quarter of 2019. • Water Expense decreased $6 million due to the associated costs related to

the sales of freshwater to third-parties for hydraulic fracturing during

       2018 in Total Other Operating Income above. There were nominal sales
       during 2019.


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 $124 million for the year ended December 31, 2019
compared to $112 million for the year ended December 31, 2018. Refer to the
discussion of total Company SG&A costs contained in the section "Net (Loss)
Income Attributable to CNX Resources Shareholders" within this Item 7 of this
Form 10-K for a detailed cost explanation.

Interest Expense


Interest expense of $121 million was recognized in the year ended December 31,
2019 compared to $122 million in the year ended December 31, 2018. The $1
million decrease was primarily due to the reduction in higher cost long-term
debt, resulting from the $500 million purchase of the outstanding 8.00% senior
notes due in April 2023 and the $411 million purchase of the outstanding 5.875%
senior notes due in April 2022 during the year ended December 31, 2018.
Additionally, the Company purchased $400 million of its outstanding 5.875%
senior notes due in April 2022 during the year ended December 31, 2019. These
decreases were partially offset by a completed private offering of $500 million
of 7.25% senior notes due March 2027 during the year ended December 31, 2019, as
well as additional borrowings on the CNX credit facility. 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.


                                       50
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TOTAL MIDSTREAM DIVISION ANALYSIS for the year ended December 31, 2019 compared to 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 both
the general partner and limited partner interests 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 began
consolidating CNXM on January 3, 2018.
                                                                         For the
                                                                         period
                                                      For the Year     January 3,
                                                          Ended       2018 through
                                                      December 31,    December 31,
 (in millions)                                            2019            2018           Variance
Midstream Revenue - Related Party                     $       233$       168$        65
Midstream Revenue - Third Party                                74              90             (16 )
Total Revenue                                         $       307     $     

258 $ 49


Transportation, Gathering and Compression             $        47$        47     $         -
Depreciation, Depletion and Amortization                       34              32               2
Selling, General and Administrative Costs                      20              23              (3 )
Total Operating Costs and Expenses                            101             102              (1 )
Other Expense                                                   2               -               2
Loss (Gain) on Asset Sales and Abandonments, net                7              (2 )             9
Interest Expense                                               30              24               6
Total Midstream Division Costs                                140             124              16

Earnings from Continuing Operations Before Income Tax $ 167 $

  134     $        33



Midstream Revenue

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. Total
midstream revenue increased $49 million primarily due to a 21.3% increase in the
average rate for related party volumes as well as a14.2% increase in gathered
volumes of both dry and wet gas in the period-to-period comparison.

The table below summarizes volumes gathered by gas type:

                                                                For the
                                                                 period
                                                               January 3,
                                                   For the        2018
                                                  Year Ended    through
                                                   December     December
                                                   31, 2019     31, 2018     Variance
Dry Gas (BBtu/d) (*)                                   889          740          149
Wet Gas (BBtu/d) (*)                                   719          661           58
Other (BBtu/d) (*)(**)                                 221           73          148
Total Gathered Volumes                               1,829        1,474          355


(*) 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.


                                       51
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Transportation, Gathering and Compression


Transportation, Gathering and Compression costs were $47 million for both the
year ended December 31, 2019 and 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 electrically-powered
compression, compressor rental, repairs and maintenance, supplies, treating and
contract services.

Selling, General and Administrative Expense


SG&A expense is comprised of direct charges for the management and operation of
CNXM assets. SG&A costs were $20 million for the year ended December 31, 2019
compared to $23 million for the period January 3, 2018 through December 31,
2018. Refer to the discussion of total Company SG&A costs contained in the
section "Net (Loss) Income Attributable to CNX Resources Shareholders" above for
a detailed cost explanation.

Depreciation, Depletion and Amortization Expense

Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25 years to 40 years.

Loss (Gain) on Asset Sales and Abandonments, net


During the year ended December 31, 2019, CNXM abandoned the construction of a
compressor station that was designed to support additional production within
certain areas of what is referred to as their "Anchor Systems," incurring a loss
of $7 million that is included in Gain on Asset Sales and Abandonments, net in
the Consolidated Statements of Income. CNXM continues to evaluate projects as
CNX's and third-party customer development plans change in order to optimize
system design and to actively manage capital investments. 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 $30 million for the year ended December 31, 2019 compared to $24 million for
the period January 3, 2018 through December 31, 2018. The increase in the
period-to-period comparison was due to additional borrowings on the revolving
credit facility.


                                       52
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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, 2019, CNX had deferred tax liabilities in excess of
deferred tax assets of approximately $351 million. At December 31, 2019, CNX had
a valuation allowance of $125 million on deferred tax assets.

CNX evaluates all tax positions taken on the state and federal tax filings to
determine if the position is more likely than not to be sustained upon
examination. For positions that meet the more likely than not to be sustained
criteria, an evaluation of the largest amount of benefit, determined on a
cumulative probability basis that is more likely than not to be realized upon
ultimate settlement is determined. A previously recognized tax position is
reversed when it is subsequently determined that a tax position no longer meets
the more likely than not threshold to be sustained. The evaluation of the
sustainability of a tax position and the probable amount that is more likely
than not is based on judgment, historical experience and on various other
assumptions that we believe are reasonable under the circumstances. The results
of these estimates, that are not readily apparent from other sources, form the
basis for recognizing an uncertain tax liability. Actual results could differ
from those estimates upon subsequent resolution of identified matters. CNX has
no uncertain tax liabilities at December 31, 2019. 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


                                       53
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valuation allowance is established or increased or decreased during a period,
the Company must include an expense or benefit within tax expense in the income
statement. Future results of operations for any particular quarterly or annual
period could be materially affected by changes in the Company's assumptions.

Natural Gas, NGL, Condensate and Oil Reserve ("Natural Gas Reserve") Values


Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are
those quantities of oil and natural gas which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward, from known reservoirs and under existing
economic conditions, operating methods and government regulations prior to the
time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation.

There are numerous uncertainties inherent in estimating quantities and values of
economically recoverable natural gas reserves, including many factors beyond our
control. As a result, estimates of economically recoverable natural gas reserves
are by their nature uncertain. Information about our reserves consists of
estimates based on engineering, economic and geological data assembled and
analyzed by our staff. Our natural gas reserves are reviewed by independent
experts each year. Some of the factors and assumptions which impact economically
recoverable reserve estimates include:

• geological conditions;

• historical production from the area compared with production from other

producing areas;

• the assumed effects of regulations and taxes by governmental agencies;

• assumptions governing future prices; and


• future operating costs.



Each of these factors may in fact vary considerably from the assumptions used in
estimating reserves. For these reasons, estimates of the economically
recoverable quantities of gas attributable to a particular group of properties,
and classifications of these reserves based on risk of recovery and estimates of
future net cash flows, may vary substantially. Actual production, revenues and
expenditures with respect to our reserves will likely vary from estimates, and
these variances may be material. See "Risk Factors" in Item 1A of this Form 10-K
for a discussion of the uncertainties in estimating our reserves.

The Company believes that the accounting estimate related to oil and gas reserves is a "critical accounting estimate" because the Company must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the estimated timing of development expenditures. Future results of operations and strength of the balance sheet for any particular quarterly or annual period could be materially affected by changes in the Company's assumptions. See "Impairment of Long-lived Assets" below for additional information regarding the Company's oil and gas reserves.

Impairment of Long-lived Assets


The carrying values of the Company's proved oil and gas properties are reviewed
for impairment whenever events or changes in circumstances indicate that a
property's carrying amount may not be recoverable. Impairment tests require that
the Company first compare future undiscounted cash flows by asset group to their
respective carrying values. The Company groups its assets by geological and
geographical characteristics. If the carrying amount exceeds the estimated
undiscounted future cash flows, a reduction of the carrying amount of the
natural gas properties to their estimated fair values is required, which is
determined based on discounted cash flow techniques using a market-specific
weighted average cost of capital. For the year ended December 31, 2019, an
impairment of $327 million was included in Impairment of Exploration and
Production Properties in the Consolidated Statements of Income. This impairment
was related to 56 operated wells and approximately 51,000 acres within our CPA
Marcellus proved properties in Armstrong, Indiana, Jefferson and Westmoreland
counties.

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 $138 million 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, 2019, 2018 or 2017.


CNX evaluates capitalized costs of unproved gas properties for recoverability on
a prospective basis. Indicators of potential impairment include, but are not
limited to, changes brought about by economic factors, commodity price outlooks,
our geologists'


                                       54
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evaluation of the property, favorable or unfavorable activity on the property
being evaluated and/or adjacent properties, potential shifts in business
strategy employed by management and historical experience. If it is determined
that the properties will not yield proved reserves, the related costs are
expensed in the period the determination is made. For the year ended December
31, 2019, an impairment of $119 million was included in Impairment of Unproved
Properties and Expirations in the Consolidated Statements of Income. There were
no other impairments related to unproved properties in the years ended December
31, 2019, 2018 or 2017.

The Company believes that the accounting estimates related to the impairment of
long-lived assets are "critical accounting estimates" because the fair value
estimation process requires considerable judgment and determining the fair value
is sensitive to changes in assumptions impacting management's estimates of
future financial results. In addition, the Company must determine the estimated
undiscounted future cash flows as well as the impact of commodity price
outlooks. The Company believes the estimates and assumptions used in estimating
the fair value are reasonable and appropriate; however, different assumptions
and estimates, such as different assumptions in projected revenues, future
commodity prices or the weighted average costs of capital, could materially
impact the calculated fair value and the resulting determinations about the
impairment of long-lived assets which could materially impact the Company's
results of operations and financial position. Additionally, future estimates may
differ materially from current estimates and assumptions.

Impairment of Goodwill


In connection with the Midstream Acquisition that closed on January 3, 2018, CNX
recorded $796 million of goodwill. See Note 6 - Acquisitions and Dispositions
for more information in the Notes to the Audited Consolidated Financial
Statements in Item 8 of this Form 10-K for more information.

Goodwill is not amortized, but rather it is evaluated for impairment annually
during the fourth quarter, or more frequently if recent events or prevailing
conditions indicate it is more likely than not that the fair value of a
reporting unit is less than its carrying value. We may assess goodwill for
impairment by first performing a qualitative assessment, which considers
specific factors, based on the weight of evidence, and the significance of all
identified events and circumstances in the context of determining whether it is
more likely than not that the fair value of a reporting unit is less than its
carrying amount. If it is determined that it is more likely than not that the
fair value of a reporting unit is less than its carrying amount using the
qualitative assessment, we perform a quantitative impairment test. From time to
time, we may also bypass the qualitative assessment and proceed directly to the
quantitative impairment test. Under the quantitative goodwill impairment test,
the fair value of a reporting unit is compared to its carrying amount. If the
quantitative goodwill impairment test indicates that the goodwill is impaired,
an impairment loss is recorded, which is the difference between carrying value
of the reporting unit and its fair value, with the impairment loss not to exceed
the amount of goodwill recorded. The estimation of fair value of a reporting
unit is determined using the income approach and/or the market approach as
described below.

The income approach is a quantitative evaluation to determine the fair value of
the reporting unit. Under the income approach we determine the fair value based
on estimated future cash flows discounted by an estimated weighted-average cost
of capital plus a forecast risk, which reflects the overall level of inherent
risk of the reporting unit and the rate of return a market participant would
expect to earn. The inputs used for the income approach were significant
unobservable inputs, or Level 3 inputs, as described in the accounting fair
value hierarchy. CNX determined the fair value based on estimated future cash
flows and earnings before deducting net interest expense (interest expense less
interest income) and income taxes (EBITDA - a non-GAAP financial measure) and
also included estimates for capital expenditures, discounted to present value
using a risk-adjusted rate, which management feels reflects the overall level of
inherent risk of the reporting unit. Cash flow projections were derived from
board approved budgeted amounts, a five-year operating forecast and an estimate
of future cash flows. Subsequent cash flows were developed using growth or
contraction rates that management believes are reasonably likely to occur.

The market approach measures the fair value of a reporting unit through the
analysis of recent transactions and/or financial multiples of comparable
businesses. Consideration is given to the financial conditions and operating
performance of the reporting unit being valued relative to those publicly-traded
companies operating in the same or similar lines of business.

The determination of the fair value requires us to make significant estimates
and assumptions. These estimates and assumptions primarily include but are not
limited to: the selection of appropriate peer group companies; control premiums
appropriate for acquisitions in the industries in which we compete; discount
rates; terminal growth rates; and forecasts of revenue, operating income,
depreciation and amortization and capital expenditures. The estimates of future
cash flows and EBITDA are subjective in nature and are subject to impacts from
business risks as described in Part I. Item 1A. "Risk Factors" of this Form 10K.
The fair value estimation process requires considerable judgment and determining
the fair value is sensitive to changes in assumptions impacting management's
estimates of future financial results. Although we believe our estimates of fair
value are reasonable, actual financial results could differ from those estimates
due to the inherent uncertainty involved in making such


                                       55
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estimates. Changes in assumptions concerning future financial results or other
underlying assumptions could have a significant impact on either the fair value
of the reporting unit, the amount of any goodwill impairment charge, or both.

In connection with our annual assessment of goodwill in the fourth quarter of
2019, we bypassed the qualitative assessment and performed a quantitative test
that utilized a combination of the income and market approaches to estimate the
fair value of the Midstream reporting unit. As a result of this assessment, we
concluded that the estimated fair value exceeded carrying value, and accordingly
no adjustment to goodwill was necessary. However, the margin by which the fair
value of the Midstream reporting unit exceeded its carrying value was less than
10%. The fair value was estimated using an equal weighting of the income
approach and guideline public company market approach. In our income approach
analyses, CNX used a production forecast that included, amount other things,
estimates of gathered volumes based upon CNX's proved developed and proved
undeveloped reserves, as defined by the SEC, as well as forecasted production
declines for third-party customers. Revenue contraction was applied to the
terminal period. Had CNX used a discount rate that was 160 basis points higher
or a terminal growth rate that was 520 basis points lower than those assumed
under the income approach, the fair value of this reporting unit would have
continued to exceed its carrying amount. Had we more heavily weighed the market
approach in estimating the fair value of this reporting unit, the excess fair
value over the carrying amount would have increased.

As a result of the small margin by which the Midstream reporting unit's fair
value exceeded its carrying value, the reporting unit is susceptible to
impairment risk from further adverse macroeconomic conditions or other adverse
factors such as future gathering volumes being less than those currently
estimated. Any such adverse changes in the future could reduce the underlying
cash flows used to estimate fair values and could result in a decline in fair
value that could trigger future impairment charges relating to the Midstream
reporting unit.

The Company believes that the accounting estimates related to goodwill are
"critical accounting estimates" because the fair value estimation process
requires considerable judgment and determining the fair value is sensitive to
changes in assumptions impacting management's estimates of future financial
results. The fair value estimation process requires considerable judgment and
determining the fair value is sensitive to changes in assumptions impacting
management's estimates of future financial results as well as other assumptions
such as movement in the Company's stock price, weighted-average cost of capital,
terminal growth rates, changes in the business climate, unanticipated changes in
the competitive environment, adverse legal or regulatory actions or
developments, changes in capital structure, cost of debt, interest rates,
capital expenditure levels, operating cash flows, or market capitalization and
industry multiples. The Company believes the estimates and assumptions used in
estimating the fair value are reasonable and appropriate; however, different
assumptions and estimates could materially impact the calculated fair value and
the resulting determinations about goodwill impairment which could materially
impact the Company's results of operations and financial position. Additionally,
future estimates may differ materially from current estimates and assumptions.

Impairment of Definite-lived Intangible Assets


Definite-lived intangible assets are amortized on a straight-line basis over
their estimated economic lives and they are reviewed for impairment when
indicators of impairment are present. Impairment tests require that the Company
first compare future undiscounted cash flows to their respective carrying
values. If the carrying amount exceeds the estimated undiscounted future cash
flows, a reduction of the carrying amount of the asset to its estimated fair
value is required.

In May 2018, CNX determined that the carrying value of a portion of the customer
relationship intangible assets that were acquired in connection with the
Midstream acquisition exceeded their fair value in conjunction with the AEA with
HG Energy (See Note 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 $19
million, 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


                                       56
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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.

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. 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 for the
next fiscal year. Nevertheless, the ability of CNX to satisfy its working
capital requirements, to service its debt obligations, to fund planned capital
expenditures, or to pay dividends will depend upon future operating performance,
which will be affected by prevailing economic conditions in the natural gas
industry and other financial and business factors, some of which are beyond
CNX's control.

From time to time, CNX is required to post financial assurances to satisfy
contractual and other requirements generated in the normal course of business.
Some of these assurances are posted to comply with federal, state or other
government agencies' statutes and regulations. CNX sometimes uses letters of
credit to satisfy these requirements and these letters of credit reduce the
Company's borrowing facility capacity.

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.

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 swap and option transactions, which exist
parallel to the underlying physical transactions. The fair value of these
contracts was a net asset of $406 million at December 31, 2019 and a net asset
of $99 million at December 31, 2018. 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.




                                       57
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Cash Flows (in millions)
                                                     For the Years Ended December 31,
                                                     2019              2018        Change
Cash Provided by Operating Activities           $        981$     886$   95
Cash Used in Investing Activities               $     (1,147 )     $    

(895 ) $ (252 ) Cash Provided by (Used in) Financing Activities $ 166$ (483 )$ 649

Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:

• Net income decreased $851 million in the period-to-period comparison.

• Adjustments to reconcile net income to cash provided by operating

activities primarily consisted of a $327 million increase in impairment

of exploration and production properties, a $119 million increase in

impairment of unproved properties and expirations, a $19 million decrease

in impairment of other intangible assets, a $267 million net change in

commodity derivative instruments, a $46 million decrease in the loss on

debt extinguishment, $624 million decrease in gain on previously held

equity interest, and a $266 million change in deferred income taxes.

Cash used in investing activities changed in the period-to-period comparison primarily due to the following items:

• Capital expenditures increased $76 million in the period-to-period

        comparison primarily due to increased expenditures in midstream and water
        operations to support development within Southwest Pennsylvania.

• 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 decreased $467 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 various 2019 sales of surface

land and oil and gas rights.

Cash provided by (used in) financing activities changed in the period-to-period comparison primarily due to the following items:

• In the year ended December 31, 2019, there were net proceeds of $49

million of borrowings on the CNX credit facility compared to net proceeds

of $612 million in the year ended December 31, 2018.

• In the year ended December 31, 2019, CNX paid $406 million to repurchase

        $400 million of the 5.875% senior notes due in April 2022. 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
        5.875% 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.


•       During the year ended December 31, 2019, CNX received proceeds of $500
        million from the issuance of senior notes due in 2027. During the year
        ended December 31, 2018, CNX received proceeds of $394 million from the

issuance of CNXM's senior notes due in 2026. 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, 2019 and 2018, CNX repurchased $117
        million and $382 million, respectively, of its common stock on the open
        market.


•       In the year ended December 31, 2019, there were net proceeds of $228
        million of borrowings on the CNXM credit facility compared to net
        payments of $66 million in the year ended December 31, 2018.


•       In the year ended December 31, 2019, there were $64 million in
        distributions to CNXM noncontrolling interest holders compared to
        distributions of $55 million in the year ended December 31, 2018.


•       In the year ended December 31, 2019, there were $11 million in debt
        issuance and financing fees compared to $21 million in the year ended
        December 31, 2018.







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The following is a summary of the Company's significant contractual obligations at December 31, 2019 (in thousands):

                                                        Payments due by Year
                              Less Than                                       More Than
                               1 Year         1-3 Years       3-5 Years        5 Years          Total
Purchase Order Firm
Commitments                 $     9,701$     2,185$       323     $         -     $    12,209
Gas Firm Transportation and
Processing                      246,912         481,622         406,592       1,072,748       2,207,874
Long-Term Debt                        -         895,308         972,750         895,375       2,763,433
Interest on Long-Term Debt      147,453         270,825         165,328         130,707         714,313
Finance Lease Obligations         7,164           7,226             480               -          14,870
Interest on Finance Lease
Obligations                         804             352              80               -           1,236
Operating Lease Obligations      61,670          76,794           7,663          26,009         172,136
Interest on Operating Lease
Obligations                       6,993           6,405           3,223           4,813          21,434
Long-Term
Liabilities-Employee
Related (a)                       1,788           3,830           4,329          32,120          42,067
Other Long-Term Liabilities
(b)                             217,858          20,000          12,500          31,877         282,235
Total Contractual
Obligations (c)             $   700,343$ 1,764,547$ 1,573,268

$ 2,193,649$ 6,231,807

_________________________

(a)    Employee related long-term liabilities include salaried retirement
       contributions and work-related injuries and illnesses.


(b)    Other long-term liabilities include royalties and other long-term
       liability costs.

(c) The 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, 2019, CNX had total long-term debt of $2,763 million, excluding unamortized debt issuance costs. This long-term debt consisted of: • An aggregate principal amount of $894 million of 5.875% Senior Notes due

in April 2022 plus $1 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 $661 million in outstanding borrowings

under the CNX credit facility.

• An aggregate principal amount of $500 million of 7.25% Senior Notes due in

March 2027. Interest on the notes is payable March 14 and September 14 of

       each year. Payment of the principal and interest on the notes is
       guaranteed by most of CNX's subsidiaries but does not include CNXM.

• 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 $312 million in outstanding borrowings

under the CNXM revolver. CNX is not a guarantor of CNXM's revolving credit

       facility.







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Total Equity and Dividends
CNX had total equity of $4,962 million at December 31, 2019 compared to $5,082
million at December 31, 2018. 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 net leverage ratio exceeds 3.00 to 1.00 and
is subject to availability under the Credit Facility of at least 15% of the
aggregate commitments. The net leverage ratio was 2.64 to 1.00 at December 31,
2019. The Credit Facility does not permit dividend payments in the event of
default. The indentures to the 5.875% Senior Notes due in April 2022 and the
7.25% Senior Notes due in March 2027 limit dividends to $0.50 per share annually
unless several conditions are met. These conditions include no defaults, ability
to incur additional debt and other payment limitations under the indentures.
There were no defaults under the year ended December 31, 2019.
On January 23, 2020, 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 $0.4143 per unit with respect to the fourth quarter of 2019. The
distribution will be made on February 13, 2020 to unitholders of record as of
the close of business on February 5, 2020. The distribution, which equates to an
annual rate of $1.6572 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 2018.

Off-Balance Sheet Transactions
CNX does not maintain off-balance sheet transactions, arrangements, obligations
or other relationships with unconsolidated entities or others that are
reasonably likely to have a material current or future effect on the Company's
financial condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources
which are not disclosed in the Notes to the Audited Consolidated Financial
Statements. CNX uses a combination of surety bonds, corporate guarantees and
letters of credit to secure the Company's financial obligations for
employee-related, environmental, performance and various other items which are
not reflected in the Consolidated Balance Sheet at December 31, 2019. 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 December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12 -
Income Taxes - Simplifying the Accounting for Income Taxes (Topic 740), which
simplifies the accounting for income taxes by removing certain exceptions to the
general principles in Topic 740. This ASU removes the following exceptions: (1)
exception to the incremental approach for intraperiod tax allocation when there
is a loss from continuing operations and income or a gain from other items; (2)
exception to the requirement to recognize a deferred tax liability for equity
method investments when a foreign subsidiary becomes an equity method
investment; (3) exception to the ability not to recognize a deferred tax
liability for a foreign subsidiary when a foreign equity method investment
becomes a subsidiary; and (4) exception to the general methodology for
calculating income taxes in an interim period when a year-to-date loss exceeds
the anticipated loss for the year. The amendments in this ASU also improve
consistency and simplify other areas of Topic 740 by clarifying and amending
existing guidance. The amendments in this ASU will be applied using different
approaches depending on what the specific amendment relates to and, for public
entities, are effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2020. Early adoption is permitted.
The adoption of this guidance is not expected to have a material impact on the
Company's financial statements.
In November 2019, the FASB issued ASU 2019-11 - Financial Instruments - Credit
Losses (Topic 326), which clarifies and addresses specific issues about certain
aspects of the amendments in ASU 2016-13. In May 2019, the FASB issued ASU
2019-05 - Financial Instruments - Credit Losses (Topic 326), which provides
optional targeted transition relief to entities adopting ASU 2016-13. ASU
2016-13 replaces the incurred loss impairment methodology that reflects expected
credit losses and requires consideration of a broader range of reasonable and
supportable information to inform credit loss estimates. The measurement of
expected credit losses will be based on relevant information about past events,
including historical experience, current conditions, and reasonable and
supportable forecasts that affect the collectability of the reported amount. ASU
2019-05 provides the option to irrevocably elect the fair value option for
certain financial assets previously measured at amortized cost basis. For those
entities, the targeted transition relief will increase comparability of
financial statement information by providing an option to align


                                       60

--------------------------------------------------------------------------------



measurement methodologies for similar financial assets. The amendments in the
ASU will be applied using the modified-retrospective approach and, for public
entities, are effective for fiscal years beginning after December 15, 2019 and
interim periods within those annual periods. Early adoption is permitted. The
adoption of this guidance is not expected to have a material impact on the
Company's financial statements.

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