CNX RESOURCES CORPORATION 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 endedDecember 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
• Repurchased
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 EndedDecember 31, 2019 Compared with the Year EndedDecember 31, 2018 Net (Loss) Income Attributable to CNX Resources Shareholders CNX reported a net loss attributable toCNX Resources shareholders of$81 million , or a loss per diluted share of$0.42 , for the year endedDecember 31, 2019 , compared to net income attributable toCNX Resources shareholders of$797 million , or earnings per diluted share of$3.71 , for the year endedDecember 31, 2018 . For the Years Ended December 31, (Dollars in thousands) 2019 2018 Variance Net Income$ 31,948 $ 883,111 $ (851,163 ) Less: Net Income Attributable to Noncontrolling Interests 112,678 86,578 26,100 Net (Loss) Income Attributable toCNX 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
CNX's E&P Division had a loss before income tax of$140 million for the year endedDecember 31, 2019 , compared to earnings before income tax of$245 million for the year endedDecember 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'sCentral 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 endedDecember 31, 2018 . 37 -------------------------------------------------------------------------------- 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 theMarcellus Shale andUtica Shale inPennsylvania andWest 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 onJanuary 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 endedDecember 31, 2019 , compared to earnings before income tax of$134 million for the period fromJanuary 3, 2018 throughDecember 31, 2018 . E&P Division Summary Sales volumes, average sales prices (including the effects of settled derivatives instruments), and average costs for the E&P Division were as follows: For the Years Ended December 31, Percent 2019 2018 Variance Change Sales Volume (Bcfe) 539.1 507.1 32.0 6.3 % Average Sales Price - Gas (per Mcf)$ 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 endedDecember 31, 2019 , compared to$1,578 million for the year endedDecember 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$0.09 per Mcfe decrease in the uplift from NGLs and condensate sales volumes when excluding the impact of hedging. Both decreases were offset, in part, 38 --------------------------------------------------------------------------------
by a
Changes in the average costs per Mcfe were primarily related to the following
items:
• Transportation, gathering and compression expense increased on a per unit
basis primarily due to an increase in CNXM gathering fees related to an
increase in our Marcellus production and an increase in firm
transportation expense, primarily as a result of new contracts that giveCNX the ability to move and sell gas outside of the Appalachian basin. The
decrease in production from CNX's lower cost dry
the third quarter 2018 sale of CNX's Ohio JV assets also contributed to
the increase on a per unit basis. See Note 6 - Acquisitions and
Dispositions in the Notes to the Audited Consolidated Financial Statements
in Item 8 of this Form 10-K for additional information.
• Lease operating expense decreased on a per unit basis primarily due to a
decrease in water disposal costs in the period-to-period comparison due to
an increase in the reuse of produced water in well completions in the
current period, and also due to the sale of the majority of CNX's shallow
oil and gas assets and the sale of substantially all of CNX's Ohio Utica
JV assets in 2018.
The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company's natural gas production and sales portfolio.
For the Years Ended December 31,
Percent
in thousands (unless noted) 2019 2018 Variance Change
LIQUIDS
NGLs:
Sales Volume (MMcfe) 32,571 36,489 (3,918 ) (10.7 )%
Sales Volume (Mbbls) 5,428 6,081 (653 ) (10.7 )%
Gross Price ($/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") -
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
million of long-term equity-based compensation (non-cash) expense during
the year ended
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
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 endedDecember 31, 2019 compared to a gain of$155 million in the year endedDecember 31, 2018 , primarily due to the$131 million gain that was recognized related 40
-------------------------------------------------------------------------------- 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 endedDecember 31, 2018 due to the Midstream Acquisition that occurred inJanuary 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 endedDecember 31, 2019 compared to a loss on debt extinguishment of$54 million in the year endedDecember 31, 2018 . During the year endedDecember 31, 2019 , CNX purchased$400 million of its 5.875% senior notes due inApril 2022 at an average price equal to 101.5% of the principal amount. During the year endedDecember 31, 2018 , CNX purchased$411 million of its 5.875% senior notes due inApril 2022 at an average price equal to 103.5% of the principal amount and redeemed the$500 million 8.00% senior notes due inApril 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 endedDecember 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 endedDecember 31, 2019 , compared to 19.6% for the year endedDecember 31, 2018 . The effective rate for the year endedDecember 31, 2019 differs from theU.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 endedDecember 31, 2018 , CNX obtained a controlling interest inCNX 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 endedDecember 31, 2018 differs from theU.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
(94.5 )% Income Tax Expense$ 28 $ 216 $ (188 ) (87.0 )% Effective Income Tax Rate 46.5 % 19.6 % 26.9 % 42
-------------------------------------------------------------------------------- TOTAL E&P DIVISION ANALYSIS for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 : The E&P division had a loss before income tax of$140 million for the year endedDecember 31, 2019 compared to earnings before income tax of$245 million for the year endedDecember 31, 2018 . Variances by individual operating segment are discussed below. For the Year Ended Difference to Year EndedDecember 31, 2019 December 31, 2018 Other Other
(in millions) Marcellus
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
Total Average
$ (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)
Average Margin for Marcellus (per Mcfe)$ 0.63 $ 0.88
* 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 endedDecember 31, 2019 compared to$903 million for the year endedDecember 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 endedDecember 31, 2019 at an average gain of$0.18 per Mcf. For the year endedDecember 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 endedDecember 31, 2019 compared to$609 million for the year endedDecember 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 endedDecember 31, 2019 compared to$41 million for the year endedDecember 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 endedDecember 31, 2019 compared to$18 million for the year endedDecember 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 -------------------------------------------------------------------------------- •Marcellus transportation, gathering and compression costs were$444 million for the year endedDecember 31, 2019 compared to$320 million for the year endedDecember 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 endedDecember 31, 2019 compared to$230 million for the year endedDecember 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.
TheUtica segment had earnings before income tax of$88 million for the year endedDecember 31, 2019 compared to earnings before income tax of$194 million for the year endedDecember 31, 2018 . For the Years Ended December 31, Percent 2019 2018 Variance Change Utica Gas Sales Volumes (Bcf) 113.7 148.1 (34.4 ) (23.2 )% NGLs Sales Volumes (Bcfe)* - 5.1 (5.1 ) (100.0 )% Oil Sales Volumes (Bcfe)* - 0.1 (0.1 ) (100.0 )% Condensate Sales Volumes (Bcfe)* 0.1 0.4 (0.3 ) (75.0 )% Total Utica Sales Volumes (Bcfe)* 113.8 153.7
(39.9 ) (26.0 )%
Average Sales Price - Gas (per Mcf)$ 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
Total Average Utica Sales Price (per Mcfe)
$ (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
Average Margin for Utica (per Mcfe)$ 0.77 $ 1.26
*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. TheUtica segment had natural gas, NGLs and oil revenue of$264 million for the year endedDecember 31, 2019 compared to$446 million for the year endedDecember 31, 2018 . The$182 million decrease was due to the 26.0% decrease in totalUtica sales volumes and a 17.7% decrease in the average sales price for natural gas. The decrease in totalUtica 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 dryUtica wells. The decrease in total averageUtica 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 -------------------------------------------------------------------------------- impact of hedging due to the sale of the previously mentioned Ohio JV assets in the third quarter of 2018, which consisted primarily of wetUtica 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 producedUtica gas sales volumes for the year endedDecember 31, 2019 at an average gain of$0.18 per Mcf. For the year endedDecember 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 theUtica segment were$191 million for the year endedDecember 31, 2019 compared to$232 million for the year endedDecember 31, 2018 . The decrease in total dollars and increase in unit costs for theUtica segment were due to the following items: •Utica lease operating expenses were$16 million for the year endedDecember 31, 2019 , compared to$30 million for the year endedDecember 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 inUtica 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 endedDecember 31, 2019 compared to$52 million for the year endedDecember 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 inUtica volumes as well as the shift to lower cost dryUtica production. •Depreciation, depletion and amortization costs attributable to theUtica segment were$136 million for the year endedDecember 31, 2019 compared to$143 million for the year endedDecember 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 dryUtica wells compared to the lower capital costUtica 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 endedDecember 31, 2019 compared to earnings before income tax of$50 million for the year endedDecember 31, 2018 . For the Years Ended December 31, Percent 2019 2018 Variance Change CBM Gas Sales Volumes (Bcf) 55.4 60.3 (4.9 ) (8.1 )% Average Sales Price - Gas (per Mcf)$ 2.96 $ 3.53 $ (0.57 ) (16.1 )% Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (per Mcf)$ 0.13 $ (0.15
)
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-------------------------------------------------------------------------------- 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 endedDecember 31, 2019 at an average gain of$0.18 per Mcf. For the year endedDecember 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 endedDecember 31, 2019 compared to$154 million for the year endedDecember 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 endedDecember 31, 2019 compared to$22 million for the year endedDecember 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 endedDecember 31, 2019 compared to$48 million for the year endedDecember 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 endedDecember 31, 2019 compared to$77 million for the year endedDecember 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 SEGMENTThe Other Gas segment had a loss before income tax of$497 million for the year endedDecember 31, 2019 compared to a loss before income tax of$253 million for the year endedDecember 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 onMarch 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 theOther Gas segment for the year endedDecember 31, 2019 compared to$16 million for the year endedDecember 31, 2018 . Total operating costs and expenses related to these other gas sales volumes were$5 million for the year endedDecember 31, 2019 compared to$18 million for the year endedDecember 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 endedDecember 31, 2019 . For the year endedDecember 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
--------------------------------------------------------------------------------
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 endedDecember 31, 2019 compared to$66 million for the year endedDecember 31, 2018 . Purchased gas costs were$91 million for the year endedDecember 31, 2019 compared to$65 million for the year endedDecember 31, 2018 . The period-to-period increase in purchased gas revenue was due to an increase in purchased gas sales volumes, offset in part by a decrease in average sales price. For the Years Ended December 31, Percent 2019 2018 Variance Change Purchased Gas Sales Volumes (in Bcf) 40.6 20.5 20.1 98.0 % Average Sales Price (per Mcf)$ 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
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
third parties for hydraulic fracturing in 2019 compared to 2018.
Impairment ofExploration 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 ofExploration 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 inArmstrong ,Indiana ,Jefferson andWestmoreland counties. The majority of these properties were developed prior to 2013 and the last of these properties were developed in 2015. Impairment ofUnproved 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
48
--------------------------------------------------------------------------------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 endedDecember 31, 2019 compared to$12 million for the year endedDecember 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
period-to-period comparison is due to an increase in the number of leases
that were allowed to expire in the year ended
expire within the next 12 months, because they were no longer in the
Company's future drilling plan. Additionally, approximately
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
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--------------------------------------------------------------------------------
rig contracts early, as well as additional idle service expense related to the
Shaw 1G
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 endedDecember 31, 2019 compared to$112 million for the year endedDecember 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 endedDecember 31, 2019 compared to$122 million in the year endedDecember 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 inApril 2023 and the$411 million purchase of the outstanding 5.875% senior notes due inApril 2022 during the year endedDecember 31, 2018 . Additionally, the Company purchased$400 million of its outstanding 5.875% senior notes due inApril 2022 during the year endedDecember 31, 2019 . These decreases were partially offset by a completed private offering of$500 million of 7.25% senior notes dueMarch 2027 during the year endedDecember 31, 2019 , as well as additional borrowings on the CNX credit facility. See Note 14 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information. 50 --------------------------------------------------------------------------------
TOTAL MIDSTREAM DIVISION ANALYSIS for the year ended
CNX's Midstream Division's principal activity is the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets of CNX Gathering and CNXM, which provide natural gas gathering services for the Company's produced gas, as well as for other independent third-parties in theMarcellus Shale andUtica Shale inPennsylvania andWest Virginia . Excluded from the Midstream Division are the gathering assets and operations of CNX that have not been contributed to CNX Gathering and CNXM. OnJanuary 3, 2018 , CNX completed the Midstream Acquisition (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). CNX Gathering holds all of the interests inCNX Midstream GP LLC , which holds both the general partner and limited partner interests in CNXM. As a result of this transaction, CNX owns and controls 100% of CNX Gathering, making CNXM a single-sponsor master limited partnership and thus the Company began consolidating CNXM onJanuary 3, 2018 . For the period For the Year January 3, Ended 2018 through December 31, December 31, (in millions) 2019 2018 Variance Midstream Revenue - Related Party$ 233 $ 168 $ 65 Midstream Revenue - Third Party 74 90 (16 ) Total Revenue$ 307 $
258
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
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--------------------------------------------------------------------------------
Transportation, Gathering and Compression
Transportation, Gathering and Compression costs were$47 million for both the year endedDecember 31, 2019 and the periodJanuary 3, 2018 throughDecember 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 endedDecember 31, 2019 compared to$23 million for the periodJanuary 3, 2018 throughDecember 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 endedDecember 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 periodJanuary 3, 2018 throughDecember 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 endedDecember 31, 2019 compared to$24 million for the periodJanuary 3, 2018 throughDecember 31, 2018 . The increase in the period-to-period comparison was due to additional borrowings on the revolving credit facility. 52
--------------------------------------------------------------------------------
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted inthe 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. AtDecember 31, 2019 , CNX had deferred tax liabilities in excess of deferred tax assets of approximately$351 million . AtDecember 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 atDecember 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 -------------------------------------------------------------------------------- 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 endedDecember 31, 2019 , an impairment of$327 million was included in Impairment ofExploration 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 inArmstrong ,Indiana ,Jefferson andWestmoreland counties. InFebruary 2017 , the Company approved a plan to sell subsidiariesKnox Energy LLC andCoalfield 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 ofExploration 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
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-------------------------------------------------------------------------------- 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 endedDecember 31, 2019 , an impairment of$119 million was included in Impairment ofUnproved Properties and Expirations in the Consolidated Statements of Income. There were no other impairments related to unproved properties in the years endedDecember 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
In connection with the Midstream Acquisition that closed onJanuary 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 -------------------------------------------------------------------------------- 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 theSEC , 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. InMay 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-------------------------------------------------------------------------------- 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 atDecember 31, 2019 and a net asset of$99 million atDecember 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 )
Cash provided by operating activities changed in the period-to-period comparison primarily due to the following items:
• Net income decreased
• Adjustments to reconcile net income to cash provided by operating
activities primarily consisted of a
of exploration and production properties, a
impairment of unproved properties and expirations, a
in impairment of other intangible assets, a
commodity derivative instruments, a
debt extinguishment,
equity interest, and a
Cash used in investing activities changed in the period-to-period comparison primarily due to the following items:
• Capital expenditures increased
comparison primarily due to increased expenditures in midstream and water
operations to support development within Southwest Pennsylvania .
• In
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
the 2018 sale of substantially all of the Ohio Utica Joint Venture Assets
in the wet gas
and Noble counties along with the 2018 sale of substantially all of CNX's
shallow oil and gas assets and certain CBM assets in
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
million of borrowings on the CNX credit facility compared to net proceeds
of
• In the year ended
$400 million of the 5.875% senior notes due inApril 2022 . In the year endedDecember 31, 2018 , CNX paid$955 million to repurchase all of the remaining 8.00% senior notes dueApril 2023 and$411 million of the 5.875% senior notes due inApril 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 endedDecember 31, 2019 , CNX received proceeds of$500 million from the issuance of senior notes due in 2027. During the year endedDecember 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 .
58--------------------------------------------------------------------------------
The following is a summary of the Company's significant contractual obligations
at
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 _________________________
(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
in
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
under the CNX credit facility.
• An aggregate principal amount 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
Interest on the notes is payable
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
under the CNXM revolver. CNX is not a guarantor of CNXM's revolving credit
facility.
59-------------------------------------------------------------------------------- Total Equity and Dividends CNX had total equity of$4,962 million atDecember 31, 2019 compared to$5,082 million atDecember 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 inMarch 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 atDecember 31, 2019 . The Credit Facility does not permit dividend payments in the event of default. The indentures to the 5.875% Senior Notes due inApril 2022 and the 7.25% Senior Notes due inMarch 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 endedDecember 31, 2019 . OnJanuary 23, 2020 , the Board of Directors ofCNX 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 onFebruary 13, 2020 to unitholders of record as of the close of business onFebruary 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 atDecember 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 InDecember 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 afterDecember 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. InNovember 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. InMay 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
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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 afterDecember 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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