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-Q. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see "Part II. Item 1A. Risk Factors" and the section entitled "Forward-Looking Statements" and the "Risk Factors" contained in our Annual Report on Form 10-K for the year endedDecember 31, 2020 , which we filed with theSEC onFebruary 9, 2021 (the "Form 2020 10-K"). CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
General
COVID-19 Update:
CNX continues to monitor the current and potential impacts of the coronavirus
COVID-19 ("COVID-19") pandemic on all aspects of our business and geographies,
including how it has impacted, and may in the future impact, our operations,
financial results, liquidity, contractors, customers, employees and vendors. The
Company also continues to monitor a number of factors that may cause actual
results of operations to differ from our historical results or current
expectations. These and other factors could affect the Company's operations,
earnings and cash flows for any period and could cause such results to not be
comparable to those of the same period in previous years. The results presented
in this Form 10-Q are not necessarily indicative of future operating results.
While CNX did not incur significant disruptions to operations during the three
or nine months ended September 30, 2021 or 2020 as a direct result of the
COVID-19 pandemic, CNX is unable to predict the full extent of the future impact
that the COVID-19 pandemic could have on the Company, including our financial
position, operating results, liquidity and ability to obtain financing in future
reporting periods, due to numerous uncertainties outside the Company's control.
Hedging Update:
Total hedged natural gas production in the 2021 fourth quarter is 130.6(1) Bcf. The annual gas hedge position is shown in the table below:
2021 2022
Volumes Hedged (Bcf), as of
1Net of purchased swaps.
2Includes actual settlements of 384.5 Bcf.
CNX's hedged gas volumes include a combination of NYMEX financial hedges, index
(NYMEX and basis) financial hedges, and physical fixed price sales. In addition,
to protect the NYMEX hedge volumes from basis exposure, CNX enters into
basis-only financial hedges and physical sales with fixed basis at certain sales
points. For further information see Item 3 Quantitative and Qualitative
Disclosures About Market Risk.
34--------------------------------------------------------------------------------
Results of Operations - Three Months Ended
Net Loss Attributable to CNX Resources Shareholders
CNX reported a net loss attributable to
For the Three Months Ended September 30,
(Dollars in thousands) 2021 2020 Variance
Net Loss $ (872,921) $ (188,793) $ (684,128)
Less: Net Income Attributable to Noncontrolling Interest - 15,905 (15,905)
Net Loss Attributable to CNX Resources Shareholders $
(872,921)
Included in the loss for the three months endedSeptember 30, 2021 was an unrealized loss on commodity derivative instruments of$1,376 million . Included in the loss for the three months endedSeptember 30, 2020 was an unrealized loss on commodity derivative instruments of$259 million .
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the company. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company's operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX's natural gas producing activities. Natural Gas, NGL and Oil Production Costs excludes certain expenses that are not directly related to CNX's natural gas producing activities and are managed outside our production operations (See Note 14 - Segment Information in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL andOil Production Costs and Natural Gas , NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies. 35
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Non-GAAP Financial Measures Reconciliation
For the Three Months Ended
September 30,
(Dollars in millions) 2021 2020
Total Revenue and Other Operating (Loss) Income $ (880) $ 66
Add (Deduct):
Purchased Gas Revenue (16) (32)
Loss on Commodity Derivative Instruments and Monetization 1,376 259
Other Revenue and Operating Income (25) (21)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure
$ 455 $ 272 Total Operating Expense$ 305 $ 280 Add (Deduct): Depreciation, Depletion and Amortization (DD&A) - Corporate (4) (2) Exploration and Production Related Other Costs (3) (2) Purchased Gas Costs (14) (32) Selling, General and Administrative Costs (25) (23) Other Operating Expense (21) (24) Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1$ 238 $ 197
1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
The following table presents a summary of our total sales volumes, sales of
natural gas, NGL and oil including cash settlements, natural gas, NGL and oil
production costs and natural gas, NGL and oil production margin related to our
production operations on a total company basis (See Non-GAAP Financial Measures
Reconciliation for the reconciliation to the most directly comparable financial
measures calculated and presented in accordance with GAAP):
For the Three Months Ended
2021 2020 Variance
in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe
Total Sales Volumes (Bcfe)* 153.5 115.7 37.8
Natural Gas, NGL and Oil Revenue
(0.92) 90 0.83 (221) (1.75)
Sales of Natural Gas, NGL and Oil,
including Cash Settlements 455 2.96 272 2.36 183 0.60
Lease Operating Expense 11 0.07 10 0.09 1 (0.02)
Production, Ad Valorem, and Other Fees 10 0.06 6 0.05 4 0.01
Transportation, Gathering and
Compression 91 0.59 69 0.59 22 -
Depreciation, Depletion and
Amortization (DD&A) 126 0.83 112 0.98 14 (0.15)
Natural Gas, NGL and Oil Production
Costs 238 1.55 197 1.71 41 (0.16)
Natural Gas, NGL and Oil Production
Margin $ 217 $ 1.41 $ 75 $ 0.65 $ 142 $ 0.76
*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals
six Mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of NGL, condensate, and natural
gas prices.
The 37.8 Bcfe increase in total sales volumes in the period-to period comparison
was primarily due to the turn-in-line of new wells throughout 2020 and 2021,
offset in part by normal production declines.
36--------------------------------------------------------------------------------
Changes in the average costs per Mcfe were primarily related to the following items:
•Lease operating expense decreased on a per unit basis as a result of increased production volumes. •Depreciation, depletion and amortization expense decreased on a per unit basis as a result of low cost reserve additions from development during the 2020 period inSouthwest Pennsylvania (SWPA), and the addition of proved undeveloped Shale wells inCentral Pennsylvania (CPA).
Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company's natural gas production and sales portfolio and information regarding settled commodity derivatives:
For the Three Months Ended
in thousands (unless noted) 2021 2020 Variance Percent Change LIQUIDS NGL: Sales Volume (MMcfe) 10,145 6,885 3,260 47.3 % Sales Volume (Mbbls) 1,691 1,147 544 47.4 % Gross Price ($/Bbl) 37.14 13.14 24.00 182.6 % Gross NGL Revenue 62,792 15,053 47,739 317.1 % Oil/Condensate: Sales Volume (MMcfe) 831 624 207 33.2 % Sales Volume (Mbbls) 138 104 34 32.7 % Gross Price ($/Bbl) 59.97 39.50 20.47 51.8 % Gross Oil/Condensate Revenue 8,302 4,106 4,196 102.2 % NATURAL GAS Sales Volume (MMcf) 142,541 108,190 34,351 31.8 % Sales Price ($/Mcf) 3.61 1.51 2.10 139.1 % Gross Natural Gas Revenue 514,821 163,054 351,767 215.7 % Hedging Impact ($/Mcf) (0.92) 0.83 (1.75) (210.8) % (Loss) Gain on Commodity Derivative Instruments - Cash Settlement (131,091) 90,311 (221,402) (245.2) % The increase in gross revenue was primarily the result of the$2.10 per Mcf increase in general natural gas prices, when excluding the impact of hedging, the 37.8 Bcfe increase in sales volumes, and the$24.00 per Bbl increase in NGL prices. These increases were offset, in-part, by the impact of the change in the realized (loss) gain on commodity derivative instruments related to the Company's hedging program. 37 --------------------------------------------------------------------------------
SEGMENT ANALYSIS for the three months ended
For the Three Months Ended Difference to Three Months Ended
September 30, 2021 September 30, 2020
(in millions) Shale CBM Other Total Shale CBM Other Total
Natural Gas, NGLs and Oil Revenue
1
$ 404 Loss on Commodity Derivative Instruments (119) (12) (1,376) (1,507) (199) (23) (1,116) (1,338) Purchased Gas Revenue - - 16 16 - - (16) (16) Other Revenue and Operating Income 19 - 6 25 2 - 2 4 Total Revenue and Other Operating Income (Loss) 436 37 (1,353) (880) 183 - (1,129) (946) Lease Operating Expense 8 3 - 11 1 (1) 1 1 Production, Ad Valorem, and Other Fees 8 2 - 10 3 1 - 4 Transportation, Gathering and Compression 79 11 1 91 19 1 2 22 Depreciation, Depletion and Amortization 112 14 4 130 18 (2) - 16 Exploration and Production Related Other Costs - - 3 3 - - 1 1 Purchased Gas Costs - - 14 14 - - (18) (18) Other Operating Expense - - 21 21 - - (3) (3) Selling, General and Administrative Costs - - 25 25 - - 2 2 Total Operating Expense 207 30 68 305 41 (1) (15) 25 Other Expense - - 3 3 - - 1 1 Gain on Asset Sales and Abandonments, net - - (12) (12) - - (8) (8) Loss on Debt Extinguishment - - 19 19 - - 19 19 Interest Expense - - 37 37 - - (1) (1) Total Other Expense - - 47 47 - - 11 11 Total Costs and Expenses 207 30 115 352 41 (1) (4) 36
Earnings (Loss) Before Income Tax
$ (982) 38
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SHALE SEGMENT
The Shale segment had earnings before income tax of$229 million for the three months endedSeptember 30, 2021 compared to earnings before income tax of$87 million for the three months endedSeptember 30, 2020 .
For the Three Months Ended
Percent
2021 2020 Variance Change
Shale Gas Sales Volumes (Bcf) 130.3 95.2 35.1 36.9 %
NGLs Sales Volumes (Bcfe)* 10.1 6.9 3.2 46.4 %
Oil/Condensate Sales Volumes (Bcfe)* 0.8 0.5 0.3 60.0 %
Total Shale Sales Volumes (Bcfe)* 141.2 102.6 38.6 37.6 %
Average Sales Price - Natural Gas (per Mcf) $ 3.57 $ 1.44 $ 2.13 147.9 %
(Loss) Gain on Commodity Derivative Instruments -
$ (0.92) $ 0.84 $ (1.76) (209.5) % Average Sales Price - NGLs (per Mcfe)*$ 6.19 $ 2.18 $ 4.01 183.9 % Average Sales Price - Oil/Condensate (per Mcfe)*$ 9.99 $ 6.27 $ 3.72 59.3 % Total Average Shale Sales Price (per Mcfe)$ 2.95 $ 2.30 $ 0.65 28.3 % Average Shale Lease Operating Expenses (per Mcfe) 0.06 0.07 (0.01) (14.3) %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) 0.06
0.04 0.02 50.0 %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)
0.56 0.58 (0.02) (3.4) %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)
0.78 0.93 (0.15) (16.1) %
Total Average Shale Production Costs (per Mcfe) $ 1.46 $ 1.62 $ (0.16) (9.9) %
Total Average Shale Production Margin (per Mcfe) $ 1.49 $ 0.68 $ 0.81 119.1 %
* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals
six Mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of oil, NGL, condensate, and
natural gas prices.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $536
million for the three months ended September 30, 2021 compared to $156 million
for the three months ended September 30, 2020 . The $380 million increase was due
primarily to a 147.9% increase in the average sales price for natural gas, a
37.6% increase in total Shale sales volumes, and a 183.9% increase in the
average sales price of NGLs. The increase in total Shale volumes was primarily
due to the turn-in-line of new wells throughout 2020 and 2021. The increase was
also due to the temporary shut-in of new turn-in-line wells in 2020 due to low
natural gas prices, offset in part by normal production declines.
The increase in total average Shale sales price was primarily due to a $2.13 per
Mcf increase in average gas sales price and a $4.01 per Mcfe increase in the
average NGL sales price. These increases were offset in part by a $1.76 per Mcf
change in the realized (loss) gain on commodity derivative instruments. The
notional amounts associated with these financial hedges represented
approximately 103.8 Bcf of the Company's produced Shale gas sales volumes for
the three months ended September 30, 2021 at an average loss of $1.15 per Mcf
hedged. For the three months ended September 30, 2020 , these financial hedges
represented approximately 89.3 Bcf at an average gain of $0.89 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $207 million for
the three months ended September 30, 2021 compared to $166 million for the three
months ended September 30, 2020 . The increase in total dollars and decrease in
unit costs for the Shale segment were due to the following items:
•Shale production, ad valorem and other fees were $8 million for the three
months ended September 30, 2021 compared to $5 million for the three months
ended September 30, 2020 . The increases in total dollars and unit costs were
primarily due to the increase in the total average sales price, as well as
production volumes.
•Shale transportation, gathering and compression costs were $79 million for the
three months ended September 30, 2021 compared to $60 million for the three
months ended September 30, 2020 . The increase in total dollars and decrease in
unit costs were primarily due to the increase in production volumes.
39
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•Depreciation, depletion and amortization costs attributable to the Shale
segment were $112 million for the three months ended September 30, 2021 compared
to $94 million for the three months ended September 30, 2020 . The increase in
total dollars was due to the increase in production volumes. These amounts
included depletion on a unit of production basis of $0.69 per Mcfe and $0.80 per
Mcfe, respectively. The decrease in the units of production depreciation,
depletion and amortization rate in the current period is primarily the result of
low-cost reserve additions from development in 2020 in SWPA as well as the
addition of proved undeveloped Shale reserves in CPA. The remaining
depreciation, depletion and amortization costs were either recorded on a
straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering
services provided to third-parties. The Shale segment had other revenue and
operating income of $19 million for the three months ended September 30, 2021
compared to $17 million for the three months ended September 30, 2020 . The
increase in the period-to-period comparison was primarily due to temporary
production curtailments by third party customers that occurred in the 2020
period. Those curtailments were restored to full production in the latter half
of 2020.
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of
For the Three Months Ended
Percent
2021 2020 Variance Change
CBM Gas Sales Volumes (Bcf) 12.2 13.0 (0.8) (6.2) %
Average Sales Price - Gas (per Mcf) $ 4.01 $ 1.98 $ 2.03 102.5 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)
$ (0.95) $ 0.81 $ (1.76) (217.3) % Total Average CBM Sales Price (per Mcf)$ 3.06 $ 2.79 $ 0.27 9.7 % Average CBM Lease Operating Expenses (per Mcf) 0.26 0.28 (0.02) (7.1) %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) 0.15
0.09 0.06 66.7 %
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
0.91 0.76 0.15 19.7 %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
1.14 1.21 (0.07) (5.8) %
Total Average CBM Production Costs (per Mcf) $ 2.46 $ 2.34 $ 0.12 5.1 %
Total Average CBM Production Margin (per Mcf) $ 0.60 $ 0.45 $ 0.15 33.3 %
The CBM segment had natural gas revenue of $49 million for the three months
ended September 30, 2021 compared to $26 million for the three months ended
September 30, 2020 . The $23 million increase was due to a 102.5% increase in the
average sales price for natural gas in the current period, offset in part by the
6.2% decrease in total CBM sales volumes. The decrease in CBM sales volumes was
primarily due to normal production declines.
The total average CBM sales price increased $0.27 per Mcf due to a $2.03 per Mcf
increase in average gas sales price, offset in part by a $1.76 per Mcf change in
the realized (loss) gain on commodity derivative instruments resulting from the
Company's hedging program. The notional amounts associated with these financial
hedges represented approximately 9.1 Bcf of the Company's produced CBM sales
volumes for the three months ended September 30, 2021 at an average loss of
$1.28 per Mcf hedged. For the three months ended September 30, 2020 , these
financial hedges represented approximately 11.8 Bcf at an average gain of $0.89
per Mcf hedged.
Total operating costs and expenses for the CBM segment were $30 million for the
three months ended September 30, 2021 compared to $31 million for the three
months ended September 30, 2020 . The decrease in total dollars and increase in
unit costs for the CBM segment were due to the following items:
•CBM lease operating expense was
40
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•CBM transportation, gathering and compression costs were $11 million for the
three months ended September 30, 2021 compared to $10 million for the three
months ended September 30, 2020 . The increases in total dollars and unit costs
were primarily due to an increase in firm transportation expense.
•Depreciation, depletion and amortization costs attributable to the CBM segment
were $14 million for the three months ended September 30, 2021 compared to $16
million for the three months ended September 30, 2020 . These amounts included
depletion on a unit of production basis of $0.66 per Mcfe and $0.67 per Mcfe,
respectively. The decrease in the units of production depreciation, depletion
and amortization rate in the current period is primarily the result of the
production mix. The remaining depreciation, depletion and amortization costs
were either recorded on a straight-line basis or related to asset retirement
obligations.
OTHER SEGMENT
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes.
The Other Segment had a loss before income tax of$1,468 million for the three months endedSeptember 30, 2021 compared to a loss before income tax of$343 million for the three months endedSeptember 30, 2020 . The decrease in total dollars is discussed below. For the
Three Months Ended
2021 2020 Variance Percent Change
Other Gas Sales Volumes (Bcf) 0.1 - 0.1 100.0 %
Oil Sales Volumes (Bcfe)* - 0.1 (0.1) (100.0) %
Total Other Sales Volumes (Bcfe)* 0.1 0.1 - - %
* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals
six Mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of oil, condensate, and natural
gas prices.
Loss on Commodity Derivative Instruments
For the three months endedSeptember 30, 2021 , the Other Segment recognized an unrealized loss on commodity derivative instruments of$1,376 million . For the three months endedSeptember 30, 2020 , the Other Segment recognized an unrealized loss on commodity derivative instruments of$259 million as well as cash settlements paid of$1 million . The unrealized loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis. See Note 11 - Derivative Instruments in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Purchased gas volumes represent volumes of natural gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were$16 million for the three months endedSeptember 30, 2021 compared to$32 million for the three months endedSeptember 30, 2020 . Purchased gas costs were$14 million for the three months endedSeptember 30, 2021 compared to$32 million for the three months endedSeptember 30, 2020 . The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes, offset in part by an increase in averages sales price. For the
Three Months Ended
2021 2020 Variance Percent Change
Purchased Gas Sales Volumes (in Bcf) 3.8 20.7 (16.9) (81.6) %
Average Sales Price (per Mcf) $ 4.33 $ 1.52 $ 2.81 184.9 %
Purchased Gas Average Cost (per Mcf) $ 3.77 $ 1.53 $ 2.24 146.4 %
41--------------------------------------------------------------------------------
Other Operating Income
For the Three Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Equity Income from Affiliates $ 1 $ - $ 1 100.0 %
Water Income 2 1 1 100.0 %
Excess Firm Transportation Income 3 3 - - %
Total Other Operating Income $ 6 $ 4 $ 2 50.0 %
•Equity income from affiliates primarily represents CNX's share of earnings from
a 50% interest in a power plant located within CNX's CBM field. Power generated
from the facility is sold into wholesale electricity markets during times of
peak energy consumption. Due to the plant consuming coal mine methane gas, the
plant qualifies for Pennsylvania Tier I Renewable Energy Credits.
•Excess firm transportation income represents revenue from the sale of excess
firm transportation capacity to third-parties. The Company obtains firm pipeline
transportation capacity to enable gas production to flow uninterrupted as sales
volumes increase. In order to minimize this unutilized firm transportation
expense, CNX is able to release (sell) unutilized firm transportation capacity
to other parties when possible and when beneficial. The revenue from released
capacity helps offset the unutilized firm transportation and processing fees in
total other operating expense.
Exploration and Production Related Other Costs
For the Three Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Lease Expiration Costs $ 2 $ 1 $ 1 100.0 %
Land Rentals 1 1 - - %
Total Exploration and Production Related Other
Costs $ 3 $ 2 $ 1 50.0 %
•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months.
Selling, General and Administrative ("SG&A")
SG&A costs include costs such as overhead, including employee labor and benefit
costs, short-term incentive compensation, costs of maintaining our headquarters,
audit and other professional fees, and legal compliance expenses. SG&A costs
also include non-cash long-term equity-based compensation expense.
For the Three Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Long-Term Equity-Based Compensation
(Non-Cash) $ 3 $ 2 $ 1 50.0 %
Short-Term Incentive Compensation 3 3 - - %
Salaries, Wages and Employee Benefits 6 8 (2) (25.0) %
Other 13 10 3 30.0 %
Total SG&A $ 25 $ 23 $ 2 8.7 %
•Salaries, wages and employee benefits decreased in the period-to-period comparison primarily due to a decrease in employees. •Other increased in the period-to-period comparison primarily due to an increase in legal and consulting professional services.
42--------------------------------------------------------------------------------
Other Operating Expense
For the Three Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Unutilized Firm Transportation and Processing Fees $ 13 $ 20 $ (7) (35.0) %
Idle Equipment and Service Charges - 2 (2) (100.0) %
Insurance Expense 1 1 - - %
Litigation Settlements 5 - 5 100.0 %
Other 2 1 1 100.0 %
Total Other Operating Expense $ 21 $ 24 $ (3) (12.5) %
•Unutilized firm transportation and processing fees represent pipeline
transportation capacity obtained to enable gas production to flow uninterrupted
as sales volumes increase, as well as additional processing capacity for NGLs.
In some instances, the Company may have the opportunity to realize more
favorable net pricing by strategically choosing to sell natural gas into a
market or to a customer that does not require the use of the Company's own firm
transportation capacity. Such sales would result in an increase in unutilized
firm transportation expense. The Company attempts to minimize this expense by
releasing (selling) unutilized firm transportation capacity to other parties
when possible and when beneficial. The revenue received when this capacity is
released (sold) is included in Excess Firm Transportation Income above. The
decrease in the period-to-period comparison was primarily due to an increase in
utilization of firm transportation capacity in the current year due to
production increases in 2021 compared to 2020.
•Idle equipment and service charges relate to the temporary idling of certain 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 decrease in the period-to-period comparison was the result of one of CNX's
drilling rigs being idled in the prior period.
Other Expense
For
the Three Months Ended
(in millions) 2021 2020 Variance Percent Change Other Income Interest Income $ -$ 2 $ (2) (100.0) % Other 3 6 (3) (50.0) % Total Other Income $ 3$ 8 $ (5) (62.5) % Other Expense Merger-Related Costs $ -$ 5 $ (5) (100.0) % Bank Fees 3 3 - - % Professional Services 2 1 1 100.0 % Other Corporate Expense 1 1 - - % Total Other Expense $ 6$ 10 $ (4) (40.0) % Total Other Expense $ 3$ 2 $ 1 50.0 % •Other income decreased in the period-to-period comparison primarily due to the receipt of a severance tax refund related to a prior period in the three months endedSeptember 30, 2020 as well as additional interest income related to the alternative minimum tax credit refund CNX received (See Note 4 - Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). •Merger-related costs consist of transaction costs directly attributable to the CNXM Merger (See Note 13 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), including financial advisory, legal service and other professional fees, which were recorded to Other Expense in the Consolidated Statements of Income. 43
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Gain on Asset Sales and Abandonments, net
A gain on asset sales of$12 million related to the sale of various non-core assets was recognized in the three months endedSeptember 30, 2021 compared to a gain of$4 million in the three months endedSeptember 30, 2020 .
Loss on Debt Extinguishment
A loss on debt extinguishment of$19 million was recognized in the three months endedSeptember 30, 2021 in connection with the purchase of a portion of the CNXM 6.50% Senior Notes dueMarch 2026 and the repayment and termination of theCardinal States Gathering Company LLC andCSG Holdings II LLC non-revolving credit facilities. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. Interest Expense For the Three Months Ended September 30, (in millions) 2021 2020 Variance Percent Change Total Interest Expense $ 37$ 38 $ (1) (2.6) % •Interest expense decreased$1 million quarter over quarter. The Company purchased the remaining$894 million of the 5.875% Senior Notes dueApril 2022 during the year endedDecember 31, 2020 , purchased a portion of the 6.50% Senior Notes dueMarch 2026 during the quarter endedSeptember 30, 2021 , repaid in full and terminated theCardinal States Gathering Company LLC andCSG Holdings II LLC non-revolving credit facilities during the quarter endedSeptember 30, 2021 , had lower average borrowings on the CNX senior secured revolving credit facility (the "CNX Credit Facility"), and had higher unrealized gains on interest rate swap agreements. These decreases were offset in part by interest related to the addition of$500 million of Senior Notes due 2029, and$200 million of Senior Notes due 2027. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. Income Taxes For the Three Months Ended September 30, (in millions) 2021 2020 Variance Percent Change Total Company Loss Before Income Tax$ (1,232) $ (250) $ (982) (392.8) % Income Tax Benefit $ (360)$ (61) $ (299) (490.2) % Effective Income Tax Rate 29.2 % 24.5 % 4.7 % The effective income tax rate was 29.2% for the three months endedSeptember 30, 2021 compared to 24.5% for the three months endedSeptember 30, 2020 . The effective rate for the three months endedSeptember 30, 2021 differs from theU.S. federal statutory rate of 21% primarily due to the impact of federal tax credits, equity compensation and state income taxes. The effective rate for the three months endedSeptember 30, 2020 differs from theU.S. federal statutory rate of 21% primarily due to the impact of equity compensation and state income taxes (See Note 4 - Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). 44 --------------------------------------------------------------------------------
Results of Operations - Nine Months Ended
Net Loss Attributable to CNX Resources Shareholders CNX reported a net loss attributable toCNX Resources shareholders of$1,129 million , or a loss per diluted share of$5.17 , for the nine months endedSeptember 30, 2021 , compared to a net loss attributable toCNX Resources shareholders of$680 million , or a loss per diluted share of$3.56 , for the nine months endedSeptember 30, 2020 . For the Nine Months Ended September 30, (Dollars in thousands) 2021 2020 Variance Net Loss $
(1,128,956)
- 55,031 (55,031)
Net Loss Attributable to CNX Resources Shareholders $
(1,128,956)
Included in the loss for the nine months endedSeptember 30, 2021 was an unrealized loss on commodity derivative instruments of$1,874 million . Included in the loss for the nine months endedSeptember 30, 2020 was an unrealized loss on commodity derivative instruments of$501 million , a$62 million non-cash impairment charge related to exploration and production properties specific to ourSouthwestern Pennsylvania (SWPA) CBM asset group (See Note 5 - Property, Plant and Equipment in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), and a$473 million non-cash impairment charge related to goodwill (See Note 6 -Goodwill and Other Intangible Assets in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information).
Non-GAAP Financial Measures
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the company. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company's operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX's natural gas producing activities. Natural Gas, NGL and Oil Production Costs excludes certain expenses that are not directly related to CNX's natural gas producing activities and are managed outside our production operations (See Note 14 - Segment Information in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). These expenses include, but are not limited to, interest expense, impairment of exploration and production properties, impairment of goodwill, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL andOil Production Costs and Natural Gas , NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies. 45
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Non-GAAP Financial Measures Reconciliation
For the Nine Months Ended
September 30,
(Dollars in millions) 2021 2020
Total Revenue and Other Operating (Loss) Income $ (534) $ 631
Add (Deduct):
Purchased Gas Revenue (67) (78)
Loss on Commodity Derivative Instruments and Monetization 1,874 417
Other Revenue and Operating Income (75) (61)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure
$ 1,198 $ 909 Total Operating Expense$ 885 $ 1,386 Add (Deduct): Depreciation, Depletion and Amortization (DD&A) - Corporate (8) (8) Exploration and Production Related Other Costs (8) (9) Purchased Gas Costs (61) (77) Impairment of Exploration and Production Properties - (62) Impairment of Goodwill - (473) Selling, General and Administrative Costs (77) (76) Other Operating Expense (52) (71) Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure1$ 679 $ 610
1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
The following table presents a summary of our total sales volumes, sales of
natural gas, NGL and oil including cash settlements, natural gas, NGL and oil
production costs and natural gas, NGL and oil production margin related to our
production operations on a total company basis (See Non-GAAP Financial Measures
Reconciliation for the reconciliation to the most directly comparable financial
measures calculated and presented in accordance with GAAP):
For the Nine Months Ended
2021 2020 Variance
in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe
Total Sales Volumes (Bcfe)* 432.1 364.6 67.5
Natural Gas, NGL and Oil Revenue $ 1,337 $ 3.11 $ 609 $ 1.62 $ 728 $ 1.49
(Loss) Gain on Commodity Derivative
Instruments - Cash Settlement - Gas** (139) (0.34) 300 0.87 (439) (1.21)
Sales of Natural Gas, NGL and Oil, including Cash Settlements 1,198 2.77 909 2.49 289 0.28 Lease Operating Expense 31 0.07 31 0.08 - (0.01) Production, Ad Valorem, and Other Fees 23 0.06 17 0.04 6 0.02 Transportation, Gathering and Compression 252 0.58 212 0.58 40 - Depreciation, Depletion and Amortization (DD&A) 373 0.86 350 0.97 23 (0.11) Natural Gas, NGL and Oil Production Costs 679 1.57 610 1.67 69
(0.10)
Natural Gas, NGL and Oil Production Margin$ 519 $ 1.20 $ 299 $ 0.82 $ 220 $ 0.38 *NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices. **Excluding hedge monetizations. The 67.5 Bcfe increase in volumes in the period-to period comparison was primarily due to the turn-in-line of new wells throughout 2020 and 2021. Additionally, in 2020 the Company temporarily shut-in new turn-in-line wells as a result of low natural gas and NGL pricing. The increases were offset in part by normal production declines. 46 --------------------------------------------------------------------------------
Changes in the average costs per Mcfe were primarily related to the following items:
•Lease operating expense decreased on a per unit basis as a result of increased production volume. •Production, ad valorem and other fees increased on a per unit basis as a result of increased realized prices on natural gas and natural gas liquids as well as the change in production mix by state as new wells are turned-in-line. •Depreciation, depletion and amortization expense decreased on a per unit basis as a result of low cost reserve additions from development during the 2020 period in SWPA, the addition of proved undeveloped Shale wells in theCentral Pennsylvania (CPA), and an impairment recognized in CBM in the 2020 period.
Average Realized Price Reconciliation
The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company's natural gas production and sales portfolio and information regarding settled commodity derivatives:
For the Nine Months Ended
in thousands (unless noted) 2021 2020 Variance Percent Change LIQUIDS NGL: Sales Volume (MMcfe) 26,083 19,927 6,156 30.9 % Sales Volume (Mbbls) 4,347 3,321 1,026 30.9 % Gross Price ($/Bbl) $ 31.32$ 12.24 $ 19.08 155.9 % Gross NGL Revenue$ 136,176 $ 40,691 $ 95,485 234.7 % Oil/Condensate: Sales Volume (MMcfe) 1,922 1,236 686 55.5 % Sales Volume (Mbbls) 320 206 114 55.3 % Gross Price ($/Bbl) $ 53.80$ 37.01 $ 16.79 45.4 % Gross Oil/Condensate Revenue$ 17,234 $ 7,630 $ 9,604 125.9 % NATURAL GAS Sales Volume (MMcf) 404,055 343,403 60,652 17.7 % Sales Price ($/Mcf) $ 2.93$ 1.63 $ 1.30 79.8 % Gross Natural Gas Revenue$ 1,183,178 $ 561,162 $ 622,016 110.8 % Hedging Impact ($/Mcf) $ (0.34)$ 0.87 $ (1.21) (139.1) % (Loss) Gain on Commodity Derivative Instruments - Cash Settlement*$ (139,045) $ 299,730 $ (438,775) (146.4) %
* Excluding gains from hedge monetization.
The increase in gross revenue was primarily the result of the$1.30 per Mcf increase in general natural gas prices, when excluding the impact of hedging, the 67.5 Bcfe increase in sales volumes, and the$19.08 per Bbl increase in NGL prices. These increases were offset, in-part, by the impact of the change in the realized (loss) gain on commodity derivative instruments related to the Company's hedging program. 47
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SEGMENT ANALYSIS for the nine months ended
For the Nine Months Ended Difference to Nine Months Ended
September 30, 2021 September 30, 2020
(in millions) Shale CBM Other Total Shale CBM Other Total
Natural Gas, NGLs and Oil Revenue
$ 728 Loss on Commodity Derivative Instruments (127) (12) (1,874) (2,013) (393) (45) (1,458) (1,896) Purchased Gas Revenue - - 67 67 - - (11) (11) Other Revenue and Operating Income 57 - 18 75 10 - 4 14 Total Revenue and Other Operating Income (Loss) 1,141 112 (1,787) (534) 299 - (1,464) (1,165) Lease Operating Expense 21 9 1 31 2 (2) - - Production, Ad Valorem, and Other Fees 19 4 - 23 5 - - 5 Transportation, Gathering and Compression 222 30 - 252 39 1 - 40 Depreciation, Depletion and Amortization 325 44 12 381 30 (6) - 24 Impairment of Exploration and Production Properties - - - - - - (62) (62) Impairment of Goodwill - - - - - - (473) (473) Exploration and Production Related Other Costs - - 8 8 - - (1) (1) Purchased Gas Costs - - 61 61 - - (16) (16) Other Operating Expense - - 52 52 - - (19) (19) Selling, General and Administrative Costs - - 77 77 - - 1 1 Total Operating Expense 587 87 211 885 76 (7) (570) (501) Other Expense - - 13 13 - - 1 1 Gain on Asset Sales and Abandonments, net - - (22) (22) - - - - Loss on Debt Extinguishment - - 19 19 - - 30 30 Interest Expense - - 114 114 - - (19) (19) Total Other Expense - - 124 124 - - 12 12 Total Costs and Expenses 587 87 335 1,009 76 (7) (558) (489)
Earnings (Loss) Before Income Tax
48--------------------------------------------------------------------------------
SHALE SEGMENT
The Shale segment had earnings before income tax of$554 million for the nine months endedSeptember 30, 2021 compared to earnings before income tax of$331 million for the nine months endedSeptember 30, 2020 .
For the Nine Months Ended
Percent
2021 2020 Variance Change
Shale Gas Sales Volumes (Bcf) 366.4 304.0 62.4 20.5 %
NGLs Sales Volumes (Bcfe)* 26.1 19.9 6.2 31.2 %
Oil/Condensate Sales Volumes (Bcfe)* 1.9 1.2 0.7 58.3 %
Total Shale Sales Volumes (Bcfe)* 394.4 325.1 69.3 21.3 %
Average Sales Price - Natural Gas (per Mcf) $ 2.89 $ 1.58 $ 1.31 82.9 %
(Loss) Gain on Commodity Derivative Instruments -
$ (0.35) $ 0.88 $ (1.23) (139.8) % Average Sales Price - NGLs (per Mcfe)*$ 5.22 $ 2.04 $ 3.18 155.9 % Average Sales Price - Oil/Condensate (per Mcfe)*$ 8.96 $ 5.98 $ 2.98 49.8 % Total Average Shale Sales Price (per Mcfe)$ 2.75 $ 2.45 $ 0.30 12.2 % Average Shale Lease Operating Expenses (per Mcfe) 0.05 0.06 (0.01) (16.7) %
Average Shale Production, Ad Valorem and Other Fees (per Mcfe) 0.05
0.04 0.01 25.0 %
Average Shale Transportation, Gathering and Compression Costs (per Mcfe)
0.56 0.56 - - %
Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe)
0.83 0.92 (0.09) (9.8) %
Total Average Shale Production Costs (per Mcfe) $ 1.49 $ 1.58 $ (0.09) (5.7) %
Total Average Shale Production Margin (per Mcfe) $ 1.26 $ 0.87 $ 0.39 44.8 %
* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals
six Mcf based upon the approximate relative energy content of oil and natural
gas, which is not indicative of the relationship of oil, NGL, condensate, and
natural gas prices.
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,211
million for the nine months ended September 30, 2021 compared to $529 million
for the nine months ended September 30, 2020 . The $682 million increase was due
primarily to an 82.9% increase in the average sales price for natural gas, a
21.3% increase in total Shale sales volumes, and a 155.9% increase in the
average sales price of NGLs. The increase in total Shale volumes was primarily
due to the turn-in-line of new wells throughout 2020 and the first half of 2021.
The increase was also due to the temporary shut-in of new turn-in-line wells in
2020 due to low natural gas prices, offset in part by normal production
declines.
The increase in total average Shale sales price was primarily due to a $1.31 per
Mcf increase in average gas sales price and a $3.18 per Mcfe increase in the
average NGL sales price. These increases were offset in part by a $1.23 per Mcf
change in the realized (loss) gain on commodity derivative instruments. The
notional amounts associated with these financial hedges represented
approximately 313.2 Bcf of the Company's produced Shale gas sales volumes for
the nine months ended September 30, 2021 at an average loss of $0.40 per Mcf
hedged. For the nine months ended September 30, 2020 , these financial hedges
represented approximately 296.6 Bcf at an average gain of $0.90 per Mcf hedged.
Total operating costs and expenses for the Shale segment were $587 million for
the nine months ended September 30, 2021 compared to $511 million for the nine
months ended September 30, 2020 . The increase in total dollars and decrease in
unit costs for the Shale segment were due to the following items:
•Shale lease operating expenses were $21 million for the nine months ended
September 30, 2021 compared to $19 million for the nine months ended
September 30, 2020 . The increase in total dollars and decrease in unit costs
were primarily related to the increase in production volumes.
•Shale production, ad valorem and other fees were $19 million for the nine
months ended September 30, 2021 compared to $14 million for the nine months
ended September 30, 2020 . The increases in total dollars and unit costs were
primarily due to increased realized prices on natural gas and natural gas
liquids as well as the change in production mix by state as new wells are
turned-in-line.
49
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•Shale transportation, gathering and compression costs were $222 million for the
nine months ended September 30, 2021 compared to $183 million for the nine
months ended September 30, 2020 . The increase in total dollars was primarily
related to the increase in production volumes, increased processing costs due to
a wetter production mix, and increased firm transportation costs.
•Depreciation, depletion and amortization costs attributable to the Shale
segment were $325 million for the nine months ended September 30, 2021 compared
to $295 million for the nine months ended September 30, 2020 . The increase in
total dollars was due to the increase in production volumes. These amounts
included depletion on a unit of production basis of $0.72 per Mcfe and $0.81 per
Mcfe, respectively. The decrease in the units of production depreciation,
depletion and amortization rate in the current period is primarily the result of
low-cost reserve additions from development in 2020 in SWPA as well as the
addition of proved undeveloped Shale reserves in CPA. The remaining
depreciation, depletion and amortization costs were either recorded on a
straight-line basis or related to asset retirement obligations.
Total Shale other revenue and operating income relates to natural gas gathering
services provided to third-parties. The Shale segment had other revenue and
operating income of $57 million for the nine months ended September 30, 2021
compared to $47 million for the nine months ended September 30, 2020 . The
increase in the period-to-period comparison was primarily due to temporary
production curtailments by third party customers that occurred in the 2020
period. Those curtailments were restored to full production in the latter half
of 2020.
COALBED METHANE (CBM) SEGMENT
The CBM segment had earnings before income tax of $25 million for the nine
months ended September 30, 2021 compared to earnings before income tax of $18
million for the nine months ended September 30, 2020 .
For the Nine Months Ended
Percent
2021 2020 Variance Change
CBM Gas Sales Volumes (Bcf) 37.5 39.3 (1.8) (4.6) %
Average Sales Price - Gas (per Mcf) $ 3.32 $ 2.02 $ 1.30 64.4 %
(Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf)
$ (0.33) $ 0.84 $ (1.17) (139.3) % Total Average CBM Sales Price (per Mcf)$ 2.99 $ 2.86 $ 0.13 4.5 % Average CBM Lease Operating Expenses (per Mcf) 0.25 0.29 (0.04) (13.8) %
Average CBM Production, Ad Valorem and Other Fees (per Mcf) 0.12
0.10 0.02 20.0 %
Average CBM Transportation, Gathering and Compression Costs (per Mcf)
0.78 0.74 0.04 5.4 %
Average CBM Depreciation, Depletion and Amortization Costs (per Mcf)
1.17 1.25 (0.08) (6.4) %
Total Average CBM Production Costs (per Mcf) $ 2.32 $ 2.38 $ (0.06) (2.5) %
Total Average CBM Production Margin (per Mcf) $ 0.67 $ 0.48 $ 0.19 39.6 %
The CBM segment had natural gas revenue of $124 million for the nine months
ended September 30, 2021 compared to $79 million for the nine months ended
September 30, 2020 . The $45 million increase was primarily due to a 64.4%
increase in the average sales price for natural gas in the current period. The
natural gas price increases were partially offset by the 4.6% decrease in CBM
sales volumes due to normal production declines.
The total average CBM sales price increased $0.13 per Mcf due to a $1.30 per Mcf
increase in average gas sales price, offset in part by a $1.17 per Mcf change in
the realized (loss) gain on commodity derivative instruments resulting from the
Company's hedging program. The notional amounts associated with these financial
hedges represented approximately 30.6 Bcf of the Company's produced CBM sales
volumes for the nine months ended September 30, 2021 at an average loss of $0.40
per Mcf hedged. For the nine months ended September 30, 2020 , these financial
hedges represented approximately 37.0 Bcf at an average gain of $0.90 per Mcf
hedged.
Total operating costs and expenses for the CBM segment were $87 million for the
nine months ended September 30, 2021 compared to $94 million for the nine months
ended September 30, 2020 . The decreases in total dollars and unit costs for the
CBM segment were due to the following items:
50
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•CBM lease operating expense was
•CBM transportation, gathering and compression costs were$30 million for the nine months endedSeptember 30, 2021 compared to$29 million for the nine months endedSeptember 30, 2020 . The increases in total dollars and unit costs were primarily due to an increase in firm transportation expense. •Depreciation, depletion and amortization costs attributable to the CBM segment were$44 million for the nine months endedSeptember 30, 2021 compared to$50 million for the nine months endedSeptember 30, 2020 . These amounts included depletion on a unit of production basis of$0.66 per Mcfe and$0.68 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate was primarily due to an impairment in the 2020 period that reduced the carrying value of the underlying CBM asset base. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
OTHER SEGMENT
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, realized gain on commodity derivative instruments that were monetized prior to their contractual settlement dates, exploration and production related other costs, impairments, as well as various other expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes. The Other Segment had a loss before income tax of$2,122 million for the nine months endedSeptember 30, 2021 compared to a loss before income tax of$1,216 million for the nine months endedSeptember 30, 2020 . The decrease in total dollars is discussed below. For the
Nine Months Ended
2021 2020 Variance Percent Change
Other Gas Sales Volumes (Bcf) 0.2 0.1 0.1 100.0 %
Loss on Commodity Derivative Instruments and Monetization
For the nine months endedSeptember 30, 2021 , the Other Segment recognized an unrealized loss on commodity derivative instruments of$1,874 million . For the nine months endedSeptember 30, 2020 , the Other Segment recognized an unrealized loss on commodity derivative instruments of$501 million as well as cash settlements received of$85 million ,$84 million of which related to natural gas hedges that were partially monetized prior to their settlement dates. The unrealized loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis. See Note 11 - Derivative Instruments in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the cash settlements.
Purchased gas volumes represent volumes of natural gas purchased at market prices from third-parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenues were$67 million for the nine months endedSeptember 30, 2021 compared to$78 million for the nine months endedSeptember 30, 2020 . Purchased gas costs were$61 million for the nine months endedSeptember 30, 2021 compared to$77 million for the nine months endedSeptember 30, 2020 . The period-to-period decrease in purchased gas revenue was due to a decrease in purchased gas sales volumes, offset in part by an increase in averages sales price. For the
Nine Months Ended
2021 2020 Variance Percent Change
Purchased Gas Sales Volumes (in Bcf) 20.5 48.2 (27.7) (57.5) %
Average Sales Price (per Mcf) $ 3.25 $ 1.63 $ 1.62 99.4 %
Purchased Gas Average Cost (per Mcf) $ 2.99 $ 1.59 $ 1.40 88.1 %
51--------------------------------------------------------------------------------
Other Operating Income
For the Nine Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Equity Income (Loss) from Affiliates $ 3 $ (1) $ 4 400.0 %
Water Income 6 5 1 20.0 %
Excess Firm Transportation Income 9 9 - - %
Other - 1 (1) (100.0) %
Total Other Operating Income $ 18 $ 14 $ 4 28.6 %
•Equity income (loss) from affiliates primarily represents CNX's share of
earnings from a 50% interest in a power plant located within CNX's CBM field.
Power generated from the facility is sold into wholesale electricity markets
during times of peak energy consumption. Due to the plant consuming coal mine
methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy
Credits.
•Excess firm transportation income represents revenue from the sale of excess
firm transportation capacity to third-parties. The Company obtains firm pipeline
transportation capacity to enable gas production to flow uninterrupted as sales
volumes increase. In order to minimize this unutilized firm transportation
expense, CNX is able to release (sell) unutilized firm transportation capacity
to other parties when possible and when beneficial. The revenue from released
capacity helps offset the unutilized firm transportation and processing fees in
total other operating expense.
Impairment of
During the nine months endedSeptember 30, 2020 , CNX recognized certain indicators of impairments specific to our SWPA CBM asset group and determined that the carrying value of that asset group was not recoverable. The fair value of the asset group was estimated by discounting the estimated future cash flows using discount rates and other assumptions that market participants would use in their estimates of fair value. As a result, an impairment of$62 million was recognized and is included in Impairment ofExploration and Production Properties in the Consolidated Statements of Income for the nine months endedSeptember 30, 2020 . The impairment was related to an economic decision to temporarily idle certain wells and the related processing facility during the first quarter. See Note 5 - Property, Plant and Equipment in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such impairment occurred in the current period.
Impairment of
In connection with the Midstream Acquisition that occurred in
Goodwill is tested for impairment annually during the fourth quarter, or more frequently if recent events or prevailing conditions indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount using the qualitative assessment, a quantitative impairment test is performed. From time to time, CNX may also bypass the qualitative assessment and proceed directly to the quantitative impairment test. In connection with CNX's assessment of goodwill in the first quarter of 2020 in relation to the deteriorating macroeconomic conditions, and the decline in the observable market value of CNXM securities both in relation to the COVID-19 pandemic and the overall decline in the MLP market space, CNX bypassed the qualitative assessment and performed a quantitative test that utilized a combination of the income and market approaches to estimate the fair value of the Midstream reporting unit. As a result of this assessment, CNX concluded that the carrying value exceed its estimated fair value, and as a result, an impairment of$473 million was included in Impairment ofGoodwill in the Consolidated Statements of Income for the nine months endedSeptember 30, 2020 . See Note 6 -Goodwill and Other Intangible Assets in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. No such impairment occurred in the current period. 52
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Exploration and Production Related Other Costs
For the Nine Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Permitting Expense $ 1 $ 2 $ (1) (50.0) %
Lease Expiration Costs 5 5 - - %
Land Rentals 2 2 - - %
Total Exploration and Production Related Other
Costs $ 8 $ 9 $ (1) (11.1) %
•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months.
Selling, General and Administrative ("SG&A")
SG&A costs include costs such as overhead, including employee labor and benefit
costs, short-term incentive compensation, costs of maintaining our headquarters,
audit and other professional fees, and legal compliance expenses. SG&A costs
also include non-cash long-term equity-based compensation expense.
For the Nine Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Long-Term Equity-Based Compensation
(Non-Cash) $ 14 $ 12 $ 2 16.7 %
Short-Term Incentive Compensation 8 7 1 14.3 %
Salaries, Wages and Employee Benefits 20 23 (3) (13.0) %
Other 35 34 1 2.9 %
Total SG&A $ 77 $ 76 $ 1 1.3 %
•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in equity awards. •Salaries, wages and employee benefits decreased in the period-to-period comparison primarily due to a decrease in employees.
Other Operating Expense
For the Nine Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Unutilized Firm Transportation and Processing Fees $ 41
(24.1) %
Idle Equipment and Service Charges - 8 (8) (100.0) %
Insurance Expense 1 2 (1) (50.0) %
Water Expense 1 1 - - %
Litigation Settlements 6 - 6 100.0 %
Other 3 6 (3) (50.0) %
Total Other Operating Expense $ 52 $ 71 $ (19) (26.8) %
•Unutilized firm transportation and processing fees represent pipeline
transportation capacity obtained to enable gas production to flow uninterrupted
as sales volumes increase, as well as additional processing capacity for NGLs.
In some instances, the Company may have the opportunity to realize more
favorable net pricing by strategically choosing to sell natural gas into a
market or to a customer that does not require the use of the Company's own firm
transportation capacity. Such sales would result in an increase in unutilized
firm transportation expense. The Company attempts to minimize this expense by
releasing (selling) unutilized firm transportation capacity to other parties
when possible and when beneficial. The revenue received when this capacity is
released (sold) is included in Excess Firm Transportation Income above. The
decrease in the period-to-period comparison was primarily due to an increase in
utilization of firm transportation capacity in the current year due to
production increases in 2021 compared to 2020.
•Idle equipment and service charges relate to the temporary idling of certain 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 decrease in the period-to-period comparison was the result of two of CNX's
drilling rigs being idled in the prior period.
53
--------------------------------------------------------------------------------Other Expense
For
the Nine Months Ended
(in millions) 2021 2020 Variance Percent Change Other Income Interest Income $ -$ 2 $ (2) (100.0) % Right-of-Way Sales 2 2 - - % Other 3 7 (4) (57.1) % Total Other Income $ 5$ 11 $ (6) (54.5) % Other Expense Merger-Related Costs $ -$ 5 $ (5) (100.0) % Professional Services 5 6 (1) (16.7) % Bank Fees 9 9 - - % Other Corporate Expense 4 3 1 33.3 % Total Other Expense $ 18$ 23 $ (5) (21.7) % Total Other Expense $ 13$ 12 $ 1 8.3 % •Other income decreased in the period-to-period comparison primarily due to the receipt of a severance tax refund related to a prior period in the nine months endedSeptember 30, 2020 as well as additional interest income related to the alternative minimum tax credit refund CNX received (See Note 4 - Income Taxes in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). •Merger-related costs consist of transaction costs directly attributable to the CNXM Merger (See Note 13 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), including financial advisory, legal service and other professional fees, which were recorded to Other Expense in the Consolidated Statements of Income.
Gain on Asset Sales and Abandonments, net
A gain on asset sales of$22 million related to the sale of various non-core assets was recognized in both the nine months endedSeptember 30, 2021 and the nine months endedSeptember 30, 2020 .
Loss (Gain) on Debt Extinguishment
A loss on debt extinguishment of$19 million was recognized in the nine months endedSeptember 30, 2021 compared to a gain on debt extinguishment of$11 million in the nine months endedSeptember 30, 2020 . During the nine months endedSeptember 30, 2021 , CNXM purchased a portion of the 6.50% Senior Notes dueMarch 2026 and repaid in full and terminated theCardinal States Gathering Company LLC andCSG Holdings II LLC non-revolving credit facilities. During the nine months endedSeptember 30, 2020 , CNX purchased$531 million of its 5.875% Senior Notes dueApril 2022 at an average price equal to 97.5% of the principal amount. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
Interest Expense
For the Nine Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Total Interest Expense $ 114 $ 133 $ (19) (14.3) %
•The $19 million decrease was primarily due to the purchase of the remaining
$894 million of the 5.875% Senior Notes due April 2022 during the year ended
December 31, 2020 , as well as lower borrowings on the CNX Credit Facility and
higher unrealized gains on interest rate swap agreements. These decreases were
offset in part by interest related to the addition of $345 million of
Convertible Notes due 2026, $500 million of 6.00% Senior Notes due 2029, and
$200 million of 7.25% Senior Notes due 2027. The amortization of debt discount
in connection with the Convertible Notes also contributed to an increase. See
Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial
Statements in Item 1 of this Form 10-Q for additional information.
54
--------------------------------------------------------------------------------Income Taxes
For the Nine Months Ended September 30,
(in millions) 2021 2020 Variance Percent Change
Total Company Loss Before Income Tax $ (1,543) $ (867) $ (676) (78.0) %
Income Tax Benefit $ (414) $ (243) $ (171) (70.4) %
Effective Income Tax Rate 26.8 % 28.0 % (1.2) %
The effective income tax rate was 26.8% for the nine months ended September 30,
2021 compared to 28.0% for the nine months ended September 30, 2020 . The
effective rate for the nine months ended September 30, 2021 differs from the
U.S. federal statutory rate of 21% primarily due to the impact of federal tax
credits, equity compensation and state income taxes. The effective rate for the
nine months ended September 30, 2020 differs from the U.S. federal statutory
rate of 21% primarily due to the impact of noncontrolling interest, equity
compensation, and state income taxes (See Note 4 - Income Taxes in the Notes to
the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for
additional information).
Liquidity and Capital Resources
CNX generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CNX currently believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments, if any, and to provide required letters of credit for the current fiscal year. Nevertheless, the ability of CNX to satisfy its working capital requirements, to service its debt obligations, to fund planned capital expenditures, or to pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, including the current COVID 19 pandemic, some of which are beyond CNX's control. From time to time, CNX is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CNX sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity. CNX continuously reviews its liquidity and capital resources. If market conditions were to change, for instance due to a significant decline in commodity prices and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be reduced. As ofSeptember 30, 2021 , CNX was in compliance with all of its debt covenants. After considering the potential effect of a significant decline in commodity prices, CNX currently expects to remain in compliance with its debt covenants. In order to manage the market risk exposure of volatile natural gas prices in the future, CNX enters into various physical natural gas supply transactions with both gas marketers and end users for terms varying in length. CNX also enters into various financial natural gas swap transactions to manage the market risk exposure to in-basin and out-of-basin pricing. The fair value of these contracts was a net liability of$1,756 million atSeptember 30, 2021 and a net asset of$118 million atDecember 31, 2020 . The Company has not experienced any issues of non-performance by derivative counterparties. CNX frequently evaluates potential acquisitions. CNX has historically 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. 55
--------------------------------------------------------------------------------
Cash Flows (in millions)
For the
Nine Months Ended
2021 2020 Change
Cash Provided by Operating Activities $ 673 $ 634 $ 39
Cash Used in Investing Activities $ (325) $ (363) $ 38
Cash Used in Financing Activities $ (149) Cash flows from operating activities changed in the period-to-period comparison primarily due to the following items:
•Net loss increased$504 million in the period-to-period comparison. •Adjustments to reconcile net loss to cash provided by operating activities primarily consisted of a$473 million impairment of goodwill and a$62 million impairment of exploration and production properties in the prior year, a$228 million change in deferred income taxes, a$1,373 million net change in commodity derivative instruments, a$29 million change in gain/loss on debt extinguishment, as well as various other changes in working capital.
Cash flows from investing activities changed in the period-to-period comparison primarily due to the following items:
•Capital expenditures decreased$46 million in the period-to-period comparison primarily due to decreased expenditures in the Shale segment resulting from decreased drilling and completions activity as well as decreased midstream activity. •Proceeds from asset sales decreased$8 million mainly due to decreased sales of surface and oil and gas interests in the nine months endedSeptember 30, 2021 .
Cash flows from financing activities changed in the period-to-period comparison primarily due to the following items:
•During the nine months endedSeptember 30, 2021 , CNXM paid$175 million to purchase$166 million of CNXM 6.50% Senior Notes due inMarch 2026 at 105.4% of the principal amount. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •During the nine months endedSeptember 30, 2021 , CNXM closed on$400 million aggregate principal amount of CNXM 4.75% Senior Notes dueApril 2030 at a price of 98.8% for cash proceeds of$395 million . See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •During the nine months endedSeptember 30, 2020 , CNX paid$519 million to purchase$531 million of senior notes due in 2022 at 97.7% of the principal amount. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •In the nine months endedSeptember 30, 2021 , there were$145 million of net payments on the CNXM Credit Facility compared to$31 million of net proceeds during the nine months endedSeptember 30, 2020 . •In the nine months endedSeptember 30, 2021 , there were$65 million of net proceeds on the CNX Credit Facility compared to$251 million of net payments during the nine months endedSeptember 30, 2020 . •During the nine months endedSeptember 30, 2021 , there were$161 million of net payments on the Cardinal States Facility and CSG Holdings Facility compared to$164 million of net proceeds in the nine months endedSeptember 30, 2020 . See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •During the nine months endedSeptember 30, 2021 , CNX repurchased$124 million of its common stock on the open market compared to no purchases in the nine months endedSeptember 30, 2020 . •During the nine months endedSeptember 30, 2020 , CNX closed on$200 million aggregate principal amount of its 7.25% Senior Notes dueMarch 2027 at a price of 103.5% for cash proceeds of$207 million . See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •During the nine months endedSeptember 30, 2020 , CNX received proceeds of$335 million from the issuance of Convertible Notes due 2026. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •During the nine months endedSeptember 30, 2020 , CNX paid$36 million for capped call transactions related to the issuance of the Convertible Notes as mentioned above. See Note 9 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. •During the nine months endedSeptember 30, 2020 there were$42 million of payments to CNXM noncontrolling interest holders compared to no payments during the nine months endedSeptember 30, 2021 due to the Merger with 56 -------------------------------------------------------------------------------- CNXM. See Note 13 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.
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 $ 721 $
860 $ - $ -
260,453 427,490 393,544 992,713 2,074,200
Long-Term Debt 232,193 371,350 249,463 1,600,926 2,453,932
Interest on Long-Term Debt 107,204 225,089 215,026 176,374 723,693
Finance Lease Obligations 495 845 241 11 1,592
Interest on Finance Lease Obligations 27 47 17 - 91
Operating Lease Obligations 35,461 7,920 7,051 19,814 70,246
Interest on Operating Lease Obligations 2,352 3,326 2,534 2,637 10,849
Long-Term Liabilities-Employee Related (a) 2,032 4,259 4,621 33,957 44,869
Other Long-Term Liabilities (b) 191,486 10,000 10,000 61,029 272,515
Total Contractual Obligations (c) $ 832,424 $
1,051,186
_________________________
(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 table above does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
Debt
AtSeptember 30, 2021 , CNX had total long-term debt of$2,454 million , including the current portion of long-term debt of$232 million and excluding unamortized debt issuance costs. This long-term debt consisted of: •An aggregate principal amount of$700 million of 7.25% Senior Notes dueMarch 2027 plus$6 million of unamortized bond premium. Interest on the notes is payableMarch 14 andSeptember 14 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). •An aggregate principal amount of$500 million of 6.00% Senior Notes dueJanuary 2029 . Interest on the notes is payableJanuary 15 andJuly 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). •An aggregate principal amount of$400 million of 4.75% Senior Notes dueApril 2030 issued by CNXM, less$5 million of unamortized bond discount. Interest on the notes is payableApril 15 andOctober 15 of each year. Payment of the principal and interest on the notes is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of these notes. •An aggregate principal amount of$345 million of 2.25% Convertible Notes dueMay 2026 , unless earlier redeemed, repurchased, or converted, less$95 million of unamortized bond discount and issuance costs. Interest on the notes is payableMay 1 andNovember 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). •An aggregate principal amount of$234 million of 6.50% Senior Notes dueMarch 2026 issued by CNXM, less$2 million of unamortized bond discount. Interest on the notes is payableMarch 15 andSeptember 15 of each year. Payment of 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$225 million in outstanding borrowings under the CNX Credit Facility. Payment of the principal and interest on the CNX Credit Facility is guaranteed by most of CNX's subsidiaries but does not include CNXM (or its subsidiaries or general partner). •An aggregate principal amount of$146 million in outstanding borrowings under the CNXM Credit Facility. Payment of the principal and interest on the CNXM Credit Facility is guaranteed by certain of CNXM's subsidiaries. CNX is not a guarantor of the CNXM Facility. 57 -------------------------------------------------------------------------------- Total Equity and Dividends CNX had total equity of$3,187 million atSeptember 30, 2021 compared to$4,422 million atDecember 31, 2020 . See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details. OnSeptember 28, 2020 , the Merger of CNXM was completed (See Note 13 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information). CNX accounted for the change in our ownership interest in CNXM as an equity transaction which was reflected as a reduction of noncontrolling interest with corresponding increases to common stock and capital in excess of par value. The declaration and payment of dividends by CNX is subject to the discretion of CNX's Board of Directors, and no assurance can be given that CNX will pay dividends in the future. CNX suspended its quarterly dividend inMarch 2016 to further reflect the Company's increased emphasis on growth at that time. The determination to pay dividends in the future will depend upon, among other things, general business conditions, CNX's financial results, contractual and legal restrictions regarding the payment of dividends by CNX, planned investments by CNX, and such other factors as the Board of Directors deems relevant. CNX's Credit Facility limits its ability to pay dividends in excess of an annual rate of$0.10 per share when the Company's net leverage ratio exceeds 3.00 to 1.00 and is subject to availability under the Credit Facility of at least 20% of the aggregate commitments and there being no borrowing base deficiency. The net leverage ratio was 2.02 to 1.00 atSeptember 30, 2021 . The Credit Facility does not permit such dividend payments when an event of default has occurred and is continuing. The indentures to the 7.25% Senior Notes dueMarch 2027 and the 6.00% Senior Notes dueJanuary 2029 limit dividends to$0.50 per share annually unless several conditions are met. These conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the nine months endedSeptember 30, 2021 . 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 Unaudited 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 atSeptember 30, 2021 . Management believes these items will expire without being funded. See Note 10 - Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CNX. 58 --------------------------------------------------------------------------------
Forward-Looking Statements
We are including the following cautionary statement in this Quarterly Report on
Form 10-Q to make applicable and take advantage of the safe harbor provisions of
the Private Securities Litigation Reform Act of 1995 for any forward-looking
statements made by, or on behalf of us. With the exception of historical
matters, the matters discussed in this Quarterly Report on Form 10-Q are
forward-looking statements (as defined in Section 21E of the Exchange Act) that
involve risks and uncertainties that could cause actual results to differ
materially from projected results. Accordingly, investors should not place undue
reliance on forward-looking statements as a prediction of actual results. The
forward-looking statements may include projections and estimates concerning the
timing and success of specific projects and our future production, revenues,
income and capital spending. When we use the words "believe," "intend,"
"expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict,"
"project," "will," or their negatives, or other similar expressions, the
statements which include those words are usually forward-looking statements.
When we describe a strategy that involves risks or uncertainties, we are making
forward-looking statements. The forward-looking statements in this Quarterly
Report on Form 10-Q speak only as of the date of this Quarterly Report on Form
10-Q; we disclaim any obligation to update these statements unless required by
securities law, and we caution you not to rely on them unduly. We have based
these forward-looking statements on our current expectations and assumptions
about future events. While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to significant
business, economic, competitive, regulatory and other risks, contingencies and
uncertainties, most of which are difficult to predict and many of which are
beyond our control. These risks, contingencies and uncertainties relate to,
among other matters, the following:
•prices for natural gas and natural gas liquids are volatile and can fluctuate
widely based upon a number of factors beyond our control including oversupply
relative to the demand for our products, weather and the price and availability
of alternative fuels;
•unsuccessful drilling efforts or continued natural gas price decreases
requiring write downs of our proved natural gas properties, or changes in
assumptions impacting management's estimates of future financial results as well
as other assumptions such as movement in our stock price, weighted-average cost
of capital, terminal growth rates and industry multiples, could cause goodwill
and other intangible assets we hold to become impaired and result in material
non-cash charges to earnings;
•a loss of our competitive position because of the competitive nature of the
natural gas industry, consolidation within the industry or overcapacity in the
industry adversely affecting our ability to sell our products and midstream
services;
•deterioration in the economic conditions in any of the industries in which our
customers operate, a domestic or worldwide financial downturn, or negative
credit market conditions;
•hedging activities may prevent us from benefiting from price increases and may
expose us to other risks;
•negative public perception regarding our Company or industry could have an
adverse effect on our operations, financial results or stock price;
•events beyond our control, including a global or domestic health crisis;
•dependence on gathering, processing and transportation facilities and other
midstream facilities owned by others, and disruption of, capacity constraints
in, or proximity to pipeline, and any decrease in availability of pipelines or
other midstream facilities;
•uncertainties in estimating our economically recoverable natural gas reserves
and inaccuracies in our estimates;
•the high-risk nature of drilling, developing and operating natural gas wells;
•our identified drilling locations are scheduled out over multiple years, making
them susceptible to uncertainties that could materially alter the occurrence or
timing of their development or drilling;
•the substantial capital expenditures required for our development and
exploration projects, as well as midstream system development;
•decreases in the availability of, or increases in the price of, required
personnel, services, equipment, parts and raw materials in sufficient quantities
or at reasonable costs to support our operations;
•our ability to find adequate water sources for our use in shale gas drilling
and production operations, or our ability to dispose of, transport or recycle
water used or removed in connection with our gas operations at a reasonable cost
and within applicable environmental rules;
•failure to successfully estimate the rate of decline of existing reserves or to
find or acquire economically recoverable natural gas reserves to replace our
current natural gas reserves;
•losses incurred as a result of title defects in the properties in which we
invest or the loss of certain leasehold or other rights related to our midstream
activities;
•the impact of climate change legislation, litigation and potential, as well as
any adopted, environmental regulations, including those relating to greenhouse
gas emissions;
•environmental regulations can increase costs and introduce uncertainty that
could adversely impact the market for natural gas with potential short and
long-term liabilities;
59
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•existing and future government laws, regulations and other legal requirements
and judicial decisions that govern our business may increase our costs of doing
business and may restrict our operations;
•significant costs and liabilities may be incurred as a result of pipeline
operations and related increase in the regulation of natural gas gathering
pipelines;
•changes in federal or state income tax laws or rates;
•the outcomes of various legal proceedings, including those which are more fully
described in our reports filed under the Exchange Act;
•risks associated with our current long-term debt obligations;
•a decrease in our borrowing base, which could decrease for a variety of reasons
including lower natural gas prices, declines in natural gas proved reserves,
asset sales and lending requirements or regulations;
•risks associated with our Convertible Notes due May 2026 , including the
potential impact that the Convertible Notes may have on our reported financial
results, potential dilution, our ability to raise funds to repurchase the
Convertible Notes, and that provisions of the Convertible Notes could delay or
prevent a beneficial takeover of the Company;
•the potential impact of the capped call transaction undertaken in tandem with
the Convertible Notes issuance, including counterparty risk;
•challenges associated with strategic determinations, including the allocation
of capital and other resources to strategic opportunities;
•acquisitions and divestitures, we anticipate may not occur or produce
anticipated benefits;
•there is no guarantee that we will continue to repurchase shares of our common
stock under our current or any future share repurchase program at levels
undertaken previously or at all;
•we may operate a portion of our business with one or more joint venture
partners or in circumstances where we are not the operator, which may restrict
our operational and corporate flexibility and we may not realize the benefits we
expect to realize from a joint venture;
•CONSOL Energy may not be able to satisfy its indemnification obligations in the
future and such indemnities may not be sufficient to hold us harmless from the
full amount of liabilities for which CONSOL Energy may be allocated
responsibility;
•cyber-incidents could have a material adverse effect on our business, financial
condition or results of operations;
•our success depends on key members of our management and our ability to attract
and retain experienced technical and other professional personnel;
•terrorist activities could materially adversely affect our business and results
of operations; and
•certain other factors addressed in this report and in our 2020 Form 10-K under
"Risk Factors".
Although forward-looking statements reflect our good faith beliefs at the time
they are made, they involve known and unknown risks, uncertainties and other
factors. For more information concerning factors that could cause actual results
to differ materially from those conveyed in the forward-looking statements,
including, among others, that our business plans may change as circumstances
warrant, please refer to the "Risk Factors" and "Forward-Looking Statements"
sections of our Annual Report 2020 Form 10-K and subsequent Quarterly Reports on
Form 10-Q. We undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new information, future
events, changed circumstances or otherwise, unless required by law.
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