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Supplemental Gas Data (unaudited) (Tables)
 12 Months Ended
Dec. 31, 2021
Extractive Industries [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure
Capitalized Costs:
As of December 31,
20212020
Intangible Drilling Costs$5,247,800 $4,965,252 
Gas Gathering Assets2,483,561 2,510,916 
Proved Gas Properties1,312,706 1,253,094 
Unproved Gas Properties730,400 725,705 
Gas Wells and Related Equipment1,202,731 1,120,061 
Other Gas Assets96,279 95,734 
Total Property, Plant and Equipment11,073,477 10,670,762 
Accumulated Depreciation, Depletion and Amortization(4,279,070)(3,852,593)
Net Capitalized Costs$6,794,407 $6,818,169 
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure
Costs incurred for property acquisition, exploration and development (*):
For the Years Ended December 31,
202120202019
Property Acquisitions:
Proved Properties
$32,355 $16,622 $36,710 
Unproved Properties
20,568 8,060 24,760 
Development**393,641 432,438 1,063,945 
Exploration30,927 33,644 79,855 
Total$477,491 $490,764 $1,205,270 
__________
(*)    Includes costs incurred whether capitalized or expensed.
(**)    Includes development costs for midstream of $35 million, $67 million and $325 million for 2021, 2020 and 2019, respectively.
Results of Operations for Oil and Gas Producing Activities Disclosure
Results of Operations for Producing Activities:
For the Years Ended December 31,
202120202019
Natural Gas, NGLs and Oil Revenue$2,183,929 $896,745 $1,364,325 
Realized (Loss) Gain on Commodity Derivative Instruments (539,016)461,217 69,780 
Unrealized (Loss) Gain on Commodity Derivative Instruments(1,093,717)(288,235)306,325 
Purchased Gas Revenue99,713 105,792 94,027 
Total Revenue650,909 1,175,519 1,834,457 
Lease Operating Expense46,256 40,407 65,443 
Production, Ad Valorem and Other Fees34,051 24,196 27,461 
Transportation, Gathering and Compression343,635 285,683 330,539 
Purchased Gas Costs93,776 100,902 90,553 
Impairment of Exploration and Production Properties— 61,849 327,400 
Impairment of Undeveloped Properties— — 119,429 
Exploration Costs20,626 14,994 44,380 
Depreciation, Depletion and Amortization515,118 501,821 508,463 
Total Costs1,053,462 1,029,852 1,513,668 
Pre-tax Operating (Loss) Income(402,553)145,667 320,789 
Income Tax (Benefit) Expense(87,354)42,098 149,167 
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$(315,199)$103,569 $171,622 
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure
The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:
For the Years Ended December 31,
202120202019
Production (MMcfe)590,248 511,072 539,149 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$3.70 $1.75 $2.53 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$(0.98)$0.78 $0.14 
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$2.79 $2.49 $2.66 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.08 $0.08 $0.12 
Schedule of Gas and Oil Acreage
The following table sets forth, at December 31, 2021, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,716 4,432 
Producing Gas Wells - Royalty Interest2,031 — 
Producing Oil Wells - Royalty Interest150 — 
Acreage Position:
   Proved Developed Acreage376,850 376,850 
   Proved Undeveloped Acreage41,605 41,605 
   Unproved Acreage4,756,680 3,442,159 
Total Acreage5,175,135 3,860,614 
____________
(1)    All of our acreage identified as proved developed and undeveloped is controlled fully by CNX through ownership of a 100% working interest.
(2)    Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities
The gas reserves estimates are as follows:
CondensateConsolidated
Natural GasNGLs& Crude OilOperations
(MMcf)(Mbbls)(Mbbls)(MMcfe)
Balance December 31, 2018 (a)7,436,338 65,904 8,261 7,881,335 
Revisions (b)(521,617)5,926 (5,418)(518,570)
Price Changes(40,773)(740)(5)(45,246)
Extensions and Discoveries (c)1,569,813 10,182 2,732 1,647,297 
Production(505,355)(5,428)(204)(539,149)
Balance December 31, 2019 (a)7,938,406 75,844 5,366 8,425,667 
Revisions (d)407,836 51,857 3,525 740,129 
Price Changes(1,019,523)(50,456)(4,946)(1,351,934)
Extensions and Discoveries (c)2,188,773 9,299 400 2,246,968 
Production(481,426)(4,677)(264)(511,072)
Balance December 31, 2020 (a)9,034,066 81,867 4,081 9,549,758 
Revisions (e)(409,215)13,655 39 (327,050)
Price Changes82,248 692 22 86,532 
Extensions and Discoveries (c)832,696 12,047 294 906,738 
Production(551,988)(5,976)(400)(590,248)
Balance December 31, 2021 (a)8,987,807 102,285 4,036 9,625,730 
Proved developed reserves:
December 31, 20194,473,534 59,800 1,087 4,838,858 
December 31, 20204,939,283 42,204 1,207 5,199,748 
December 31, 20215,569,332 53,204 2,843 5,905,611 
Proved undeveloped reserves:
December 31, 20193,464,873 16,044 4,278 3,586,809 
December 31, 20204,094,783 39,664 2,874 4,350,010 
December 31, 20213,418,475 49,081 1,193 3,720,119 
__________
(a)    Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods.
(b)    The downward revisions in 2019 are due to changes in our five-year development plan due to increased dry gas investment which increased dry gas proved undeveloped reserves and decreased wet gas investment which lowered wet gas proved undeveloped reserves. The investment shift was a result of a significant decrease in forecasted liquids price realizations in the five-year plan. These five-year plan changes resulted in the removal of 872 Bcfe in reserves for wet gas investment. There was additionally a reduction of 304 Bcfe related to removal of proved undeveloped locations removed from our plans due to the SEC five-year development rule. These downward revisions were partially offset by efficiencies in operations investment in dry gas properties which increased reserves by 657 Bcfe.
(c)    Extensions and Discoveries in 2019, 2020, and 2021 are due to the addition of wells on the Company’s Shale acreage more than one offset location away with continued use of reliable technology. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sits and data exchanges to confirm continuity of the formation. Total proved extensions and discoveries are a combination of proved developed and proved undeveloped reserves; and, extensions and discoveries
for proven developed reserves are associated with non-operated assets and exploratory wells. In 2021, 2020 and 2019, the Company added 26 Bcfe, 70 Bcfe and 77 Bcfe, respectively, related to exploratory and non-operated wells.
(d)    Upward revisions in 2020 are due to performance revisions of 579 Bcfe related to production performance and an 853 Bcfe increase in reserves due to a decrease in operating costs in 2020. These upward revisions were partially offset by negative revisions of 677 Bcfe due to changes in our development plan related to the removal of four Utica wells and 23 Marcellus wells from our development plan.
(e)    The downward revisions in 2021 are partly due to changes in our five-year development plan that are driven by acreage consolidation initiatives. These initiatives resulted in 267 Bcfe being removed. Additional downward revisions, of 356 Bcfe are due to additional changes in our 5 year development plans from continued focus on optimizing and maximizing value of our assets. The remaining 20 Bcfe was removed due to risk in well development. 60 Bcfe was removed due to the 5 year rule. Offsetting these negative revisions are positive performance revisions of 46 Bcfe associated with Proved Developed Producing assets and 331 Bcfe related to increase performance in Proved Undeveloped assets.
For the Year
Ended
December 31,
2021
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves4,350,010 
Undeveloped Reserves Transferred to Developed (a)(1,133,110)
Revisions Due to 5 Year Rule (b)(59,948)
Price Revisions(4,939)
Revisions Due to Plan Changes (c)(643,994)
Revisions Due to Changes Related to Well Performance (d)331,135 
Extension and Discoveries (e)880,965 
Ending Proved Undeveloped Reserves(f)3,720,119 
_________
(a)    During 2021, various exploration and development drilling and evaluations were completed. Approximately, $248,232 of capital was spent in the year ended December 31, 2021 related to undeveloped reserves that were transferred to developed.
(b)    Due to the 5 Year Rule, 60 Bcfe of reserves were removed.
(c) The downward revisions for 2021 plan changes is due to the removal of 267 Bcfe of reserves related acreage consolidation initiatives. We also had 356 Bcfe which were removed from our 5 year development plan from our continued focus on optimizing the development timing of our assets. The remaining 20 Bcfe was removed due to risk in well development.
(d)    The upward revisions of 331 Bcfe are due to increased ethane extractions for our undeveloped locations related to increased production performance.
(e)    Extensions and discoveries are due mainly to the addition of 476 Bcfe related to 29 Marcellus wells within our Southwest Pennsylvania, Central Pennsylvania and West Virginia operations and 405 Bcfe of 16 Utica wells within our Central Pennsylvania and Southwest Pennsylvania operations. The Company uses reliable technologies when assigning reserves to undeveloped locations, including wire line open-hole log data, performance data, geological log cross sections, core data and statistical analysis. The statistical methods use production performance of analog wells and include data from operated and competitor wells. We also use geophysical data that includes data from our wells, published documents, state data-sites and data exchanges to confirm continuity of the formation.
(f)    Included in proved undeveloped reserves at December 31, 2021 are approximately 310 MMcfe of reserves that have been reported for more than five years. These reserves are all attributable to acreage within the current operating plan identified by the life-of-mine timing maps for the Buchanan mine. The annual increase in proved undeveloped gob reserves is a result of a change in planned mining activity, which includes an expanded mining footprint, partially offset by the conversion to proved developed gob reserves. These reserves specifically relate to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine that was sold in March 2016 to Coronado IV LLC with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons constitute the specific circumstances that exist to continue recognizing these reserves for CNX.
Schedule of Aging of Capitalized Exploratory Well Costs
The following table indicates the changes to the Company’s suspended exploratory well costs:
For the Years Ended December 31,
202120202019
Balance, Beginning of Period$9,062 $8,984 $8,178 
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves— 28,336 66,409 
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves— (28,258)(65,603)
Capitalized Exploratory Well Costs Charged to Expense(9,062)— — 
Balance, End of Period$— $9,062 $8,984 
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure
The standardized measure is intended to provide a better means for comparing the value of CNX proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
December 31,
202120202019
Future Cash Flows (a)
Revenues
$31,838,532 $16,577,563 $19,489,588 
Production Costs
(8,246,671)(6,071,763)(7,903,120)
Development Costs (b)(1,735,784)(1,957,519)(1,121,073)
Income Tax Expense
(5,838,632)(2,235,205)(2,720,994)
Future Net Cash Flows16,017,445 6,313,076 7,744,401 
Discounted to Present Value at a 10% Annual Rate(10,135,869)(3,677,340)(4,673,932)
Total Standardized Measure of Discounted Net Cash Flows$5,881,576 $2,635,736 $3,070,469 
_________
(a)    For 2021, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2021, adjusted for energy content and a regional price differential. For 2021, this adjusted natural gas price was $3.19 per Mcf, the adjusted oil price was $55.72 per barrel and the adjusted NGL price was $28.44 per barrel. In 2020, as the result of the CNXM take-in transaction (see Note 4 - Acquisitions and Dispositions), there was a change in production costs and development costs. Historically the production costs included contractual CNXM rates but in 2020 this was replaced with actual operating costs of the midstream infrastructure. Additionally, our development costs in 2020 include capital related to connecting undeveloped Shale wells to the midstream gathering systems; in prior years this was captured within the CNXM contractual rate within production costs. These changes resulted in an increase of $932 million to the prior year Standardized Measure of Discounted Net Cash Flows.
For 2020, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2020, adjusted for energy content and a regional price differential. For 2020, this adjusted natural gas price was $1.70 per Mcf, the adjusted oil price was $35.61 per barrel and the adjusted NGL price was $13.18 per barrel.

    For 2019, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2019, adjusted for energy content and a regional price differential. For 2019, this adjusted natural gas price was $2.24 per Mcf, the adjusted oil price was $44.31 per barrel and the adjusted NGL price was $19.10 per barrel.

(b)    Development costs for 2021 include $405,700 of plugging and abandonment costs and $185,074 of Midstream capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,166 and $154,200, respectively.

Development costs for 2020 include $402,174 of plugging and abandonment costs and $286,724 of Midstream capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $18,357 and $231,512, respectively. The increase from 2019 was primarily due to the addition of Midstream capital as a result of the Merger that occurred on September 28, 2020 (See Note 4 - Acquisitions and Dispositions).
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202120202019
Balance at Beginning of Period$2,635,736 $3,070,469 $4,655,457 
Net Changes in Sales Prices and Production Costs5,272,386 (695,216)(2,944,555)
Sales Net of Production Costs(1,220,971)(1,007,676)(824,360)
Net Change Due to Revisions in Quantity Estimates(334,660)322,820 (252,796)
Net Change Due to Extensions, Discoveries and Improved Recovery699,710 268,196 654,027 
Development Costs Incurred During the Period393,641 434,273 739,874 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period(33,175)(129,642)(323,922)
Changes in Estimated Future Development Costs31,406 (499,316)(24,469)
Net Change in Future Income Taxes(1,231,883)138,404 409,797 
Accretion329,782 390,391 583,320 
Timing and Other(660,396)343,033 398,096 
     Total Discounted Cash Flow at End of Period$5,881,576 $2,635,736 $3,070,469 
Note: Table excludes unrealized gain/loss on commodity derivative instruments.