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Supplemental Gas Data (unaudited) (Tables)
 12 Months Ended
Dec. 31, 2022
Extractive Industries [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure
Capitalized Costs:
As of December 31,
20222021
Intangible Drilling Costs$5,554,021 $5,247,800 
Gas Gathering Assets2,542,587 2,483,561 
Proved Gas Properties1,345,114 1,312,706 
Unproved Gas Properties734,890 730,400 
Gas Wells and Related Equipment1,342,719 1,202,731 
Other Gas Assets99,457 96,279 
Total Property, Plant and Equipment11,618,788 11,073,477 
Accumulated Depreciation, Depletion and Amortization(4,710,684)(4,279,070)
Net Capitalized Costs$6,908,104 $6,794,407 
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,
202220212020
Property Acquisitions:
Proved Properties
$19,766 $32,355 $16,622 
Unproved Properties
14,802 20,568 8,060 
Development**526,092 393,641 432,438 
Exploration6,806 30,927 33,644 
Total$567,466 $477,491 $490,764 
__________
(*)    Includes costs incurred whether capitalized or expensed.
(**)    Includes development costs for midstream of $38 million, $35 million and $67 million for 2022, 2021 and 2020, respectively.
Results of Operations for Oil and Gas Producing Activities Disclosure
Results of Operations for Producing Activities:
For the Years Ended December 31,
202220212020
Natural Gas, NGLs and Oil Revenue$3,652,112 $2,183,929 $896,745 
Realized (Loss) Gain on Commodity Derivative Instruments (1,812,777)(539,016)461,217 
Unrealized Loss on Commodity Derivative Instruments(850,998)(1,093,717)(288,235)
Purchased Gas Revenue185,552 99,713 105,792 
Total Revenue1,173,889 650,909 1,175,519 
Lease Operating Expense66,658 46,256 40,407 
Production, Ad Valorem and Other Fees44,965 34,051 24,196 
Transportation, Gathering and Compression369,660 343,635 285,683 
Purchased Gas Costs185,383 93,776 100,902 
Impairment of Exploration and Production Properties— — 61,849 
Exploration Costs8,298 20,626 14,994 
Depreciation, Depletion and Amortization461,215 515,118 501,821 
Total Costs1,136,179 1,053,462 1,029,852 
Pre-tax Operating Income (Loss)37,710 (402,553)145,667 
Income Tax Expense (Benefit)12,444 (87,354)42,098 
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$25,266 $(315,199)$103,569 
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,
202220212020
Production (MMcfe)580,169 590,248 511,072 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$6.29 $3.70 $1.75 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$(3.35)$(0.98)$0.78 
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$3.17 $2.79 $2.49 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.11 $0.08 $0.08 
Schedule of Gas and Oil Acreage
The following table sets forth, at December 31, 2022, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,553 4,420 
Producing Oil Wells - Working Interest2 — 
Producing Gas Wells - Royalty Interest2,325 — 
Producing Oil Wells - Royalty Interest157 — 
Acreage Position:
   Proved Developed Acreage381,873 381,873 
   Proved Undeveloped Acreage40,894 40,894 
   Unproved Acreage4,791,506 3,456,575 
Total Acreage5,214,273 3,879,342 
____________
(1)    All of our acreage identified as proved developed and undeveloped is controlled fully by CNX through ownership of a 100% working interest.
(2)    Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
Schedule of Aging of Capitalized Exploratory Well Costs
The following table indicates the changes to the Company’s suspended exploratory well costs:
For the Years Ended December 31,
202220212020
Balance, Beginning of Period$— $9,062 $8,984 
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves— — 28,336 
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves— — (28,258)
Capitalized Exploratory Well Costs Charged to Expense— (9,062)— 
Balance, End of Period$— $— $9,062 
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,
202220212020
Future Cash Flows (a)
Revenues
$54,713,692 $31,838,532 $16,577,563 
Production Costs
(10,225,451)(8,246,671)(6,071,763)
Development Costs (b)(2,233,706)(1,735,784)(1,957,519)
Income Tax Expense
(10,695,511)(5,838,632)(2,235,205)
Future Net Cash Flows31,559,024 16,017,445 6,313,076 
Discounted to Present Value at a 10% Annual Rate(20,796,325)(10,135,869)(3,677,340)
Total Standardized Measure of Discounted Net Cash Flows$10,762,699 $5,881,576 $2,635,736 
_________
(a)    For 2022, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2022, adjusted for energy content and a regional price differential. For 2022, this adjusted natural gas price was $5.48 per Mcf, the adjusted oil/condensate price was $85.71 per barrel and the adjusted NGL price was $41.05 per barrel.

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/condensate price was $55.72 per barrel and the adjusted NGL price was $28.44 per barrel.
    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/condensate price was $35.61 per barrel and the adjusted NGL price was $13.18 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.

(b)    Development costs for 2022 include $441,980 of plugging and abandonment costs and $292,937 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,861 and $241,782, respectively.

Development costs for 2021 include $405,700 of plugging and abandonment costs and $234,761 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,166 and $197,980, respectively.

Development costs for 2020 include $402,174 of plugging and abandonment costs and $286,724 of midstream and water 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 following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202220212020
Balance at Beginning of Period$5,881,576 $2,635,736 $3,070,469 
Net Changes in Sales Prices and Production Costs6,774,652 5,272,386 (695,216)
Sales Net of Production Costs(1,358,052)(1,220,971)(1,007,676)
Net Change Due to Revisions in Quantity Estimates(472,831)(334,660)322,820 
Net Change Due to Extensions, Discoveries and Improved Recovery1,853,496 699,710 268,196 
Development Costs Incurred During the Period526,092 393,641 434,273 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period(167,298)(33,175)(129,642)
Changes in Estimated Future Development Costs(257,458)31,406 (499,316)
Net Change in Future Income Taxes(1,539,146)(1,231,883)138,404 
Accretion766,899 329,782 390,391 
Timing and Other(1,245,231)(660,396)343,033 
     Total Discounted Cash Flow at End of Period$10,762,699 $5,881,576 $2,635,736 
Note: Table excludes unrealized gain/loss on commodity derivative instruments.