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Supplemental Gas Data (unaudited)
 12 Months Ended
Dec. 31, 2022
Extractive Industries [Abstract]  
Supplemental Gas Data (unaudited) SUPPLEMENTAL GAS DATA (unaudited):
The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” The supplementary information summarized below presents the results of natural gas and oil activities for the Company in accordance with the successful efforts method of accounting for production activities.

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 

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 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 
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 
During the years ended December 31, 2022, 2021 and 2020, the Company drilled 37.0, 33.0, and 29.0 net development wells, respectively. There were no net dry development wells in 2022, 2021 or 2020.
There were no net exploratory wells drilled during the years ended December 31, 2022 and 2021. There were 2.0 net exploratory wells drilled during the year ended December 31, 2020. There were no net dry exploratory wells in 2022, 2021 or 2020.
As of December 31, 2022, there were 13.0 net development wells and no exploratory wells drilled but uncompleted.
CNX is committed to provide 403.2 Bcf of gas under existing sales contracts or agreements over the course of the next four years. The Company expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.
Most of the Company’s development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied.
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.

Proved Oil and Gas Reserves Quantities:

Annually, the preparation of natural gas reserves estimates is completed in accordance with CNX prescribed internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as multi-functional management review. As part of the annual review, management reviews and approves changes in the future development plan and the impact to proved-undeveloped locations to ensure that annual changes are aligned with the overall strategic business plan of the Company. A detailed review is completed to ensure that all proved undeveloped locations will be fully developed within five-years of the reserves booking. As part of the development plan review, management reviews current well production data, acreage position, downstream infrastructure availability, operational leases and other commitments, financial capacity to complete the development and individual project economics in expected future gas pricing scenarios. The input data verification includes reviews of the price and operating, and development cost assumptions as well as tax rates by jurisdiction used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a registered professional engineer in the state of West Virginia with over 18 years of experience in the oil and gas industry. The Company’s gas reserves results, which are reported in Note 22 – Supplemental Gas Data for the year ended December 31, 2022 Form 10-K, were audited by independent petroleum engineers, Netherland, Sewell & Associates, Inc. The technical person primarily responsible for overseeing the audit of the Company's reserves is a registered professional engineer in the state of Texas with over 15 years of experience in the oil and gas industry.
The gas reserves estimates are as follows:
CondensateConsolidated
Natural GasNGLs& Crude OilOperations
(MMcf)(Mbbls)(Mbbls)(MMcfe)
Balance December 31, 2019 (a)7,938,406 75,844 5,366 8,425,667 
Revisions (b)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 (d)(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 
Revisions (e)(339,878)(6,140)(1,768)(387,320)
Price Changes24,795 17 1 24,904 
Extensions and Discoveries (c)1,055,250 10,324 1,092 1,123,745 
Production(540,696)(6,333)(246)(580,169)
Balance December 31, 2022 (a)9,187,278 100,153 3,115 9,806,890 
Proved developed reserves:
December 31, 20204,939,283 42,204 1,207 5,199,748 
December 31, 20215,569,332 53,204 2,843 5,905,611 
December 31, 20225,788,814 70,063 2,038 6,221,422 
Proved undeveloped reserves:
December 31, 20204,094,783 39,664 2,874 4,350,010 
December 31, 20213,418,475 49,081 1,193 3,720,119 
December 31, 20223,398,464 30,090 1,077 3,585,468 
__________
(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)    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.
(c)    Extensions and Discoveries in 2020, 2021, and 2022 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-sites 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 2022, 2021, and 2020, the Company added 23 Bcfe, 26 Bcfe and 70 Bcfe, respectively, related to exploratory and non-operated wells.
(d)    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 five-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 five-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.
(e)    The downward revisions in 2022 are partly due to changes in our five-year development plan that are driven by our continued focus on optimizing the development timing of our assets. These initiatives resulted in 298 Bcfe being removed. Additional downward revisions of 66 Bcfe are primarily the result of the plugging of a Shale well. Additionally there was a 24 Bcfe reduction as a result of net performance revisions.
For the Year
Ended
December 31,
2022
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves3,720,119 
Undeveloped Reserves Transferred to Developed (a)(902,105)
Price Revisions(3,012)
Revisions Due to Plan Changes (b)(363,644)
Revisions Due to Changes Related to Well Performance (c)33,082 
Extension and Discoveries (d)1,101,028 
Ending Proved Undeveloped Reserves(e)3,585,468 
_________
(a)    During 2022, various exploration and development drilling and evaluations were completed. Approximately, $281,727 of capital was spent in the year ended December 31, 2022 related to undeveloped reserves that were transferred to developed.
(b)    The downward revisions for 2022 plan changes are due to changes in our five-year development plan that are driven by our continued focus on optimizing the development timing of our assets. These initiatives resulted in 298 Bcfe being removed. Additional downward revisions of 66 Bcfe are primarily the result of the plugging of a Shale well.
(c)    The upward revisions of 33 Bcfe are from increased production performance related to producing offset locations.
(d)    Extensions and discoveries are due mainly to the addition of 724 Bcfe related to 46 Marcellus wells within our Southwest Pennsylvania, Central Pennsylvania and West Virginia operations and 377 Bcfe of 14 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.
(e)    Included in proved undeveloped reserves at December 31, 2022 are approximately 290 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. 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.
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 
At December 31, 2020 there was one well pending the determination of proved reserves. During the year-ended December 31, 2021, the Company determined it would be more economical to access the underlying reserves from a different location and the costs associated with this well were recorded to Exploration and Production Related Other Costs in the Consolidated Statements of Income.
CNX proved natural gas reserves are located in the United States.
Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.
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.