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SUPPLEMENTAL GAS DATA (unaudited)
 12 Months Ended
Dec. 31, 2024
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,
20242023
Intangible Drilling Costs$6,171,177 $5,902,498 
Gas Gathering Assets2,660,668 2,631,110 
Proved Gas Properties1,396,631 1,374,685 
Unproved Gas Properties721,692 724,401 
Gas Wells and Related Equipment1,657,272 1,513,945 
Other Gas Assets136,138 119,163 
Total Property, Plant and Equipment12,743,578 12,265,802 
Accumulated Depreciation, Depletion and Amortization(5,561,023)(5,110,938)
Net Capitalized Costs$7,182,555 $7,154,864 
Costs incurred for property acquisition, exploration and development (*):
For the Years Ended December 31,
202420232022
Property Acquisitions:
Proved Properties
$10,362 $2,319 $19,766 
Unproved Properties
15,061 26,405 14,802 
Development**500,402 637,711 526,092 
Exploration4,494 4,257 6,806 
Total$530,319 $670,692 $567,466 
__________
(*)    Includes costs incurred whether capitalized or expensed.
(**)    Includes development costs for midstream of $23,135, $46,814 and $38,418 for the years ended December 31, 2024, 2023 and 2022, respectively.
Results of Operations for Producing Activities:
For the Years Ended December 31,
202420232022
Natural Gas, NGLs and Oil Revenue$1,186,077 $1,302,218 $3,652,112 
Realized Gain (Loss) on Commodity Derivative Instruments 281,195 163,026 (1,812,777)
Unrealized (Loss) Gain on Commodity Derivative Instruments(453,600)1,765,626 (850,998)
Purchased Gas Revenue59,467 74,218 185,552 
Total Revenue1,073,139 3,305,088 1,173,889 
Lease Operating Expense70,646 63,333 66,658 
Production, Ad Valorem and Other Fees27,554 27,946 44,965 
Transportation, Gathering and Compression382,220 381,934 369,660 
Purchased Gas Costs57,248 69,924 185,383 
Exploration Costs8,446 10,447 8,298 
Depreciation, Depletion and Amortization485,754 433,586 461,215 
Total Costs1,031,868 987,170 1,136,179 
Pre-tax Operating Income41,271 2,317,918 37,710 
Income Tax Expense10,235 523,849 12,444 
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$31,036 $1,794,069 $25,266 
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,
202420232022
Production (MMcfe)550,814 560,366 580,169 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$2.15 $2.32 $6.29 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$0.57 $0.32 $(3.35)
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$2.66 $2.61 $3.17 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.13 $0.11 $0.11 
During the years ended December 31, 2024, 2023 and 2022, the Company drilled 25.7, 30.8, and 37.0 net development wells, respectively. There were no net dry development wells in 2024, 2023 or 2022.
There were no net exploratory wells drilled during the years ended December 31, 2024, 2023 or 2022. There were no net dry exploratory wells in 2024, 2023 or 2022.
As of December 31, 2024, there were 4.98 net development wells and no exploratory wells drilled but uncompleted.
CNX is committed to provide 478.8 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, 2024, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,518 4,447 
Producing Oil Wells - Working Interest2 — 
Producing Gas Wells - Royalty Interest350 — 
Producing Oil Wells - Royalty Interest127 — 
Acreage Position:
   Proved Developed Acreage416,500 416,500 
   Proved Undeveloped Acreage27,941 27,941 
   Unproved Acreage4,809,670 3,485,900 
Total Acreage5,254,111 3,930,341 
____________
(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 20 years of experience in the oil and gas industry. The Company’s gas reserves results, which are reported in Note 23 – Supplemental Gas Data for the year ended December 31, 2024 in this 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 21 years of experience in the oil and gas industry.
The oil and gas reserves estimates are as follows:
CondensateConsolidated
Natural GasNGLs& Crude OilOperations
(MMcf)(Mbbls)(Mbbls)(MMcfe)
Balance December 31, 2021 (a)8,987,807 102,285 4,036 9,625,730 
Revisions (b)(339,878)(6,140)(1,768)(387,320)
Price Changes24,795 17 1 24,904 
Extensions and Discoveries (e)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 
Revisions (c)(698,397)41,119 (453)(454,409)
Price Changes(382,311)(12,733)(1,101)(465,314)
Extensions and Discoveries (e)478,026 16,778 589 582,229 
Production(514,668)(7,410)(206)(560,366)
Sales of Reserves In-Place(146,936)(3,196)(363)(168,288)
Balance December 31, 2023 (a)7,922,992 134,711 1,581 8,740,742 
Revisions (d)(634,288)1,921 (356)(624,896)
Price Changes(237,036)(6,707)(569)(280,692)
Extensions and Discoveries (e)1,092,556 30,465 112 1,276,018 
Production(496,922)(8,825)(157)(550,814)
Sales of Reserves In-Place(18,377)(644)(29)(22,415)
Balance December 31, 2024 (a)7,628,925 150,921 582 8,537,943 
Proved developed reserves:
December 31, 20225,788,814 70,063 2,038 6,221,422 
December 31, 20235,521,437 83,682 706 6,027,762 
December 31, 20245,418,858 112,884 582 6,099,654 
Proved undeveloped reserves:
December 31, 20223,398,464 30,090 1,077 3,585,468 
December 31, 20232,401,555 51,029 875 2,712,980 
December 31, 20242,210,067 38,037 — 2,438,289 
__________
(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 2022 are partly due to changes in our five-year development plan that were 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.
(c)    The downward revisions in 2023 are partly due to changes in our five-year development plan that were driven by development optimization initiatives where wells were shifted into the future. These initiatives resulted in 169 Bcfe being removed. Additional downward revisions of 710 Bcfe are due to the wells not being developed within five years of their original booking. The remaining negative revisions of 43 Bcfe are due to plugging and abandoning of wells due to mining and performance. These are partially offset by positive performance revisions of 467 Bcfe for proved undeveloped assets. The 467 Bcfe contains 146 Bcfe of reserves associated with wells that fell out due to price and were uneconomic but are in 2023 due to improved performance.
(d)    The downward revisions in 2024 are partly due to changes in our five-year development plan that were driven by development optimization initiatives where wells were shifted into the future. These initiatives resulted in 189 Bcfe being removed. Additional downward revisions of 284 Bcfe are due to the wells not being developed within five years of their original booking. Additionally, there were negative revisions of 65 Bcfe due to performance and 87 Bcfe due to wells that that were uneconomic.
(e)    Extensions and Discoveries in 2022, 2023, and 2024 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, operated assets and exploratory wells. In 2024, 2023, and 2022, the Company added 252 Bcfe, 42 Bcfe and 23 Bcfe, respectively, related to exploratory and non-operated wells.

For the Year
Ended
December 31,
2024
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves2,712,980 
Undeveloped Reserves Transferred to Developed (a)(555,964)
Price Revisions(226,829)
Revisions Due to Plan Changes (b)(189,167)
Revisions Due to Changes Related to Well Performance (c)(43,030)
Revisions Due to 5 Year Rule(283,938)
Extension and Discoveries (d)1,024,237 
Ending Proved Undeveloped Reserves(e)2,438,289 
_________
(a)    During 2024, various exploration and development drilling and evaluations were completed. Approximately, $224,394 of capital was spent in the year ended December 31, 2024 related to undeveloped reserves that were transferred to developed.
(b)    The downward revisions for 2024 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 189 Bcfe being removed.
(c)    The downward revision of 43 Bcfe are from positive performance revisions of 44 Bcfe and a negative revision of 87 Bcfe due to uneconomic wells, which resulted in them falling out of our 2024 reserves.
(d)    Extensions and discoveries are due mainly to the addition of 522 Bcfe related to 22 Marcellus wells within our Southwest Pennsylvania and Central Pennsylvania operations and 502 Bcfe related to 40 Utica wells within our Central 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, 2024 are approximately 312 Bcfe 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.
During the years ended December 31, 2024, 2023 and 2022, there have been no additions, reclassifications or capitalization of suspended exploratory well costs.
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 FASB 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,
202420232022
Future Cash Flows (a)
Revenues
$17,997,427 $20,281,496 $54,713,692 
Production Costs
(8,034,256)(8,515,152)(10,225,451)
Development Costs (b)(1,743,442)(1,903,477)(2,233,706)
Income Tax Expense
(2,083,504)(2,507,151)(10,695,511)
Future Net Cash Flows6,136,225 7,355,716 31,559,024 
Discounted to Present Value at a 10% Annual Rate(3,297,503)(4,245,681)(20,796,325)
Total Standardized Measure of Discounted Net Cash Flows$2,838,722 $3,110,035 $10,762,699 
_________
(a)    For 2024, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2024, adjusted for energy content and a regional price differential. For 2024, this adjusted natural gas price was $2.00 per Mcf, the adjusted oil/condensate price was $63.13 per barrel and the adjusted NGL price was $17.92 per barrel.

For 2023, the future cash flows were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2023, adjusted for energy content and a regional price differential. For 2023, this adjusted natural gas price was $2.23 per Mcf, the adjusted oil/condensate price was $65.41 per barrel and the adjusted NGL price was $18.54 per barrel.

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.

(b)    Development costs for 2024 include $705,070 of plugging and abandonment costs and $160,868 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $94,169 and $131,711, respectively.

Development costs for 2023 include $534,853 of plugging and abandonment costs and $210,322 of midstream and water capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $48,538 and $172,885, respectively.
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.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202420232022
Balance at Beginning of Period$3,110,035 $10,762,699 $5,881,576 
Net Changes in Sales Prices and Production Costs(506,616)(10,722,238)6,774,652 
Sales Net of Production Costs(986,852)(992,030)(1,358,052)
Net Change Due to Revisions in Quantity Estimates(229,940)(155,807)(472,831)
Net Change Due to Extensions, Discoveries and Improved Recovery197,972 32,876 1,853,496 
Development Costs Incurred During the Period500,402 637,711 526,092 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period(72,232)(149,770)(167,298)
Changes in Estimated Future Development Costs(183,359)(211,592)(257,458)
Net Change in Future Income Taxes102,450 2,647,842 (1,539,146)
Accretion395,680 1,403,417 766,899 
Timing and Other511,182 (143,073)(1,245,231)
     Total Discounted Cash Flow at End of Period$2,838,722 $3,110,035 $10,762,699 
Note: Table excludes unrealized gain/loss on commodity derivative instruments.