XML 73 R54.htm IDEA: XBRL DOCUMENT v3.24.0.1
Supplemental Gas Data (unaudited) (Tables)
 12 Months Ended
Dec. 31, 2023
Extractive Industries [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure
Capitalized Costs:
As of December 31,
20232022
Intangible Drilling Costs$5,902,498 $5,554,021 
Gas Gathering Assets2,631,110 2,542,587 
Proved Gas Properties1,374,685 1,345,114 
Unproved Gas Properties724,401 734,890 
Gas Wells and Related Equipment1,513,945 1,342,719 
Other Gas Assets119,163 99,457 
Total Property, Plant and Equipment12,265,802 11,618,788 
Accumulated Depreciation, Depletion and Amortization(5,110,938)(4,710,684)
Net Capitalized Costs$7,154,864 $6,908,104 
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,
202320222021
Property Acquisitions:
Proved Properties
$2,319 $19,766 $32,355 
Unproved Properties
26,405 14,802 20,568 
Development**637,711 526,092 393,641 
Exploration4,257 6,806 30,927 
Total$670,692 $567,466 $477,491 
__________
(*)    Includes costs incurred whether capitalized or expensed.
(**)    Includes development costs for midstream of $47 million, $38 million and $35 million for 2023, 2022 and 2021, respectively.
Results of Operations for Oil and Gas Producing Activities Disclosure
Results of Operations for Producing Activities:
For the Years Ended December 31,
202320222021
Natural Gas, NGLs and Oil Revenue$1,302,218 $3,652,112 $2,183,929 
Realized Gain (Loss) on Commodity Derivative Instruments 163,026 (1,812,777)(539,016)
Unrealized Gain (Loss) on Commodity Derivative Instruments1,765,626 (850,998)(1,093,717)
Purchased Gas Revenue74,218 185,552 99,713 
Total Revenue3,305,088 1,173,889 650,909 
Lease Operating Expense63,333 66,658 46,256 
Production, Ad Valorem and Other Fees27,946 44,965 34,051 
Transportation, Gathering and Compression381,934 369,660 343,635 
Purchased Gas Costs69,924 185,383 93,776 
Exploration Costs10,447 8,298 20,626 
Depreciation, Depletion and Amortization433,586 461,215 515,118 
Total Costs987,170 1,136,179 1,053,462 
Pre-tax Operating Income (Loss)2,317,918 37,710 (402,553)
Income Tax Expense (Benefit)523,849 12,444 (87,354)
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$1,794,069 $25,266 $(315,199)
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,
202320222021
Production (MMcfe)560,366 580,169 590,248 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$2.32 $6.29 $3.70 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$0.32 $(3.35)$(0.98)
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$2.61 $3.17 $2.79 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.11 $0.11 $0.08 
Schedule of Gas and Oil Acreage
The following table sets forth, at December 31, 2023, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,499 4,425 
Producing Oil Wells - Working Interest2 — 
Producing Gas Wells - Royalty Interest320 — 
Producing Oil Wells - Royalty Interest126 — 
Acreage Position:
   Proved Developed Acreage385,087 385,087 
   Proved Undeveloped Acreage40,811 40,811 
   Unproved Acreage4,704,922 3,392,132 
Total Acreage5,130,820 3,818,030 
____________
(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 oil and gas reserves estimates are as follows:
CondensateConsolidated
Natural GasNGLs& Crude OilOperations
(MMcf)(Mbbls)(Mbbls)(MMcfe)
Balance December 31, 2020 (a)9,034,066 81,867 4,081 9,549,758 
Revisions (b)(409,215)13,655 39 (327,050)
Price Changes82,248 692 22 86,532 
Extensions and Discoveries (e)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 (c)(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 (d)(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 
Proved developed reserves:
December 31, 20215,569,332 53,204 2,843 5,905,611 
December 31, 20225,788,814 70,063 2,038 6,221,422 
December 31, 20235,521,437 83,682 706 6,027,762 
Proved undeveloped reserves:
December 31, 20213,418,475 49,081 1,193 3,720,119 
December 31, 20223,398,464 30,090 1,077 3,585,468 
December 31, 20232,401,555 51,029 875 2,712,980 
__________
(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 2021 are partly due to changes in our five-year development plan that were 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.
(c)    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.
(d)    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.
(e)    Extensions and Discoveries in 2021, 2022, and 2023 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 2023, 2022, and 2021, the Company added 42 Bcfe, 23 Bcfe and 26 Bcfe, respectively, related to exploratory and non-operated wells.

For the Year
Ended
December 31,
2023
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves3,585,468 
Undeveloped Reserves Transferred to Developed (a)(819,365)
Price Revisions(181,837)
Revisions Due to Plan Changes (b)(168,800)
Revisions Due to Changes Related to Well Performance (c)466,730 
Revisions Due to 5 Year Rule(709,561)
Extension and Discoveries (d)540,345 
Ending Proved Undeveloped Reserves(e)2,712,980 
_________
(a)    During 2023, various exploration and development drilling and evaluations were completed. Approximately, $319,475 of capital was spent in the year ended December 31, 2023 related to undeveloped reserves that were transferred to developed.
(b)    The downward revisions for 2023 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 169 Bcfe being removed.
(c)    The upward revisions of 467 Bcfe are from increased production performance related to producing offset locations, leasing activities and performance revisions related to wells that fell out for price, but performance resulted in them being in our 2023 reserves.
(d)    Extensions and discoveries are due mainly to the addition of 336 Bcfe related to 16 Marcellus wells within our Southwest Pennsylvania and Central Pennsylvania operations and 204 Bcfe related to 9 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, 2023 are approximately 290 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.
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,
202320222021
Balance, Beginning of Period$— $— $9,062 
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves— — — 
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves— — — 
Capitalized Exploratory Well Costs Charged to Expense— — (9,062)
Balance, End of Period$— $— $— 
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,
202320222021
Future Cash Flows (a)
Revenues
$20,281,496 $54,713,692 $31,838,532 
Production Costs
(8,515,152)(10,225,451)(8,246,671)
Development Costs (b)(1,903,477)(2,233,706)(1,735,784)
Income Tax Expense
(2,507,151)(10,695,511)(5,838,632)
Future Net Cash Flows7,355,716 31,559,024 16,017,445 
Discounted to Present Value at a 10% Annual Rate(4,245,681)(20,796,325)(10,135,869)
Total Standardized Measure of Discounted Net Cash Flows$3,110,035 $10,762,699 $5,881,576 
_________
(a)    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.
    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.

(b)    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.

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.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202320222021
Balance at Beginning of Period$10,762,699 $5,881,576 $2,635,736 
Net Changes in Sales Prices and Production Costs(10,722,238)6,774,652 5,272,386 
Sales Net of Production Costs(992,030)(1,358,052)(1,220,971)
Net Change Due to Revisions in Quantity Estimates(155,807)(472,831)(334,660)
Net Change Due to Extensions, Discoveries and Improved Recovery32,876 1,853,496 699,710 
Development Costs Incurred During the Period637,711 526,092 393,641 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period(149,770)(167,298)(33,175)
Changes in Estimated Future Development Costs(211,592)(257,458)31,406 
Net Change in Future Income Taxes2,647,842 (1,539,146)(1,231,883)
Accretion1,403,417 766,899 329,782 
Timing and Other(143,073)(1,245,231)(660,396)
     Total Discounted Cash Flow at End of Period$3,110,035 $10,762,699 $5,881,576 
Note: Table excludes unrealized gain/loss on commodity derivative instruments.