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Supplemental Gas Data (unaudited)
 12 Months Ended
Dec. 31, 2020
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 E&P segment in accordance with the successful efforts method of accounting for production activities.
Capitalized Costs:
As of December 31,
20202019
Intangible Drilling Costs$4,965,252 $4,688,497 
Gas Gathering Assets2,510,916 2,463,866 
Proved Gas Properties1,253,094 1,208,046 
Gas Wells and Related Equipment1,120,061 1,042,000 
Unproved Gas Properties725,705 755,590 
Other Gas Assets95,734 73,479 
Total Property, Plant and Equipment10,670,762 10,231,478 
Accumulated Depreciation, Depletion and Amortization(3,852,593)(3,317,442)
Net Capitalized Costs$6,818,169 $6,914,036 

Costs incurred for property acquisition, exploration and development (*):
For the Years Ended December 31,
202020192018
Property Acquisitions:
Proved Properties
$16,622 $36,710 $38,621 
Unproved Properties
8,060 24,760 36,248 
Development**432,438 1,063,945 986,419 
Exploration33,644 79,855 61,604 
Total$490,764 $1,205,270 $1,122,892 
__________
(*)    Includes costs incurred whether capitalized or expensed.
(**)    Includes development costs for midstream of $67 million, $325 million and $142 million for 2020, 2019 and 2018, respectively.

Results of Operations for Producing Activities:
For the Years Ended December 31,
202020192018
Natural Gas, NGLs and Oil Revenue$896,745 $1,364,325 $1,577,937 
Realized Gain (Loss) on Commodity Derivative Instruments 461,217 69,780 (69,720)
Unrealized (Loss) Gain on Commodity Derivative Instruments(288,235)306,325 39,508 
Purchased Gas Revenue105,792 94,027 65,986 
Total Revenue1,175,519 1,834,457 1,613,711 
Lease Operating Expense40,407 65,443 95,139 
Production, Ad Valorem and Other Fees24,196 27,461 32,750 
Transportation, Gathering and Compression285,683 330,539 302,933 
Purchased Gas Costs100,902 90,553 64,817 
Impairment of Exploration and Production Properties61,849 327,400 — 
Impairment of Undeveloped Properties— 119,429 — 
Exploration Costs14,994 44,380 12,033 
Depreciation, Depletion and Amortization501,821 508,463 493,423 
Total Costs1,029,852 1,513,668 1,001,095 
Pre-tax Operating Income145,667 320,789 612,616 
Income Tax Expense42,098 149,167 120,073 
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$103,569 $171,622 $492,543 
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,
202020192018
Production (MMcfe)511,072 539,149 507,104 
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)$1.75 $2.53 $3.11 
Average Effects of Commodity Derivative Financial Settlements (per Mcfe)$0.74 $0.14 $(0.15)
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)
$2.49 $2.66 $2.97 
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)$0.08 $0.12 $0.19 
During the years ended December 31, 2020, 2019 and 2018, the Company drilled 29.0, 75.7, and 83.9 net development wells, respectively. There were no net dry development wells in 2020 and 2018, and 1.0 net dry development well in 2019.
During the years ended December 31, 2020 and 2019, the Company drilled 2.0 and 5.0 net exploratory wells, respectively. During the year ended December 31, 2018, the Company drilled no net exploratory wells. There were no net dry exploratory wells in 2020, 2019 or 2018.
At December 31, 2020, there were 23.0 net development wells and 1.0 exploratory well that are drilled but uncompleted. Additionally, there are 2.0 net exploratory wells that have been completed and are awaiting final tie-in to production.
CNX is committed to provide 492.5 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, 2020, the number of producing wells, developed acreage and undeveloped acreage:
Gross(1)Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest4,712 4,401 
Producing Oil Wells - Working Interest— — 
Producing Gas Wells - Royalty Interest1,810 — 
Producing Oil Wells - Royalty Interest152 — 
Acreage Position:
   Proved Developed Acreage351,537 351,537 
   Proved Undeveloped Acreage43,713 43,713 
   Unproved Acreage4,986,196 3,637,982 
Total Acreage5,381,446 4,033,232 
____________
(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 16 years of experience in the oil and gas industry. The Company's gas reserves results, which are reported in the Supplemental Gas Data for the year ended December 31, 2020 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 13 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, 2017 (a)7,121,758 71,691 4,950 7,581,612 
Revisions (b)313,091 441 865 320,925 
Price Changes28,100 32 4 28,315 
Extensions and Discoveries (c)839,268 16,247 4,010 960,808 
Production(468,228)(6,011)(468)(507,104)
Sales of Reserves In-Place (d)(715,088)(17,252)(1,100)(825,196)
Balance December 31, 2018 (a)7,436,338 65,904 8,261 7,881,335 
Revisions (e)(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 (f)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 
Proved developed reserves:
December 31, 20184,242,579 40,180 1,870 4,494,878 
December 31, 20194,473,534 59,800 1,087 4,838,858 
December 31, 20204,939,283 42,204 1,207 5,199,748 
Proved undeveloped reserves:
December 31, 20183,193,759 25,724 6,391 3,386,457 
December 31, 20193,464,873 16,044 4,278 3,586,809 
December 31, 20204,094,783 39,664 2,874 4,350,010 
__________
(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 upward revision for 2018 of 321 Bcfe is primarily due to a 472 Bcfe upward revision from increased performance through our continued focus on optimization. This is partially offset by a 151 Bcfe downward revision due to plan changes.
(c)    Extensions and Discoveries in 2018, 2019, and 2020 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 2020 and 2019, the Company added 70 Bcfe and 77 Bcfe, respectively, related to exploratory and non-operated wells.
(d)    The sales of reserves in-place is related to the divestiture of our Utica JV assets and substantially all of our conventional properties. Refer to Note 4 - Acquisitions and Dispositions for more information.
(e)    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.
(f)    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.
For the Year
Ended
December 31,
2020
Proved Undeveloped Reserves (MMcfe)
Beginning Proved Undeveloped Reserves3,586,809 
Undeveloped Reserves Transferred to Developed (a)(1,152,598)
Price Revisions(380,200)
Revisions Due to Plan Changes (b)(691,054)
Revisions Due to Changes Due to Well Performance (c)810,727 
Extension and Discoveries (d)2,176,326 
Ending Proved Undeveloped Reserves(e)4,350,010 
_________
(a)    During 2020, various exploration and development drilling and evaluations were completed. Approximately, $257,952 of capital was spent in the year ended December 31, 2020 related to undeveloped reserves that were transferred to developed.
(b) The downward revisions for 2020 plan changes is due to the removal of 88 Bcfe of reserves related to 4 Utica wells and 579 Bcfe of reserves related to 23 Marcellus wells which were removed from our development plan.
(c)    The upward revisions due to a 342 Bcfe increase in reserves of liquids rich Marcellus production which requires processing due to a reduction in the Company's operating costs as a result of the CNXM take-in transaction completed in 2020. The remaining portion is due to production performance.
(d)    Extensions and discoveries are due mainly to the addition of 1,465 Bcfe related to 47 net Marcellus wells within our Southwest Pennsylvania and West Virginia dry gas operations and 711 Bcfe of 23 net 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, 2020 are approximately 320,987 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.
The following table indicates the changes to the Company's suspended exploratory well costs for the three years ended December 31, 2020:
202020192018
Balance, Beginning of Period$8,984 $8,178 $6,388 
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves28,336 66,409 49,213 
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves(28,258)(65,603)(46,614)
Capitalized Exploratory Well Costs Charged to Expense— — (809)
Balance, End of Period$9,062 $8,984 $8,178 
At December 31, 2020 there was one well pending the determination of proved reserves. The $9,062 of exploratory well costs capitalized for more than one year is related to one partially constructed well that the Company is currently evaluating to determine the most economic approach to access the natural gas reserves. The company expects to make a determination in 2021 to either finalize the well or to access the natural gas reserves from an alternative location.
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,
202020192018
Future Cash Flows (a)
Revenues
$16,577,563 $19,489,588 $26,610,100 
Production Costs
(6,071,763)(7,903,120)(7,730,451)
Development Costs (b)(1,957,519)(1,121,073)(1,600,128)
Income Tax Expense
(2,235,205)(2,720,994)(4,147,075)
Future Net Cash Flows6,313,076 7,744,401 13,132,446 
Discounted to Present Value at a 10% Annual Rate(3,677,340)(4,673,932)(8,476,989)
Total Standardized Measure of Discounted Net Cash Flows$2,635,736 $3,070,469 $4,655,457 
_________
(a)    For 2020, the reserves 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. 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 current year Standardized Measure of Discounted Net Cash Flows.
(b)    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 addition of Midstream capital is the result of the Merger that occurred on September 28, 2020 (See Note 4 - Acquisitions and Dispositions).

    For 2019, the reserves 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.

    For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2018, adjusted for energy content and a regional price differential. For 2018, this adjusted natural gas price was $3.28 per Mcf, the adjusted oil price was $51.68 per barrel and the adjusted NGL price was $27.58 per barrel.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
December 31,
202020192018
Balance at Beginning of Period$3,070,469 $4,655,457 $3,131,398 
Net Changes in Sales Prices and Production Costs(819,247)(2,826,725)1,732,229 
Sales Net of Production Costs(719,441)(1,130,685)(995,630)
Net Change Due to Revisions in Quantity Estimates322,820 (252,796)307,030 
Net Change Due to Extensions, Discoveries and Improved Recovery268,196 654,027 534,052 
Development Costs Incurred During the Period434,273 739,874 844,081 
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period
(129,642)(323,922)(434,817)
Purchase of Reserves In-Place— — 209,630 
Sales of Reserves In-Place— — (434,103)
Changes in Estimated Future Development Costs(499,316)(24,469)(49,294)
Net Change in Future Income Taxes138,404 409,797 (507,410)
Timing and Other390,391 586,591 (69,087)
Accretion178,829 583,320 387,378 
     Total Discounted Cash Flow at End of Period$2,635,736 $3,070,469 $4,655,457