XML 57 R31.htm IDEA: XBRL DOCUMENT
v3.22.0.1

Supplemental Gas Data (unaudited) | 12 Months Ended
--- | ---
Dec. 31, 2021
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,
| 2021 |  | 2020
Intangible Drilling Costs | $ | 5,247,800 |  |  | $ | 4,965,252 |
Gas Gathering Assets | 2,483,561 |  |  | 2,510,916 |
Proved Gas Properties | 1,312,706 |  |  | 1,253,094 |
Unproved Gas Properties | 730,400 |  |  | 725,705 |
Gas Wells and Related Equipment | 1,202,731 |  |  | 1,120,061 |
Other Gas Assets | 96,279 |  |  | 95,734 |
Total Property, Plant and Equipment | 11,073,477 |  |  | 10,670,762 |
Accumulated Depreciation, Depletion and Amortization | (4,279,070) |  |  | (3,852,593) |
Net Capitalized Costs | $ | 6,794,407 |  |  | $ | 6,818,169 |
Costs incurred for property acquisition, exploration and development (*):
| For the Years Ended December 31,
| 2021 |  | 2020 |  | 2019
Property Acquisitions: |  |  |  |  |
Proved Properties | $ | 32,355 |  |  | $ | 16,622 |  |  | $ | 36,710 |
Unproved Properties | 20,568 |  |  | 8,060 |  |  | 24,760 |
Development** | 393,641 |  |  | 432,438 |  |  | 1,063,945 |
Exploration | 30,927 |  |  | 33,644 |  |  | 79,855 |
Total | $ | 477,491 |  |  | $ | 490,764 |  |  | $ | 1,205,270 |
__________ (*) Includes costs incurred whether capitalized or expensed. (**) Includes development costs for midstream of $35 million, $67 million and $325 million for 2021, 2020 and 2019, respectively. Results of Operations for Producing Activities:
| For the Years Ended December 31,
| 2021 |  | 2020 |  | 2019
Natural Gas, NGLs and Oil Revenue | $ | 2,183,929 |  |  | $ | 896,745 |  |  | $ | 1,364,325 |
Realized (Loss) Gain on Commodity Derivative Instruments | (539,016) |  |  | 461,217 |  |  | 69,780 |
Unrealized (Loss) Gain on Commodity Derivative Instruments | (1,093,717) |  |  | (288,235) |  |  | 306,325 |
Purchased Gas Revenue | 99,713 |  |  | 105,792 |  |  | 94,027 |
Total Revenue | 650,909 |  |  | 1,175,519 |  |  | 1,834,457 |
Lease Operating Expense | 46,256 |  |  | 40,407 |  |  | 65,443 |
Production, Ad Valorem and Other Fees | 34,051 |  |  | 24,196 |  |  | 27,461 |
Transportation, Gathering and Compression | 343,635 |  |  | 285,683 |  |  | 330,539 |
Purchased Gas Costs | 93,776 |  |  | 100,902 |  |  | 90,553 |
Impairment of Exploration and Production Properties | — |  |  | 61,849 |  |  | 327,400 |
Impairment of Undeveloped Properties | — |  |  | — |  |  | 119,429 |
Exploration Costs | 20,626 |  |  | 14,994 |  |  | 44,380 |
Depreciation, Depletion and Amortization | 515,118 |  |  | 501,821 |  |  | 508,463 |
Total Costs | 1,053,462 |  |  | 1,029,852 |  |  | 1,513,668 |
Pre-tax Operating (Loss) Income | (402,553) |  |  | 145,667 |  |  | 320,789 |
Income Tax (Benefit) Expense | (87,354) |  |  | 42,098 |  |  | 149,167 |
Results of Operations for Producing Activities excluding Corporate and Interest Costs | $ | (315,199) |  |  | $ | 103,569 |  |  | $ | 171,622 |
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,
| 2021 |  | 2020 |  | 2019
Production (MMcfe) | 590,248 |  |  | 511,072 |  |  | 539,149 |
Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe) | $ | 3.70 |  |  | $ | 1.75 |  |  | $ | 2.53 |
Average Effects of Commodity Derivative Financial Settlements (per Mcfe) | $ | (0.98) |  |  | $ | 0.78 |  |  | $ | 0.14 |
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe) | $ | 2.79 |  |  | $ | 2.49 |  |  | $ | 2.66 |
Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe) | $ | 0.08 |  |  | $ | 0.08 |  |  | $ | 0.12 |
During the years ended December 31, 2021, 2020 and 2019, the Company drilled 33.0, 29.0, and 75.7 net development wells, respectively. There were no net dry development wells in 2021 and 2020, and 1.0 net dry development well in 2019. There were no net exploratory wells drilled during the year ended December 31, 2021. There were 2.0 and 5.0 net exploratory wells drilled during the years ended December 31, 2020 and 2019, respectively. There were no net dry exploratory wells in 2021, 2020 or 2019. As of December 31, 2021, there were 13.0 net development wells drilled but uncompleted. Additionally, there were no net exploratory wells that have been completed and are awaiting final tie-in to production. CNX is committed to provide 394.6 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, 2021, the number of producing wells, developed acreage and undeveloped acreage:
| Gross(1) |  | Net(2)
Producing Gas Wells (including Gob Wells) - Working Interest | 4,716 |  |  | 4,432 |
Producing Gas Wells - Royalty Interest | 2,031 |  |  | — |
Producing Oil Wells - Royalty Interest | 150 |  |  | — |
Acreage Position: |  |  |
Proved Developed Acreage | 376,850 |  |  | 376,850 |
Proved Undeveloped Acreage | 41,605 |  |  | 41,605 |
Unproved Acreage | 4,756,680 |  |  | 3,442,159 |
Total Acreage | 5,175,135 |  |  | 3,860,614 |
____________ (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 17 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, 2021 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 14 years of experience in the oil and gas industry. The gas reserves estimates are as follows:
|  |  |  |  |  | Condensate |  | Consolidated
|  | Natural Gas |  | NGLs |  | & Crude Oil |  | Operations
|  | (MMcf) |  | (Mbbls) |  | (Mbbls) |  | (MMcfe)
Balance December 31, 2018 (a) |  | 7,436,338 |  |  | 65,904 |  |  | 8,261 |  |  | 7,881,335 |
Revisions (b) |  | (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 (d) |  | 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 (e) |  | (409,215) |  |  | 13,655 |  |  | 39 |  |  | (327,050) |
Price Changes |  | 82,248 |  |  | 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 |
Proved developed reserves: |  |  |  |  |  |  |  |
December 31, 2019 |  | 4,473,534 |  |  | 59,800 |  |  | 1,087 |  |  | 4,838,858 |
December 31, 2020 |  | 4,939,283 |  |  | 42,204 |  |  | 1,207 |  |  | 5,199,748 |
December 31, 2021 |  | 5,569,332 |  |  | 53,204 |  |  | 2,843 |  |  | 5,905,611 |
Proved undeveloped reserves: |  |  |  |  |  |  |  |
December 31, 2019 |  | 3,464,873 |  |  | 16,044 |  |  | 4,278 |  |  | 3,586,809 |
December 31, 2020 |  | 4,094,783 |  |  | 39,664 |  |  | 2,874 |  |  | 4,350,010 |
December 31, 2021 |  | 3,418,475 |  |  | 49,081 |  |  | 1,193 |  |  | 3,720,119 |
__________ (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 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. (c) Extensions and Discoveries in 2019, 2020, and 2021 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 2021, 2020 and 2019, the Company added 26 Bcfe, 70 Bcfe and 77 Bcfe, respectively, related to exploratory and non-operated wells. (d) 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. (e) 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 5 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 5 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.
|  | For the Year
|  | Ended
|  | December 31,
|  | 2021
Proved Undeveloped Reserves (MMcfe) |  |
Beginning Proved Undeveloped Reserves |  | 4,350,010 |
Undeveloped Reserves Transferred to Developed (a) |  | (1,133,110) |
Revisions Due to 5 Year Rule (b) |  | (59,948) |
Price Revisions |  | (4,939) |
Revisions Due to Plan Changes (c) |  | (643,994) |
Revisions Due to Changes Related to Well Performance (d) |  | 331,135 |
Extension and Discoveries (e) |  | 880,965 |
Ending Proved Undeveloped Reserves(f) |  | 3,720,119 |
_________ (a) During 2021, various exploration and development drilling and evaluations were completed. Approximately, $248,232 of capital was spent in the year ended December 31, 2021 related to undeveloped reserves that were transferred to developed. (b) Due to the 5 Year Rule, 60 Bcfe of reserves were removed. (c) The downward revisions for 2021 plan changes is due to the removal of 267 Bcfe of reserves related acreage consolidation initiatives. We also had 356 Bcfe which were removed from our 5 year development plan from our continued focus on optimizing the development timing of our assets. The remaining 20 Bcfe was removed due to risk in well development. (d) The upward revisions of 331 Bcfe are due to increased ethane extractions for our undeveloped locations related to increased production performance. (e) Extensions and discoveries are due mainly to the addition of 476 Bcfe related to 29 Marcellus wells within our Southwest Pennsylvania, Central Pennsylvania and West Virginia operations and 405 Bcfe of 16 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. (f) Included in proved undeveloped reserves at December 31, 2021 are approximately 310 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 Years Ended December 31,
| 2021 |  | 2020 |  | 2019
Balance, Beginning of Period | $ | 9,062 |  |  | $ | 8,984 |  |  | $ | 8,178 |
Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves | — |  |  | 28,336 |  |  | 66,409 |
Reclassifications to Wells, Facilities and Equipment Based on the Determination of Proved Reserves | — |  |  | (28,258) |  |  | (65,603) |
Capitalized Exploratory Well Costs Charged to Expense | (9,062) |  |  | — |  |  | — |
Balance, End of Period | $ | — |  |  | $ | 9,062 |  |  | $ | 8,984 |
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,
| 2021 |  | 2020 |  | 2019
Future Cash Flows (a) |  |  |  |  |
Revenues | $ | 31,838,532 |  |  | $ | 16,577,563 |  |  | $ | 19,489,588 |
Production Costs | (8,246,671) |  |  | (6,071,763) |  |  | (7,903,120) |
Development Costs (b) | (1,735,784) |  |  | (1,957,519) |  |  | (1,121,073) |
Income Tax Expense | (5,838,632) |  |  | (2,235,205) |  |  | (2,720,994) |
Future Net Cash Flows | 16,017,445 |  |  | 6,313,076 |  |  | 7,744,401 |
Discounted to Present Value at a 10% Annual Rate | (10,135,869) |  |  | (3,677,340) |  |  | (4,673,932) |
Total Standardized Measure of Discounted Net Cash Flows | $ | 5,881,576 |  |  | $ | 2,635,736 |  |  | $ | 3,070,469 |
_________ (a) 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 price was $55.72 per barrel and the adjusted NGL price was $28.44 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. 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 price was $35.61 per barrel and the adjusted NGL price was $13.18 per barrel. For 2019, the future cash flows 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. (b) Development costs for 2021 include $405,700 of plugging and abandonment costs and $185,074 of Midstream capital on an undiscounted pre-tax basis. On a PV-10 pre-tax discounted basis, these amounts equate to $7,166 and $154,200, respectively. 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 increase from 2019 was primarily due to the addition of Midstream capital as a result of the Merger that occurred on September 28, 2020 (See Note 4 - Acquisitions and Dispositions). The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
| December 31,
| 2021 |  | 2020 |  | 2019
Balance at Beginning of Period | $ | 2,635,736 |  |  | $ | 3,070,469 |  |  | $ | 4,655,457 |
Net Changes in Sales Prices and Production Costs | 5,272,386 |  |  | (695,216) |  |  | (2,944,555) |
Sales Net of Production Costs | (1,220,971) |  |  | (1,007,676) |  |  | (824,360) |
Net Change Due to Revisions in Quantity Estimates | (334,660) |  |  | 322,820 |  |  | (252,796) |
Net Change Due to Extensions, Discoveries and Improved Recovery | 699,710 |  |  | 268,196 |  |  | 654,027 |
Development Costs Incurred During the Period | 393,641 |  |  | 434,273 |  |  | 739,874 |
Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period | (33,175) |  |  | (129,642) |  |  | (323,922) |
Changes in Estimated Future Development Costs | 31,406 |  |  | (499,316) |  |  | (24,469) |
Net Change in Future Income Taxes | (1,231,883) |  |  | 138,404 |  |  | 409,797 |
Accretion | 329,782 |  |  | 390,391 |  |  | 583,320 |
Timing and Other | (660,396) |  |  | 343,033 |  |  | 398,096 |
Total Discounted Cash Flow at End of Period | $ | 5,881,576 |  |  | $ | 2,635,736 |  |  | $ | 3,070,469 |
Note: Table excludes unrealized gain/loss on commodity derivative instruments.

X
- References No definition available. + Details
Name: | srt_ExtractiveIndustriesAbstract
Namespace Prefix: | srt_
Data Type: | xbrli:stringItemType
Balance Type: | na
Period Type: | duration

X
- Definition The entire disclosure for oil and gas producing industries. + References Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef -Publisher FASB -Name Accounting Standards Codification -Topic 932 -URI http://asc.fasb.org/topic&trid=2145477 + Details
Name: | us-gaap_OilAndGasExplorationAndProductionIndustriesDisclosuresTextBlock
Namespace Prefix: | us-gaap_
Data Type: | dtr-types:textBlockItemType
Balance Type: | na
Period Type: | duration