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Supplemental Gas Data (unaudited)
 12 Months Ended
Dec. 31, 2019
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,
 
2019
 
2018
Intangible Drilling Costs
$
4,688,497

 
$
4,120,283

Proved Gas Properties
1,208,046

 
1,135,411

Gas Gathering Assets
1,110,977

 
1,099,047

Unproved Gas Properties
755,590

 
927,667

Gas Wells and Related Equipment
1,042,000

 
856,973

Other Gas Assets
73,479

 
54,395

Total Property, Plant and Equipment
$
8,878,589

 
$
8,193,776

Accumulated Depreciation, Depletion and Amortization
(3,263,221
)
 
(2,475,917
)
Net Capitalized Costs
$
5,615,368

 
$
5,717,859



Costs incurred for property acquisition, exploration and development (*):
 
For the Years Ended December 31,
 
2019
 
2018
 
2017
Property Acquisitions:
 
 
 
 
 
Proved Properties
$
36,710

 
$
38,621

 
$
15,850

Unproved Properties
24,760

 
36,248

 
32,038

Development
739,874

 
844,081

 
544,809

Exploration
79,855

 
61,604

 
48,020

Total
$
881,199

 
$
980,554

 
$
640,717

__________
(*)
Includes costs incurred whether capitalized or expensed.




Results of Operations for Producing Activities:
 
For the Years Ended December 31,
 
2019
 
2018
 
2017
Natural Gas, NGLs and Oil Revenue
$
1,364,325

 
$
1,577,937

 
$
1,125,224

Gain (Loss) on Commodity Derivative Instruments
376,105

 
(30,212
)
 
206,930

Purchased Gas Revenue
94,027

 
65,986

 
53,795

Total Revenue
1,834,457

 
1,613,711

 
1,385,949

Lease Operating Expense
65,443

 
95,139

 
88,932

Production, Ad Valorem, and Other Fees
27,461

 
32,750

 
29,267

Transportation, Gathering and Compression
516,879

 
424,206

 
382,865

Purchased Gas Costs
90,553

 
64,817

 
52,597

Impairment of Exploration and Production Properties
327,400

 
—

 
137,865

Impairment of Undeveloped Properties
119,429

 
—

 
—

Exploration Costs
44,380

 
12,033

 
48,074

Depreciation, Depletion and Amortization
474,352

 
461,149

 
412,036

Total Costs
1,665,897

 
1,090,094

 
1,151,636

Pre-tax Operating Income
168,560

 
523,617

 
234,313

Income Tax Expense (Benefit)
78,398

 
102,629

 
(348,676
)
Results of Operations for Producing Activities excluding Corporate and Interest Costs
$
90,162

 
$
420,988

 
$
582,989


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,
 
2019
 
2018
 
2017
Production (MMcfe)
539,149

 
507,104

 
407,166

Total Average Sales Price Before Effects of Commodity Derivative Financial Settlements (per Mcfe)
$
2.53

 
$
3.11

 
$
2.76

Average Effects of Commodity Derivative Financial Settlements (per Mcfe)
$
0.14

 
$
(0.15
)
 
$
(0.11
)
Total Average Sales Price Including Effects of Commodity Derivative Financial Settlements (per Mcfe)

$
2.66

 
$
2.97

 
$
2.66

Average Lifting Costs, Excluding Ad Valorem and Severance Taxes (per Mcfe)
$
0.12

 
$
0.19

 
$
0.22


During the years ended December 31, 2019, 2018 and 2017, the Company drilled 75.7, 83.9, and 90.0 net development wells, respectively. There was 1.0 net dry development well in 2019, and no net dry development wells in 2018 or 2017.
During the years ended December 31, 2019 and 2017, the Company drilled 5.0 and 4.0 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 2019, 2018 or 2017.
At December 31, 2019, there were 35.0 net development wells and 1.0 exploratory well that are drilled but uncompleted. Additionally, there are 7.0 net developmental wells that have been completed and are awaiting final tie-in to production.
CNX is committed to provide 532.3 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, 2019, the number of producing wells, developed acreage and undeveloped acreage:
 
 
Gross
 
Net(1)
Producing Gas Wells (including Gob Wells)
 
6,512

 
4,510

Producing Oil Wells
 
151

 
—

Acreage Position:
 
 
 
 
   Proved Developed Acreage
 
337,700

 
337,700

   Proved Undeveloped Acreage
 
28,916

 
28,916

   Unproved Acreage
 
5,192,777

 
3,868,533

Total Acreage
 
5,559,393

 
4,235,149

____________
(1)
Net acres include acreage attributable to the Company's working interests of the properties. Additional adjustments (either increases or decreases) may be required as the Company further develops title to and further confirms its rights with respect to its various properties in anticipation of development. The Company believes that its 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. The input data verification includes reviews of the price and operating, and development cost assumptions 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 15 years of experience in the oil and gas industry. The Company's gas reserves results, which are reported in the Supplemental Gas Data year ended December 31, 2019 Form 10-K, were audited by 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 12 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, 2016 (a)
 
5,828,399

 
60,532

 
10,009

 
6,251,648

Revisions (b)
 
(202,735
)
 
1,162

 
(5,834
)
 
(232,321
)
Price Changes
 
173,738

 
1,188

 
(159
)
 
181,470

Extensions and Discoveries (c)
 
1,769,029

 
17,887

 
1,800

 
1,887,153

Production
 
(364,893
)
 
(6,456
)
 
(589
)
 
(407,166
)
Sales of Reserves In-Place
 
(81,780
)
 
(2,622
)
 
(277
)
 
(99,172
)
Balance December 31, 2017 (a)
 
7,121,758

 
71,691

 
4,950

 
7,581,612

Revisions (d)
 
313,091

 
441

 
865

 
320,925

Price Changes
 
28,100

 
32

 
4

 
28,315

Extensions and Discoveries (c)
 
839,268

 
16,247

 
4,010

 
960,808

Production
 
(468,228
)
 
(6,011
)
 
(468
)
 
(507,104
)
Purchases of Reserves In-Place
 
317,437

 
756

 
—

 
321,975

Sales of Reserves In-Place (e)
 
(715,088
)
 
(17,252
)
 
(1,100
)
 
(825,196
)
Balance December 31, 2018 (a)
 
7,436,338

 
65,904

 
8,261

 
7,881,335

Revisions (f)
 
(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

 
 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
 
December 31, 2017
 
4,051,526

 
56,022,000

 
3,567,000

 
4,409,065

December 31, 2018
 
4,242,579

 
40,180,000

 
1,870,000

 
4,494,878

December 31, 2019
 
4,473,534

 
59,800,000

 
1,087,000

 
4,838,858

 
 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 
 
 
 
 
 
 
 
December 31, 2017
 
3,070,232

 
15,669,000

 
1,383,000

 
3,172,547

December 31, 2018
 
3,193,759

 
25,724,000

 
6,391,000

 
3,386,457

December 31, 2019
 
3,464,873

 
16,044,000

 
4,278,000

 
3,586,809

__________
(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 for 2017 are due to corporate planning changes by our JV partner in Ohio Utica which resulted in all PUD's being removed, causing a 458 Bcfe downward revision, offset, in part, by improved well performance due to the enhanced RCS completions and improved operating costs.
(c)
Extensions and Discoveries in 2017, 2018, and 2019 are due to the addition of wells on the Company's Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.
(d)
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.
(e)
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 6 - Acquisitions and Dispositions for more information.
(f)
The downward revisions in 2019 are primarily due to removal of 872 Bcfe in reserves from plan changes which are the result of our continued focus on optimization and high grading initiatives. 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 and optimization which increased reserves by 657 Bcfe.
 
 
For the Year
 
 
Ended
 
 
December 31,
 
 
2019
Proved Undeveloped Reserves (MMcfe)
 
 
Beginning Proved Undeveloped Reserves
 
3,386,457

Undeveloped Reserves Transferred to Developed (a)
 
(752,970
)
Revisions Due to 5 Year Rule
 
(303,787
)
Price Revisions
 
2,147

Revisions Due to Plan Changes (b)
 
(872,495
)
Revisions Due to Changes Due to Well Performance (c)
 
556,881

Extension and Discoveries (d)
 
1,570,576

Ending Proved Undeveloped Reserves(e)
 
3,586,809

_________
(a)
During 2019, various exploration and development drilling and evaluations were completed. Approximately, $334,062 of capital was spent in the year ended December 31, 2019 related to undeveloped reserves that were transferred to developed.
(b) The downward revisions for 2019 plan changes is due to removal of a portion of our Marcellus and Utica locations from our proved undeveloped reserves.
(c)
The upward revisions due to well performance is due to results from Marcellus Shale production.
(d)
Extensions and discoveries are due mainly to the addition of wells on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology.
(e)
Included in proved undeveloped reserves at December 31,2019 are approximately 248,570 MMcfe of reserves that have been reported for more than five years. 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.
At December 31, 2019 there was one well pending the determination of proved reserves.
The following table represents the capitalized exploratory well cost activity as indicated:
 
December 31,
 
2019
 
2018
 
2017
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
$
59,981

 
$
46,614

 
$
40,149

Costs expensed due to determination of dry hole or abandonment of project
$
—

 
$
809

 
$
—


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,
 
 
2019
 
2018
 
2017
Future Cash Flows (a)
 
 
 
 
 
 
Revenues
 
$
19,489,588

 
$
26,610,100

 
$
19,261,578

Production Costs
 
(7,903,120
)
 
(7,730,451
)
 
(7,234,303
)
Development Costs
 
(1,121,073
)
 
(1,600,128
)
 
(1,710,585
)
Income Tax Expense
 
(2,720,994
)
 
(4,147,075
)
 
(2,475,981
)
Future Net Cash Flows
 
7,744,401

 
13,132,446

 
7,840,709

Discounted to Present Value at a 10% Annual Rate
 
(4,673,932
)
 
(8,476,989
)
 
(4,709,311
)
Total Standardized Measure of Discounted Net Cash Flows
 
$
3,070,469

 
$
4,655,457

 
$
3,131,398


(a)
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.

For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017, adjusted for energy content and a regional price differential. For 2017, this adjusted natural gas price was $2.44 per Mcf, the adjusted oil price was $38.65 per barrel and the adjusted NGL price was $23.61 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,
 
2019
 
2018
 
2017
Balance at Beginning of Period
$
4,655,457

 
$
3,131,398

 
$
955,117

Net Changes in Sales Prices and Production Costs
(2,826,725
)
 
1,732,229

 
1,983,475

Sales Net of Production Costs
(1,130,685
)
 
(995,630
)
 
(831,131
)
Net Change Due to Revisions in Quantity Estimates
(252,796
)
 
307,030

 
(145,496
)
Net Change Due to Extensions, Discoveries and Improved Recovery
654,027

 
534,052

 
588,574

Development Costs Incurred During the Period
739,874

 
844,081

 
544,809

Difference in Previously Estimated Development Costs Compared to Actual Costs Incurred During the Period
(323,922
)
 
(434,817
)
 
(129,427
)
Purchase of Reserves In-Place
—

 
209,630

 
—

Sales of Reserves In-Place
—

 
(434,103
)
 
(55,277
)
Changes in Estimated Future Development Costs
(24,469
)
 
(49,294
)
 
(233,017
)
Net Change in Future Income Taxes
409,797

 
(507,410
)
 
(404,582
)
Timing and Other
586,591

 
(69,087
)
 
712,764

Accretion
583,320

 
387,378

 
145,589

     Total Discounted Cash Flow at End of Period
$
3,070,469

 
$
4,655,457

 
$
3,131,398