Supplemental Gas Data (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

Capitalized Costs:

	As of December 31,
	2018			2017
Intangible drilling costs	$	4,120,283		$	3,849,689
Proved gas properties	1,135,411			1,999,891
Gas gathering assets	1,099,047			1,182,234
Unproved gas properties	927,667			919,733
Gas wells and related equipment	856,973			834,120
Other gas assets	54,395			181,038
Total Property, Plant and Equipment	$	8,193,776		$	8,966,705
Accumulated Depreciation, Depletion and Amortization	(2,475,917		)	(3,408,606		)
Net Capitalized Costs	$	5,717,859		$	5,558,099

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,
	2018		2017		2016
Property acquisitions
Proved properties	$	38,621	$	15,850	$	—
Unproved properties	36,248		32,038		1,537
Development	844,081		544,809		138,813
Exploration	61,604		48,020		32,259
Total	$	980,554	$	640,717	$	172,609

__________

(*)

Includes costs incurred whether capitalized or expensed.

Results of Operations for Oil and Gas Producing Activities Disclosure

Results of Operations for Producing Activities:

	For the Years Ended December 31,
	2018			2017			2016
Natural Gas, NGLs and Oil Revenue	$	1,577,937		$	1,125,224		$	793,248
(Loss) Gain on Commodity Derivative Instruments	(30,212		)	206,930			(141,021		)
Purchased Gas Revenue	65,986			53,795			43,256
Total Revenue	1,613,711			1,385,949			695,483
Lease Operating Expense	95,139			88,932			96,434
Production, Ad Valorem, and Other Fees	32,750			29,267			31,049
Transportation, Gathering and Compression	424,206			382,865			374,350
Purchased Gas Costs	64,817			52,597			42,717
Impairment of Exploration and Production Properties	—			137,865			—
Exploration Costs	12,033			48,074			14,522
Depreciation, Depletion and Amortization	461,149			412,036			419,939
Total Costs	1,090,094			1,151,636			979,011
Pre-tax Operating Income (Loss)	523,617			234,313			(283,528		)
Income Tax Expense (Benefit)	102,629			(348,676		)	(69,929		)
Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	420,988		$	582,989		$	(213,599	)

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,
	2018			2017			2016
Production (MMcfe)	507,104			407,166			394,387
Total average sales price before effects of financial settlements (per Mcfe)	$	3.12		$	2.76		$	2.01
Average effects of financial settlements (per Mcfe)	$	(0.15	)	$	(0.10	)	$	0.62
Total average sales price including effects of financial settlements (per Mcfe)	$	2.97		$	2.66		$	2.63
Average lifting costs, excluding ad valorem and severance taxes (per Mcfe)	$	0.19		$	0.22		$	0.24

Schedule of Gas and Oil Acreage

The following table sets forth, at December 31, 2018, the number of producing wells, developed acreage and undeveloped acreage:

	Gross	Net(1)
Producing Gas Wells (including gob wells)	6,453	4,623
Producing Oil Wells	149	1
Acreage Position:
Proved Developed Acreage	289,602	289,602
Proved Undeveloped Acreage	33,370	33,370
Unproved Acreage	4,940,180	3,960,428
Total Acreage	5,263,152	4,283,400

____________

(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.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

The gas reserves estimates are as follows:

					Condensate		Consolidated
	Natural Gas		NGLs		& Crude Oil		Operations
	(MMcf)		(Mbbls)		(Mbbls)		(MMcfe)
Balance December 31, 2015 (a)	5,060,215		86,212		10,916		5,642,989
Revisions (b)	11,559		(19,078	)	510		(99,849	)
Price Changes	(179,914	)	(1,647	)	(34	)	(190,009	)
Extensions and Discoveries (c)	643,688		10,960		1,783		720,146
Production	(348,753	)	(6,710	)	(896	)	(394,387	)
Purchases of Reserves In-Place (d)	1,352,759		13,177		1,970		1,443,642
Sales of Reserves In-Place (d)	(711,155	)	(22,382	)	(4,240	)	(870,884	)
Balance December 31, 2016 (a)	5,828,399		60,532		10,009		6,251,648
Revisions (e)	(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 (f)	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 (g)	(715,088	)	(17,252	)	(1,100	)	(825,196	)
Balance December 31, 2018 (a)	7,436,338		65,904		8,261		7,881,335
Proved developed resources:
December 31, 2016	3,478,464		30,666,000		3,474,000		3,683,302
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
Proved undeveloped resources:
December 31, 2016	2,349,934		29,866,000		6,536,000		2,568,346
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

__________

(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 net downward revision of 99.8 Bcfe was the result of 255 Bcfe downward revision for wells that were removed from both internal and JV partner development plans, 113 Bcfe downward revision related to economics for producing properties offset by 268 Bcfe of improved analog performance.

(c) Extensions and Discoveries in 2016, 2017, and 2018 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) Purchases and Sales of Reserves In-Place in 2016 is the result of the Company's fourth quarter realignment of the Marcellus Shale properties as part of dissolving our joint venture with Noble Energy.

(e) The downward revisions for 2017 is 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.

(f) 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.

(g) 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.

	For the Year
	Ended
	December 31,
	2018
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves	3,172,547
Undeveloped reserves transferred to developed(a)	(1,037,727	)
Disposition of reserves in place	(27,741	)
Acquisition of reserves in place	321,975
Price Revisions	(2,489	)
Revisions Due to Plan Changes (b)	(151,550	)
Revisions Due to Changes Due to Well Performance (c)	189,954
Extension and discoveries (d)	921,488
Ending proved undeveloped reserves(e)	3,386,457

_________

(a) During 2018, various exploration and development drilling and evaluations were completed. Approximately, $480,003 of capital was spent in the year ended December 31, 2018 related to undeveloped reserves that were transferred to developed.

(b) The downward revisions for 2018 plan changes is due to removal of a portion of our CBM and Marcellus locations from our proved undeveloped reserves.

(c) The upward revisions due to well performance is due to results from Marcellus and Utica Shale production.

(d) Extensions and discoveries are due mainly to the addition of wells or an extension to previously booked PUD's 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, 2018 are approximately 281,696 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 (See Note 5 - Discontinued Operations for more information) 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 represents the capitalized exploratory well cost activity as indicated:

	December 31,
	2018		2017		2016
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$	46,614	$	40,149	$	40,917
Costs expensed due to determination of dry hole or abandonment of project	$	809	$	—	$	—

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,
	2018			2017			2016
Future Cash Flows (a)
Revenues	$	26,610,100		$	19,261,578		$	11,303,409
Production costs	(7,730,451		)	(7,234,303		)	(5,850,941		)
Development costs	(1,600,128		)	(1,710,585		)	(1,550,294		)
Income tax expense	(4,147,075		)	(2,475,981		)	(1,482,826		)
Future Net Cash Flows	13,132,446			7,840,709			2,419,348
Discounted to present value at a 10% annual rate	(8,476,989		)	(4,709,311		)	(1,464,231		)
Total standardized measure of discounted net cash flows	$	4,655,457		$	3,131,398		$	955,117

(a) 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.

For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016, adjusted for energy content and a regional price differential. For 2016, this adjusted natural gas price was $1.73 per Mcf, the adjusted oil price was $25.04 per barrel and the adjusted NGL price was $15.77 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,
	2018			2017			2016
Balance at beginning of period	$	3,131,398		$	955,117		$	1,019,304
Net changes in sales prices and production costs	1,732,229			1,983,475			(172,812		)
Sales net of production costs	(995,630		)	(831,131		)	(150,819		)
Net change due to revisions in quantity estimates	307,030			(145,496		)	(35,502		)
Net change due to extensions, discoveries and improved recovery	534,052			588,574			(54,628		)
Development costs incurred during the period	844,081			544,809			138,813
Difference in previously estimated development costs compared to actual costs incurred during the period	(434,817		)	(129,427		)	(39,821		)
Purchase of Reserves In-Place	209,630			—			238,819
Sales of Reserves In-Place	(434,103		)	(55,277		)	(137,998		)
Changes in estimated future development costs	(49,294		)	(233,017		)	(158,000		)
Net change in future income taxes	(507,410		)	(404,582		)	36,513
Timing and Other	(69,087		)	712,764			125,529
Accretion	387,378			145,589			145,719
Total discounted cash flow at end of period	$	4,655,457		$	3,131,398		$	955,117