(20) Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following tables set forth supplemental information regarding the Company’s consolidated oil and gas producing activities (in thousands). The amounts shown include the Company’s net working interests in all of its oil and gas properties.

Net proved oil and gas reserves for the years ended December 31, 2019, 2020 and 2021 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (“D&M”) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States.

Proved reserves are the estimated quantities of oil, condensate, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months.

Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital, future commodity prices, net cash provided by operating activities, future drilling and completion costs, and other economic factors.

The tables below set forth the changes in quantities of proved reserves and net quantities of proved developed and proved undeveloped reserves for the periods indicated. This information includes the Company’s royalty and net working interest share of the reserves in oil and gas properties.


			Oil and
	Natural Gas	NGLs	Condensate	Equivalents
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
Proved reserves:
December 31, 2018	11,425	1,052	46	18,011
Revisions	(1,735)	25	(11)	(1,648)
Extensions, discoveries and other additions	2,626	169	11	3,705
Production	(822)	(55)	(4)	(1,175)
December 31, 2019	11,494	1,191	42	18,893
Revisions	(1,280)	65	(8)	(940)
Extensions, discoveries and other additions	799	48	3	1,105
Production	(875)	(68)	(4)	(1,310)
Sales	(113)	—	—	(113)
December 31, 2020 ⁽¹⁾	10,025	1,236	33	17,635
Revisions	993	77	6	1,486
Extensions, discoveries and other additions	349	18	2	472
Production	(826)	(58)	(4)	(1,194)
Sales	(337)	(54)	(1)	(670)
December 31, 2021 ⁽¹⁾	10,204	1,219	36	17,729

(1)

Proved reserves for the noncontrolling interest in Martica as of December 31, 2020 were 254 Bcfe, which consists of 159 Bcf of natural gas, 15 MMBbl of NGLs and 0.5 MMBbl of oil and condensate. Proved reserves for the noncontrolling interest in Martica as of December 31, 2021 were 167 Bcfe, which consists of 101 Bcf of natural gas, 11 MMBbl of NGLs and 0.4 MMBbl of oil and condensate.


			Oil and
	Natural Gas	NGLs	Condensate	Equivalents
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
Proved developed reserves:
December 31, 2019	7,229	731	21	11,740
December 31, 2020 ⁽¹⁾	6,901	810	19	11,873
December 31, 2021 ⁽¹⁾	7,395	876	17	12,753
Proved undeveloped reserves:
December 31, 2019	4,265	460	21	7,153
December 31, 2020 ⁽²⁾	3,124	426	14	5,762
December 31, 2021 ⁽²⁾	2,809	343	19	4,976

(1)

Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2020 were 181 Bcfe, which consists of 110 Bcf of natural gas, 11 MMBbl of NGLs and 0.3 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2021 were 133 Bcfe, which consists of 78 Bcf of natural gas, 9 MMBbl of NGLs and 0.2 MMBbl of oil and condensate.

(2)

Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2020 were 73 Bcfe, which consists of 49 Bcf of natural gas, 4 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2021 were 34 Bcfe, which consists of 23 Bcf of natural gas, 2 MMBbl of NGLs and 0.2 MMBbl of oil and condensate.

Significant changes in proved reserves for the years ended December 31, 2019, 2020 and 2021 include the following:

Year Ended December 31, 2019 Proved Reserve Changes

●

Extensions, discoveries, and other additions of 3,705 Bcfe resulted from delineation and development drilling in the Appalachian Basin.

●

Net downward revisions of 1,648 Bcfe include:

●

Upward revisions of 63 Bcfe related to well performance.

●

Net downward revisions of 1,705 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 595 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, and downward revisions of 2,300 Bcfe for locations that were not developed within five years of initial booking as proved reserves.

●

Downward revisions of 157 Bcfe were due to increases in prices for natural gas, NGLs and oil.

●

Upward revisions of 315 Bcfe are due to an increase in the Company’s assumed future ethane recovery.

●

Downward revisions of 164 Bcfe are due to the deconsolidation of Antero Midstream Partners. Deconsolidation of Antero Midstream Partners resulted in Antero Resources recording the full fees paid to Antero Midstream Partners for services rendered and no longer including future capital expenditures associated with Antero Midstream Partners’ assets in future development costs. Prior to deconsolidation, Antero Resources’ consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream Partners and the inclusion of the operating costs and capital incurred by Antero Midstream Partners.

Year Ended December 31, 2020 Proved Reserve Changes

●

Extensions, discoveries, and other additions of 1,105 Bcfe resulted from delineation and development drilling in the Appalachian Basin.

●

Net downward revisions of 940 Bcfe include:

●

Net downward revision of 1,126 Bcfe due to decreases in prices for natural gas, NGLs and oil.

●

Net downward revision of 922 Bcfe for locations that were not developed within five years of initial booking as proved reserves.

●

Upward revisions of 485 Bcfe are due to an increase in the Company’s assumed future ethane recovery.

●

Net upward revision of 132 Bcfe due to schedule optimization primarily driven by previously proved undeveloped properties reclassified from non-proved to proved undeveloped.

●

Net upward performance revisions of 491 Bcfe.

●

Sales of reserves of 113 Bcfe related to the VPP.

Year Ended December 31, 2021 Proved Reserve Changes

●

Extensions, discoveries, and other additions of 472 Bcfe resulted from delineation and development drilling in the Appalachian Basin.

●

Net upward revisions of 1,486 Bcfe include:

●

Upward revisions of 149 Bcfe due to increases in prices for natural gas, NGLs and oil.

●

Upward revisions of 121 Bcfe are due to an increase in the Company’s assumed future ethane recovery.

●

Net upward performance revisions of 565 Bcfe.

●

Net upward revision of 651 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 1,475 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, and downward revisions of 824 Bcfe for locations that were not developed within five years of initial booking as proved reserves.

●

Sales of reserves of 670 Bcfe related to the drilling partnership.

(e)	Standardized Measure of Discounted Future Net Cash Flow

The standardized measure relating to proved oil and reserves was prepared in accordance with the provisions of ASC 932. Future cash inflows were computed by applying historical 12 month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of available NOL carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

The following table sets forth the Standardized Measure of the discounted future net cash flows attributable to the Company’s proved reserves (in millions):


	Year Ended December 31,
	2019		2020		2021
Future cash inflows	$	54,228		37,845		74,622
Future production costs		(36,524)		(32,202)		(34,665)
Future development costs		(2,772)		(1,685)		(1,704)
Future net cash flows before income tax		14,932		3,958		38,253
Future income tax expense ⁽¹⁾		(1,639)		—		(7,813)
Future net cash flows		13,293		3,958		30,440
10% annual discount for estimated timing of cash flows		(7,824)		(2,748)		(17,007)
Standardized measure of discounted future net cash flows ⁽²⁾	$	5,469		1,210		13,433

(1)

Based on the 12-month average of the first-day-of-the-month prices used in the computation of PV-10 as of December 31, 2020, the future taxable net income generated over the life of the Company’s proved reserves was expected to be less than its NOL carryforward deductions and therefore, under the standardized measure, there was no deduction for federal or state income taxes.

(2)	The standardized measure of discounted future net cash flows for the noncontrolling interest in Martica was $359 million and $501 million for the years ended December 31, 2020 and 2021, respectively.

The Company used the following 12-month weighted average prices to estimate its total equivalent reserves (per Mcfe):


	Year Ended December 31,
	2019		2020		2021
12-month weighted average price	$	2.87		2.15		4.21

(f)	Changes in Standardized Measure of Discounted Future Net Cash Flow

The changes in the Standardized Measure relating to proved oil and natural gas reserves, which were prepared in accordance with the provisions of ASC 932, are as follows (in millions):


	Year Ended December 31,
	2019		2020		2021
Sales of oil and gas, net of productions costs	$	(1,116)		(347)		(2,917)
Net changes in prices and production costs ⁽¹⁾		(6,729)		(5,455)		14,099
Development costs incurred during the period		758		704		454
Net changes in future development costs ⁽²⁾		(92)		249		(117)
Extensions, discoveries and other additions		782		31		504
Divestitures		—		(174)		(125)
Revisions of previous quantity estimates		(1,011)		(379)		2,543
Accretion of discount		1,259		607		121
Net change in income taxes		1,513		598		(3,115)
Changes in timing and other		(373)		(93)		776
Net increase (decrease)		(5,009)		(4,259)		12,223
Beginning of year		10,478		5,469		1,210
End of year ⁽³⁾	$	5,469		1,210		13,433

(1)	Includes $3.3 billion in increased production costs due to the deconsolidation of Antero Midstream Partners for the year ended December 31, 2019.

(2)	Includes $185 million in increased future development costs due to the deconsolidation of Antero Midstream Partners for the year ended December 31, 2019.

(3)	The standardized measure for the noncontrolling interest in Martica was $359 million and $501 million for the years ended December 31, 2020 and 2021, respectively.